ENBRIDGE INC - Quarter Report: 2021 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM			10-Q


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

For the quarterly period ended September 30, 2021


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

For the transition period from to

Commission file number 1-10934



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


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

200, 425 - 1st Street S.W.

Calgary, Alberta, Canada T2P 3L8

(Address of Principal Executive Offices) (Zip Code)

(403) 231-3900

(Registrant’s Telephone Number, Including Area Code)

_______________________________

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Shares

ENB

New York Stock Exchange

6.375% Fixed-to-Floating Rate Subordinated Notes Series 2018-B due 2078

ENBA

New York Stock Exchange

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

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

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

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

Large accelerated filer

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

The registrant had 2,025,962,505 common shares outstanding as at October 29, 2021.


		Page
	PART I
Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 4.	Controls and Procedures	63
	PART II
Item 1.	Legal Proceedings	65
Item 1A.	Risk Factors	65
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	65
Item 3.	Defaults Upon Senior Securities	65
Item 4.	Mine Safety Disclosures	65
Item 5.	Other Information	66
Item 6.	Exhibits	66
	Signatures	67

GLOSSARY



AOCI			Accumulated other comprehensive loss
Army Corps			United States Army Corps of Engineers
ASC			Accounting Standards Codification
ASU			Accounting Standards Update




CPP Investments			Canada Pension Plan Investment Board
DAPL			Dakota Access Pipeline
DCP Midstream			DCP Midstream, LLC
EBITDA			Earnings before interest, income taxes and depreciation and amortization

EEP			Enbridge Energy Partners, L.P.


EIS			Environmental Impact Statement
EMF			Éolien Maritime France SAS
Enbridge			Enbridge Inc.
Enbridge Gas			Enbridge Gas Inc.


Exchange Act			United States Securities Exchange Act of 1934, as amended







FERC			Federal Energy Regulatory Commission


MTN			Medium-term notes
MW			Megawatts
NGL			Natural gas liquids
Noverco			Noverco Inc.
OCI			Other comprehensive income/(loss)

OEB			Ontario Energy Board
OPEB			Other postretirement benefits
PADD II			Petroleum Administration for Defense District - Midwest District
PennEast			PennEast Pipeline Company, L.L.C.
SEP			Spectra Energy Partners, LP
SESH			Southeast Supply Header, L.L.C.
Steckman			Steckman Ridge, LP
Texas Eastern			Texas Eastern Transmission, LP





the Partnerships			Spectra Energy Partners, LP (SEP) and Enbridge Energy Partners, L.P. (EEP)


the State			State of Michigan
the Straits			Straits of Mackinac
US			United States of America
US$			Unites States dollars

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 our and our subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: our corporate vision and strategy, including strategic priorities and enablers; the COVID-19 pandemic and the duration and impact thereof; energy intensity and emissions reduction targets and related environmental, social and governance matters; diversity and inclusion goals; 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; anticipated utilization of our existing assets; expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected future cash flows and distributable cash flow; dividend growth and 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 related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction and for maintenance; expected capital expenditures, investment capacity and capital allocation priorities; expected equity funding requirements for our commercially secured growth program; expected future growth and expansion opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions and the timing thereof; expected benefits of transactions, including the realization of efficiencies, synergies and cost savings; expected future actions of regulators and courts; toll and rate cases discussions and filings, including Mainline System contracting; anticipated competition; and Line 5 dual pipelines and related litigation and other matters.

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, NGL and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; 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 transactions; governmental legislation; litigation; estimated future dividends and impact of our dividend policy on our future cash flows; our credit ratings; capital project funding; hedging program; expected EBITDA; expected earnings/(loss); expected future cash flows; and 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 expected EBITDA, expected

earnings/(loss), expected future cash flows, expected distributable cash flow or estimated future dividends. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes; and the COVID-19 pandemic and the duration and impact thereof.

Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities, operating performance, legislative and regulatory parameters; litigation, including with respect to the Dakota Access Pipeline (DAPL) and Line 5 dual pipelines; acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom; our dividend policy; project approval and support; renewals of rights-of-way; weather; economic and competitive conditions; public opinion; changes in tax laws and tax rates; exchange rates; interest rates; commodity prices; political decisions; the supply of, demand for 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 assumes no obligation to publicly update or revise any forward-looking statement made in this quarterly report on Form 10-Q or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	7,279	4,595	20,042	14,920
Transportation and other services	3,695	4,075	11,740	11,609
Gas distribution sales	492	440	2,769	2,550
Total operating revenues (Note 3)	11,466	9,110	34,551	29,079
Operating expenses
Commodity costs	7,347	4,443	19,975	14,464
Gas distribution costs	120	83	1,359	1,188
Operating and administrative	1,667	1,554	4,710	4,955
Depreciation and amortization	944	935	2,805	2,766

Total operating expenses	10,078	7,015	28,849	23,373
Operating income	1,388	2,095	5,702	5,706
Income from equity investments	440	315	1,187	805
Impairment of equity investments (Note 8)	(111)	(615)	(111)	(2,351)
Other income/(expense)
Net foreign currency gain/(loss)	(165)	173	146	(257)
Other	109	85	300	(8)
Interest expense	(648)	(718)	(1,923)	(2,105)
Earnings before income taxes	1,013	1,335	5,301	1,790
Income tax expense (Note 10)	(199)	(231)	(952)	(273)
Earnings	814	1,104	4,349	1,517
Earnings attributable to noncontrolling interests	(34)	(20)	(93)	(25)
Earnings attributable to controlling interests	780	1,084	4,256	1,492
Preference share dividends	(98)	(94)	(280)	(284)
Earnings attributable to common shareholders	682	990	3,976	1,208
Earnings per common share attributable to common shareholders (Note 5)	0.34	0.49	1.97	0.60
Diluted earnings per common share attributable to common shareholders (Note 5)	0.34	0.49	1.96	0.60

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(unaudited; millions of Canadian dollars)
Earnings	814	1,104	4,349	1,517
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	(16)	29	197	(532)
Change in unrealized gain/(loss) on net investment hedges	(206)	154	16	(221)
Other comprehensive income/(loss) from equity investees	(30)	(14)	(28)	6
Excluded components of fair value hedges	(1)	(1)	(3)	7
Reclassification to earnings of loss on cash flow hedges	55	58	168	138
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	5	3	16	10
Foreign currency translation adjustments	1,281	(1,119)	(350)	1,817
Other comprehensive income/(loss), net of tax	1,088	(890)	16	1,225
Comprehensive income	1,902	214	4,365	2,742
Comprehensive (income)/loss attributable to noncontrolling interests	(62)	16	(68)	(79)
Comprehensive income attributable to controlling interests	1,840	230	4,297	2,663
Preference share dividends	(98)	(94)	(280)	(284)
Comprehensive income attributable to common shareholders	1,742	136	4,017	2,379

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares
Balance at beginning and end of period	7,747	7,747	7,747	7,747
Common shares
Balance at beginning of period	64,780	64,763	64,768	64,746
Shares issued on exercise of stock options	10	1	22	18
Balance at end of period	64,790	64,764	64,790	64,764
Additional paid-in capital
Balance at beginning of period	324	207	277	187
Stock-based compensation	7	6	23	25
Options exercised	(7)	(1)	(15)	(19)
Change in reciprocal interest	—	54	39	66

Other	—	(1)	—	6
Balance at end of period	324	265	324	265
Deficit
Balance at beginning of period	(8,388)	(7,797)	(9,995)	(6,314)
Earnings attributable to controlling interests	780	1,084	4,256	1,492
Preference share dividends	(98)	(94)	(280)	(284)
Dividends paid to reciprocal shareholder	1	4	6	14
Common share dividends declared	(1,692)	(1,640)	(3,384)	(3,281)
Adoption of ASU 2016-13 Financial Instruments - Credit Losses	—	—	—	(66)
Other	—	1	—	(3)
Balance at end of period	(9,397)	(8,442)	(9,397)	(8,442)
Accumulated other comprehensive income/(loss) (Note 7)
Balance at beginning of period	(2,420)	1,753	(1,401)	(272)
Other comprehensive income/(loss) attributable to common shareholders, net of tax	1,060	(854)	41	1,171

Balance at end of period	(1,360)	899	(1,360)	899
Reciprocal shareholding
Balance at beginning of period	(17)	(47)	(29)	(51)
Change in reciprocal interest	—	18	12	22
Balance at end of period	(17)	(29)	(17)	(29)
Total Enbridge Inc. shareholders’ equity	62,087	65,204	62,087	65,204
Noncontrolling interests
Balance at beginning of period	2,870	3,315	2,996	3,364
Earnings attributable to noncontrolling interests	34	20	93	25
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized loss on cash flow hedges	(9)	—	(15)	(3)
Foreign currency translation adjustments	37	(36)	(10)	57



Contributions	4	1	13	21
Distributions	(67)	(68)	(210)	(232)

Redemption of preferred shares held by subsidiary	(293)	—	(293)	—
Other	(1)	(1)	1	(1)
Balance at end of period	2,575	3,231	2,575	3,231
Total equity	64,662	68,435	64,662	68,435
Dividends paid per common share	0.835	0.810	2.505	2.430

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine months ended September 30,
	2021	2020
(unaudited; millions of Canadian dollars)
Operating activities
Earnings	4,349	1,517
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	2,805	2,766
Deferred income tax expense/(recovery)	789	(82)
Unrealized derivative fair value loss, net (Note 9)	86	200
Income from equity investments	(1,187)	(805)
Distributions from equity investments	1,197	1,145
Impairment of equity investments (Note 8)	111	2,351

Gain on disposition	(41)	—
Other	(87)	222
Changes in operating assets and liabilities	(1,068)	213
Net cash provided by operating activities	6,954	7,527
Investing activities
Capital expenditures	(5,475)	(3,790)
Long-term investments and restricted long-term investments	(241)	(413)
Distributions from equity investments in excess of cumulative earnings	295	438
Additions to intangible assets	(185)	(154)
Proceeds from disposition	122	265
Affiliate loans, net	19	10
Other	(30)	—
Net cash used in investing activities	(5,495)	(3,644)
Financing activities
Net change in short-term borrowings	84	71
Net change in commercial paper and credit facility draws	(32)	231
Debenture and term note issues, net of issue costs	6,135	4,834
Debenture and term note repayments	(1,888)	(3,517)
Contributions from noncontrolling interests	13	21
Distributions to noncontrolling interests	(210)	(232)
Common shares issued	3	3
Preference share dividends	(274)	(284)
Common share dividends	(5,074)	(4,920)
Redemption of preferred shares held by subsidiary	(115)	—
Other	(64)	(52)
Net cash used in financing activities	(1,422)	(3,845)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	(12)	(22)
Net increase in cash and cash equivalents and restricted cash	25	16
Cash and cash equivalents and restricted cash at beginning of period	490	676
Cash and cash equivalents and restricted cash at end of period	515	692

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	September 30, 2021	December 31, 2020
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	451	452
Restricted cash	64	38
Accounts receivable and other	6,378	5,258
Accounts receivable from affiliates	170	66
Inventory	1,495	1,536
	8,558	7,350
Property, plant and equipment, net	98,097	94,571
Long-term investments	13,489	13,818
Restricted long-term investments	575	553
Deferred amounts and other assets	8,413	8,446
Intangible assets, net	2,212	2,080
Goodwill	32,573	32,688
Deferred income taxes	615	770
Total assets	164,532	160,276

Liabilities and equity
Current liabilities
Short-term borrowings	1,205	1,121
Accounts payable and other	8,754	9,228
Accounts payable to affiliates	170	22
Interest payable	619	651
Current portion of long-term debt	4,693	2,957
	15,441	13,979
Long-term debt	65,036	62,819
Other long-term liabilities	8,116	8,783
Deferred income taxes	11,277	10,332
	99,870	95,913
Contingencies (Note 12)
Equity
Share capital
Preference shares	7,747	7,747
Common shares (2,026 outstanding at September 30, 2021 and December 31, 2020)	64,790	64,768
Additional paid-in capital	324	277
Deficit	(9,397)	(9,995)
Accumulated other comprehensive loss (Note 7)	(1,360)	(1,401)
Reciprocal shareholding	(17)	(29)
Total Enbridge Inc. shareholders’ equity	62,087	61,367
Noncontrolling interests	2,575	2,996
	64,662	64,363
Total liabilities and equity	164,532	160,276

The accompanying notes are an integral part of these interim consolidated financial statements.

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by 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, 2020. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our audited consolidated financial statements for the year ended December 31, 2020, except for the adoption of new standards (Note 2). Amounts are stated in Canadian dollars unless otherwise noted.

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

2. CHANGES IN ACCOUNTING POLICIES

ADOPTION OF NEW ACCOUNTING STANDARDS

Reference Rate Reform

For eligible hedging relationships existing as at January 1, 2021 and prospectively, we have applied the optional expedient in Accounting Standards Update (ASU) 2020-04 whereby the modification of the hedging instrument does not result in an automatic hedging relationship de-designation. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Clarifying Interaction Between Equity Securities, Equity Method Investments and Derivatives

Effective January 1, 2021, we adopted ASU 2020-01 on a prospective basis. The new standard was issued in January 2020 and clarifies that observable transactions should be considered for the purpose of applying the measurement alternative in accordance with Accounting Standards Codification (ASC) 321 Investments - Equity Securities immediately before the application or upon discontinuance of the equity method of accounting. Furthermore, the ASU clarifies that forward contracts or purchased options on equity securities are not out of scope of ASC 815 Derivatives and Hedging guidance only because, upon the contracts’ exercise, the equity securities could be accounted for under the equity method of accounting or fair value option. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Accounting for Income Taxes

Effective January 1, 2021, we adopted ASU 2019-12 on a prospective basis. The new standard was issued in December 2019 with the intent of simplifying the accounting for income taxes. The accounting update removes certain exceptions to the general principles in ASC 740 Income Taxes as well as provides simplification by clarifying and amending existing guidance. The adoption of this ASU did not have a material impact on our consolidated financial statements.

FUTURE ACCOUNTING POLICY CHANGES

Accounting for Certain Lessor Leases with Variable Lease Payments

ASU 2021-05 was issued in July 2021 to amend lessor accounting for certain leases with variable lease payments that do not depend on a reference index or a rate and would have resulted in the recognition of a loss at lease commencement if classified as a sales-type or a direct financing lease. The ASU amends the classification requirements of such leases for lessors to result in an operating lease classification. ASU 2021-05 is effective January 1, 2022 and can be applied either retrospectively or prospectively with early adoption permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

Accounting for Modifications or Exchanges of Certain Equity-Classified Contracts

ASU 2021-04 was issued in 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 accounting for the modification or exchange based on the economic substance of the modification or exchange. ASU 2021-04 is effective January 1, 2022 and should be applied prospectively. We are currently assessing the impact of the new standard on our consolidated financial statements.

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity

ASU 2020-06 was 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 settled in either cash or shares. ASU 2020-06 is effective January 1, 2022 and should be applied on a full or modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.

Accounting for Contract Assets and Liabilities from Contracts with Customers in a Business Combination

ASU 2021-08 was issued in October 2021 to amend business combination accounting specific to contract assets and contract liabilities resulting from contracts with customers, requiring measurement in accordance with ASC 606. The ASU is also applicable to contract assets and contract liabilities from other contracts to which ASC 606 applies, such as contract liabilities from the sale of nonfinancial assets within the scope of ASC 610-20. ASU 2021-08 is effective January 1, 2023 and should be applied prospectively with early adoption permitted. Early adoption requires retrospective application for business combinations with an acquisition date in the year of early application. We are currently assessing the impact of the new standard on our consolidated financial statements.

3. REVENUES

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Three months ended September 30, 2021
(millions of Canadian dollars)
Transportation revenue	2,340	1,081	128	—	—	—	3,549
Storage and other revenue	33	58	50	—	—	—	141
Gas gathering and processing revenue	—	15	—	—	—	—	15
Gas distribution revenue	—	—	496	—	—	—	496
Electricity and transmission revenue	—	—	—	44	—	—	44

Total revenue from contracts with customers	2,373	1,154	674	44	—	—	4,245
Commodity sales	—	—	—	—	7,279	—	7,279
Other revenue1,2	(143)	4	24	78	(1)	(20)	(58)
Intersegment revenue	140	1	(11)	—	12	(142)	—
Total revenue	2,370	1,159	687	122	7,290	(162)	11,466


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Three months ended September 30, 2020
(millions of Canadian dollars)
Transportation revenue	2,234	1,077	128	—	—	—	3,439
Storage and other revenue	22	64	51	—	—	—	137
Gas gathering and processing revenue	—	7	—	—	—	—	7
Gas distribution revenue	—	—	448	—	—	—	448
Electricity and transmission revenue	—	—	—	46	—	—	46

Total revenue from contracts with customers	2,256	1,148	627	46	—	—	4,077
Commodity sales	—	—	—	—	4,595	—	4,595
Other revenue1,2	360	14	(8)	80	(3)	(5)	438
Intersegment revenue	157	—	2	—	4	(163)	—
Total revenue	2,773	1,162	621	126	4,596	(168)	9,110


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Nine months ended September 30, 2021
(millions of Canadian dollars)
Transportation revenue	6,826	3,248	494	—	—	—	10,568
Storage and other revenue	96	195	159	—	—	—	450
Gas gathering and processing revenue	—	32	—	—	—	—	32
Gas distribution revenue	—	—	2,755	—	—	—	2,755
Electricity and transmission revenue	—	—	—	125	—	—	125

Total revenue from contracts with customers	6,922	3,475	3,408	125	—	—	13,930
Commodity sales	—	—	—	—	20,042	—	20,042
Other revenue1,2	284	25	42	246	—	(18)	579
Intersegment revenue	410	1	13	—	26	(450)	—
Total revenue	7,616	3,501	3,463	371	20,068	(468)	34,551


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Nine months ended September 30, 2020
(millions of Canadian dollars)
Transportation revenue	6,815	3,458	494	—	—	—	10,767
Storage and other revenue	72	209	154	—	—	—	435
Gas gathering and processing revenue	—	19	—	—	—	—	19
Gas distribution revenue	—	—	2,551	—	—	—	2,551
Electricity and transmission revenue	—	—	—	150	—	—	150

Total revenue from contracts with customers	6,887	3,686	3,199	150	—	—	13,922
Commodity sales	—	—	—	—	14,920	—	14,920
Other revenue1,2	(59)	35	(1)	279	1	(18)	237
Intersegment revenue	424	1	8	—	22	(455)	—
Total revenue	7,252	3,722	3,206	429	14,943	(473)	29,079

1 Includes mark-to-market gains/(losses) from our hedging program for the three months ended September 30, 2021 and 2020 of $225 million mark-to-market loss and $276 million mark-to-market gain, respectively. For the nine months ended September 30, 2021 and 2020, Other revenue includes a $36 million mark-to-market gain and $298 million mark-to-market loss, respectively.

2 Includes revenues from lease contracts for the three months ended September 30, 2021 and 2020 of $140 million and $144 million, respectively and for the nine months ended September 30, 2021 and 2020 of $442 million and $459 million, respectively.

We disaggregate revenues into categories which represent our principal performance obligations within each business segment. 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 Receivables	Contract Assets	Contract Liabilities
(millions of Canadian dollars)
Balance as at September 30, 2021	1,673	212	1,842
Balance as at December 31, 2020	2,042	226	1,815

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

Contract assets represent the amount of revenues which have 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 payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to receive the consideration becomes unconditional.

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenues. Revenue recognized during the three and nine months ended September 30, 2021 included in contract liabilities at the beginning of the period was $44 million and $269 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three and nine months ended September 30, 2021 were $154 million and $299 million, respectively.

Performance Obligations

There were no material revenues recognized in the three and nine months ended September 30, 2021 from performance obligations satisfied in previous periods.

Revenues to be Recognized from Unfulfilled Performance Obligations

Total revenues from performance obligations expected to be fulfilled in future periods are $55.6 billion, of which $1.7 billion and $5.6 billion are expected to be recognized during the remaining three months ending December 31, 2021 and the year ending December 31, 2022, respectively.

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

Variable Consideration

During the three months ended September 30, 2021, 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 Canadian Mainline commercial arrangement is implemented and are subject to finalization and adjustment applicable to the interim period, if any. Due to the uncertainty of adjustment to tolling pursuant to a Canada Energy Regulator decision and potential customer negotiations, the interim toll revenue recognized during the three months ended September 30, 2021 is considered variable consideration. We do not expect a significant adjustment to revenue when the uncertainty is resolved.

Recognition and Measurement of Revenues


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
Three months ended September 30, 2021
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	13	—	13
Revenues from products and services transferred over time1	2,373	1,154	661	44	4,232
Total revenue from contracts with customers	2,373	1,154	674	44	4,245


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
Three months ended September 30, 2020
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	15	—	15
Revenues from products and services transferred over time1	2,256	1,148	612	46	4,062
Total revenue from contracts with customers	2,256	1,148	627	46	4,077


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
Nine months ended September 30, 2021
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	47	—	47
Revenues from products and services transferred over time1	6,922	3,475	3,361	125	13,883
Total revenue from contracts with customers	6,922	3,475	3,408	125	13,930


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
Nine months ended September 30, 2020
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	45	—	45
Revenues from products and services transferred over time1	6,887	3,686	3,154	150	13,877
Total revenue from contracts with customers	6,887	3,686	3,199	150	13,922

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

4. SEGMENTED INFORMATION


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Three months ended September 30, 2021
(millions of Canadian dollars)
Revenues	2,370	1,159	687	122	7,290	(162)	11,466
Commodity and gas distribution costs	(6)	—	(135)	—	(7,485)	159	(7,467)
Operating and administrative	(919)	(445)	(280)	(51)	(13)	41	(1,667)

Income/(loss) from equity investments	226	211	(12)	15	—	—	440
Impairment of equity investments	—	(111)	—	—	—	—	(111)
Other income/(expense)	2	70	22	5	4	(159)	(56)
Earnings/(loss) before interest, income taxes, and depreciation and amortization	1,673	884	282	91	(204)	(121)	2,605
Depreciation and amortization							(944)
Interest expense							(648)
Income tax expense							(199)
Earnings							814
Capital expenditures1	1,053	602	359	—	1	18	2,033


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Three months ended September 30, 2020
(millions of Canadian dollars)
Revenues	2,773	1,162	621	126	4,596	(168)	9,110
Commodity and gas distribution costs	(5)	—	(87)	—	(4,613)	179	(4,526)
Operating and administrative	(811)	(432)	(243)	(57)	(15)	4	(1,554)


Income/(loss) from equity investments	118	191	(13)	22	(3)	—	315
Impairment of equity investments	—	(615)	—	—	—	—	(615)
Other income	15	28	20	2	1	192	258
Earnings/(loss) before interest, income taxes, and depreciation and amortization	2,090	334	298	93	(34)	207	2,988
Depreciation and amortization							(935)
Interest expense							(718)
Income tax expense							(231)
Earnings							1,104
Capital expenditures1	442	642	339	11	1	22	1,457


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Nine months ended September 30, 2021
(millions of Canadian dollars)
Revenues	7,616	3,501	3,463	371	20,068	(468)	34,551
Commodity and gas distribution costs	(16)	—	(1,392)	—	(20,405)	479	(21,334)
Operating and administrative	(2,411)	(1,303)	(794)	(131)	(36)	(35)	(4,710)
Income from equity investments	560	525	37	65	—	—	1,187
Impairment of equity investments	—	(111)	—	—	—	—	(111)
Other income/(expense)	7	113	60	57	(6)	215	446
Earnings/(loss) before interest, income taxes, and depreciation and amortization	5,756	2,725	1,374	362	(379)	191	10,029
Depreciation and amortization							(2,805)
Interest expense							(1,923)
Income tax expense							(952)
Earnings							4,349
Capital expenditures1	2,976	1,631	878	7	1	39	5,532


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Nine months ended September 30, 2020
(millions of Canadian dollars)
Revenues	7,252	3,722	3,206	429	14,943	(473)	29,079
Commodity and gas distribution costs	(13)	—	(1,213)	—	(14,877)	451	(15,652)
Operating and administrative	(2,458)	(1,377)	(761)	(144)	(72)	(143)	(4,955)
Income from equity investments	463	284	2	59	(3)	—	805
Impairment of equity investments	—	(2,351)	—	—	—	—	(2,351)


Other income/(expense)	36	(48)	51	32	(3)	(333)	(265)
Earnings/(loss) before interest, income taxes, and depreciation and amortization	5,280	230	1,285	376	(12)	(498)	6,661
Depreciation and amortization							(2,766)
Interest expense							(2,105)
Income tax expense							(273)
Earnings							1,517
Capital expenditures1	1,503	1,462	765	41	2	63	3,836

1 Includes allowance for equity funds used during construction.

5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

BASIC

Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of approximately 2 million for the three and nine months ended September 30, 2021, compared to 5 million for the three and nine months ended September 30, 2020, 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 September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(number of shares in millions)
Weighted average shares outstanding	2,024	2,021	2,023	2,020
Effect of dilutive options	2	—	2	1
Diluted weighted average shares outstanding	2,026	2,021	2,025	2,021

For the three months ended September 30, 2021 and 2020, 13.3 million and 34.1 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $56.16 and $50.55, respectively, were excluded from the diluted earnings per common share calculation.

For the nine months ended September 30, 2021 and 2020, 20.5 million and 28.5 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $52.19 and $51.85, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE

On November 3, 2021, our Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2021 to shareholders of record on November 15, 2021.


			Dividend per share
Common Shares1			$0.83500
Preference Shares, Series A			$0.34375
Preference Shares, Series B			$0.21340
Preference Shares, Series C2			$0.16081
Preference Shares, Series D			$0.27875
Preference Shares, Series F			$0.29306
Preference Shares, Series H			$0.27350
Preference Shares, Series J			US$0.30540
Preference Shares, Series L			US$0.30993
Preference Shares, Series N			$0.31788
Preference Shares, Series P			$0.27369
Preference Shares, Series R			$0.25456
Preference Shares, Series 1			US$0.37182
Preference Shares, Series 3			$0.23356
Preference Shares, Series 5			US$0.33596
Preference Shares, Series 7			$0.27806
Preference Shares, Series 9			$0.25606
Preference Shares, Series 11			$0.24613
Preference Shares, Series 13			$0.19019
Preference Shares, Series 15			$0.18644
Preference Shares, Series 17			$0.32188
Preference Shares, Series 19			$0.30625

1 The quarterly dividend per common share was increased 3% to $0.835 from $0.81, effective March 1, 2021.

2 The quarterly dividend per share paid on Series C was increased to $0.15501 from $0.15349 on March 1, 2021, increased to $0.15753 from $0.15501 on June 1, 2021, and increased to $0.16081 from $0.15753 on September 1, 2021, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.

6. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at September 30, 2021:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2022-2026	9,169	7,378	1,791
Enbridge (U.S.) Inc.	2023-2026	6,968	2,515	4,453
Enbridge Pipelines Inc.	2023	3,000	469	2,531
Enbridge Gas Inc.	2023	2,000	1,205	795
Total committed credit facilities		21,137	11,567	9,570

1Maturity date is inclusive of the one-year term out option for certain credit facilities.

2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

On February 10, 2021, Enbridge Inc. entered into a three year, revolving, extendible, sustainability-linked credit facility for $1.0 billion with a syndicate of lenders and concurrently terminated our one year, revolving, syndicated credit facility for $3.0 billion.

On February 25, 2021, two term loans with an aggregate total of US$500 million were repaid with proceeds from a floating rate notes issuance.

On July 22 and 23, 2021, we renewed approximately $8.0 billion of our five-year credit facilities, extending the maturity date out to July 2026. We also extended approximately $10.0 billion of our 364-day extendible credit facilities to July 2022, which includes a one-year term out provision to July 2023.

In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $868 million was unutilized as at September 30, 2021. As at December 31, 2020, we had $849 million of uncommitted demand letter of credit facilities, of which $533 million was unutilized.

Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2022 to 2026.

As at September 30, 2021 and December 31, 2020, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $8.3 billion and $9.9 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.

LONG-TERM DEBT ISSUANCES

During the nine months ended September 30, 2021, we completed the following long-term debt issuances totaling US$2.4 billion and $3.2 billion:


Company	Issue Date		Principal Amount
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
	February 2021	Floating rate notes due February 20231	US$500
	June 2021	2.50% Sustainability-Linked senior notes due August 2033	US$1,000
	June 2021	3.40% senior notes due August 2051	US$500
	September 2021	3.10% Sustainability-Linked medium-term notes due September 2033	$1,100
	September 2021	4.10% medium-term notes due September 2051	$400
Enbridge Gas Inc.
	September 2021	2.35% medium-term notes due September 2031	$475
	September 2021	3.20% medium-term notes due September 2051	$425
Enbridge Pipelines Inc.
	May 2021	2.82% medium-term notes due May 2031	$400
	May 2021	4.20% medium-term notes due May 2051	$400
Spectra Energy Partners, LP
	September 2021	2.50% senior notes due September 20312	US$400

1Notes mature in two years and carry an interest rate set to equal Secured Overnight Financing Rate plus a margin of 40 basis points.

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

On October 4, 2021, we closed a three tranche offering of aggregate US$1.5 billion senior notes consisting of US$500 million 0.55% 2-year notes, US$500 million 1.60% 5-year notes, and a US$500 million re-opening of the 3.40% 2051 notes issued in June 2021. Each tranche is payable semi-annually in arrears and matures on October 4, 2023, October 4, 2026, and August 1, 2051, respectively.

LONG-TERM DEBT REPAYMENTS

During the nine months ended September 30, 2021, we completed the following long-term debt repayments totaling $808 million and US$880 million:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars unless otherwise stated)

Enbridge Inc.

February 2021

4.26% medium-term notes

$200

March 2021

3.16% medium-term notes

$400

Enbridge Energy Partners, L.P.

June 2021

4.20% senior notes

US$600

Enbridge Gas Inc.

May 2021

2.76% medium-term notes

$200

Enbridge Pipelines (Southern Lights) L.L.C.

June 2021

3.98% senior notes

US$30

Enbridge Southern Lights LP

June 2021

4.01% senior notes

Spectra Energy Partners, LP

March 2021

4.60% senior notes

US$250

SUBORDINATED TERM NOTES

As at September 30, 2021 and December 31, 2020, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $7.7 billion and $7.8 billion, respectively.

FAIR VALUE ADJUSTMENT

As at September 30, 2021 and December 31, 2020, the net fair value adjustments to total debt assumed in a historical acquisition were $687 million and $750 million, respectively. During the three months ended September 30, 2021 and 2020, amortization of the fair value adjustment recorded as a reduction to Interest expense in the Consolidated Statements of Earnings was $11 million and $13 million, respectively. During the nine months ended September 30, 2021 and 2020, amortization of the fair value adjustment recorded as a reduction to Interest expense in the Consolidated Statements of Earnings was $36 million and $42 million, respectively.

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at September 30, 2021, we were in compliance with all covenant provisions.

7. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE LOSS

Changes in Accumulated other comprehensive loss (AOCI) attributable to our common shareholders for the nine months ended September 30, 2021 and 2020 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, 2021	(1,326)	5	(215)	568	66	(499)	(1,401)
Other comprehensive income/(loss) retained in AOCI	284	(3)	18	(340)	(33)	—	(74)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	218	—	—	—	—	—	218
Commodity contracts2	(4)	—	—	—	—	—	(4)
Foreign exchange contracts3	4	—	—	—	—	—	4
Other contracts4	1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial loss and prior service costs5	—	—	—	—	—	21	21
Other	17	—	—	(20)	3	—	—
	520	(3)	18	(360)	(30)	21	166
Tax impact
Income tax on amounts retained in AOCI	(72)	—	(2)	—	5	—	(69)
Income tax on amounts reclassified to earnings	(51)	—	—	—	—	(5)	(56)
	(123)	—	(2)	—	5	(5)	(125)

Balance as at September 30, 2021	(929)	2	(199)	208	41	(483)	(1,360)


	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, 2020	(1,073)	—	(317)	1,396	67	(345)	(272)
Other comprehensive income/(loss) retained in AOCI	(696)	7	(228)	1,760	8	—	851
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	179	—	—	—	—	—	179
Commodity contracts2	(1)	—	—	—	—	—	(1)
Foreign exchange contracts3	3	—	—	—	—	—	3
Other contracts4	(1)	—	—	—	—	—	(1)
Amortization of pension and OPEB actuarial loss and prior service costs5	—	—	—	—	—	13	13
	(516)	7	(228)	1,760	8	13	1,044
Tax impact
Income tax on amounts retained in AOCI	167	—	7	—	(2)	—	172
Income tax on amounts reclassified to earnings	(42)	—	—	—	—	(3)	(45)
	125	—	7	—	(2)	(3)	127

Balance as at September 30, 2020	(1,464)	7	(538)	3,156	73	(335)	899

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

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

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

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

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

8. IMPAIRMENT OF EQUITY INVESTMENTS

PennEast Pipeline Company, L.L.C.

PennEast Pipeline Company, L.L.C. (PennEast) is a joint venture formed to develop a natural gas transmission pipeline to serve local distribution companies and power generators in Southeastern Pennsylvania and New Jersey, is owned 20% by Enbridge, and is recorded as an equity method investment. During the three months ended September 30, 2021, PennEast determined further development of the project was no longer viable and further development of the project has ceased. As a result, we recorded an other than temporary impairment loss of $111 million on our investment for the three and nine months ended September 30, 2021 based on the estimated fair value of our share of the net assets. The carrying value of this investment as at September 30, 2021 and December 31, 2020 was $11 million and $116 million, respectively.

Steckman Ridge, LP

Steckman Ridge, LP (Steckman) is engaged in the storage of natural gas, is owned 50% by Enbridge, and is recorded as an equity method investment. In the third quarter of 2020, Steckman’s forecasted performance was adjusted for the expectation that future available capacity will be re-contracted at lower than expected rates and an other than temporary impairment loss on our investment of $221 million for the three and nine months ended September 30, 2020 was recorded based on a discounted cash flow analysis. The carrying value of this investment as at September 30, 2021 and December 31, 2020 was $88 million and $90 million, respectively.

Southeast Supply Header, L.L.C.

Southeast Supply Header, L.L.C. (SESH) provides natural gas transmission services from east Texas and northern Louisiana to the southeast markets of the Gulf Coast. SESH is owned 50% by Enbridge and is recorded as an equity method investment. In the third quarter of 2020, SESH's forecasted performance was revised to reflect downward revisions to future negotiated rates as well as higher than expected available capacity levels, caused primarily by a significant contract expiry. An other than temporary impairment loss on our investment of $394 million for the three and nine months ended September 30, 2020 was recorded based on a discounted cash flow analysis. The carrying value of this investment as at September 30, 2021 and December 31, 2020 was $83 million and $84 million, respectively.

DCP Midstream, LLC

DCP Midstream, LLC (DCP Midstream), a 50% owned equity method investment of Enbridge, holds an equity interest in DCP Midstream, LP. A decline in the market price of DCP Midstream, LP’s publicly traded units during the first quarter of 2020 resulted in an other than temporary impairment loss on our investment in DCP Midstream of $1.7 billion for the nine months ended September 30, 2020. In addition, we incurred losses of $324 million through our equity earnings pick up in relation to asset and goodwill impairment losses recorded by DCP Midstream, LP during the nine months ended September 30, 2020. The carrying value of our investment in DCP Midstream as at September 30, 2021 and December 31, 2020 was $298 million and $331 million, respectively.

Our investments in PennEast, Steckman, SESH, and DCP Midstream form part of our Gas Transmission and Midstream segment. The impairment losses were recorded within Impairment of equity investments in the Consolidated Statements of Earnings.

9. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

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

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

Foreign Exchange Risk

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

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

Interest Rate Risk

Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 3.2%.

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 September 30, 2021, we do not have any pay floating-receive fixed interest rate swaps outstanding.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 1.9%.

Commodity Price Risk

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

Equity Price Risk

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

COVID-19 PANDEMIC RISK

The spread of the COVID-19 pandemic has caused significant volatility in Canada, the US and international markets. While we have taken proactive measures to deliver energy safely and reliably during this pandemic, given the ongoing dynamic nature of the circumstances surrounding COVID-19, including ongoing uncertainty as to the duration of the pandemic and corresponding public health measures, the impact of this pandemic and the ongoing recovery on our business remains uncertain.

TOTAL DERIVATIVE INSTRUMENTS

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

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


September 30, 2021	Derivative Instruments Used as Cash Flow Hedges	Derivative Instruments Used as Net Investment Hedges	Derivative Instruments Used as Fair Value Hedges	Non- Qualifying Derivative Instruments	Total Gross Derivative Instruments as Presented	Amounts Available for Offset	Total Net Derivative Instruments
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts	—	—	—	225	225	(31)	194

Commodity contracts	—	—	—	320	320	(278)	42
Other contracts	1	—	—	7	8	—	8
	1	—	—	552	553	(309)	244
Deferred amounts and other assets
Foreign exchange contracts	—	—	—	248	248	(86)	162
Interest rate contracts	168	—	—	—	168	(25)	143
Commodity contracts	—	—	—	83	83	(61)	22
Other contracts	1	—	—	2	3	—	3
	169	—	—	333	502	(172)	330
Accounts payable and other
Foreign exchange contracts	(8)	—	(105)	(148)	(261)	31	(230)
Interest rate contracts	(37)	—	—	2	(35)	—	(35)
Commodity contracts	(14)	—	—	(535)	(549)	278	(271)

	(59)	—	(105)	(681)	(845)	309	(536)
Other long-term liabilities
Foreign exchange contracts	—	—	—	(499)	(499)	86	(413)
Interest rate contracts	(115)	—	—	(23)	(138)	25	(113)
Commodity contracts	(18)	—	—	(131)	(149)	61	(88)

	(133)	—	—	(653)	(786)	172	(614)
Total net derivative assets/(liabilities)
Foreign exchange contracts	(8)	—	(105)	(174)	(287)	—	(287)
Interest rate contracts	16	—	—	(21)	(5)	—	(5)
Commodity contracts	(32)	—	—	(263)	(295)	—	(295)
Other contracts	2	—	—	9	11	—	11
	(22)	—	(105)	(449)	(576)	—	(576)


December 31, 2020	Derivative Instruments Used as Cash Flow Hedges	Derivative Instruments Used as Net Investment Hedges	Derivative Instruments Used as Fair Value Hedges	Non- Qualifying Derivative Instruments	Total Gross Derivative Instruments as Presented	Amounts Available for Offset	Total Net Derivative Instruments
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts	—	—	—	180	180	(28)	152

Commodity contracts	—	—	—	143	143	(81)	62

	—	—	—	323	323	(109)	214
Deferred amounts and other assets
Foreign exchange contracts	14	—	—	452	466	(218)	248
Interest rate contracts	56	—	—	—	56	(25)	31
Commodity contracts	—	—	—	39	39	(9)	30

	70	—	—	491	561	(252)	309
Accounts payable and other
Foreign exchange contracts	(5)	—	(29)	(151)	(185)	28	(157)
Interest rate contracts	(423)	—	—	(2)	(425)	—	(425)
Commodity contracts	(2)	—	—	(278)	(280)	81	(199)
Other contracts	(1)	—	—	(3)	(4)	—	(4)
	(431)	—	(29)	(434)	(894)	109	(785)
Other long-term liabilities
Foreign exchange contracts	—	—	(87)	(673)	(760)	218	(542)
Interest rate contracts	(218)	—	—	(23)	(241)	25	(216)
Commodity contracts	(1)	—	—	(57)	(58)	9	(49)

	(219)	—	(87)	(753)	(1,059)	252	(807)
Total net derivative assets/(liabilities)
Foreign exchange contracts	9	—	(116)	(192)	(299)	—	(299)
Interest rate contracts	(585)	—	—	(25)	(610)	—	(610)
Commodity contracts	(3)	—	—	(153)	(156)	—	(156)
Other contracts	(1)	—	—	(3)	(4)	—	(4)
	(580)	—	(116)	(373)	(1,069)	—	(1,069)

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


September 30, 2021	2021	2022	2023	2024	2025	Thereafter	Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)	1,357	1,750	—	—	—	—	3,107
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)	2,210	6,354	3,784	2,480	1,290	672	16,790
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	62	28	29	30	30	60	239

Foreign exchange contracts - Euro forwards - sell (millions of Euro)	38	94	92	91	86	428	829
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	—	72,500	—	—	—	—	72,500
Interest rate contracts - short-term debt pay fixed rate (millions of Canadian dollars)	992	395	47	35	30	90	1,589
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	—	1,987	1,333	—	—	—	3,320
Equity contracts (millions of Canadian dollars)	40	19	26	20	—	—	105
Commodity contracts - natural gas (billions of cubic feet)2	19	55	15	4	10	(16)	87
Commodity contracts - crude oil (millions of barrels)2	12	2	—	—	—	—	14

Commodity contracts - power (megawatt per hour) (MW/H)	(18)	(43)	(43)	(43)	(43)	—	(42)	1

1 Total is an average net purchase/(sale) of power.

2 Total is a net purchase/(sale) of underlying commodity.

Fair Value Derivatives

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


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	50	(60)	15	25
Unrealized gain/(loss) on hedged item	(50)	59	(22)	(6)
Realized loss on derivative	(1)	—	(40)	(12)
Realized gain on hedged item	—	—	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 September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	4	—	(21)	6
Interest rate contracts	(1)	41	293	(709)
Commodity contracts	(21)	(1)	(25)	8
Other contracts	(2)	—	2	(6)
Fair value hedges
Foreign exchange contracts	(1)	(1)	(3)	7
Net investment hedges
Foreign exchange contracts	—	17	—	13
	(21)	56	246	(681)
Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts1	1	1	4	3
Interest rate contracts2	76	76	218	179
Commodity contracts	(4)	(1)	(4)	(1)
Other contracts3	—	(1)	1	(1)
	73	75	219	180

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

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

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

We estimate that a loss of $59 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 27 months as at September 30, 2021.

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 September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars)
Foreign exchange contracts1	(436)	571	18	(186)
Interest rate contracts2	2	(13)	4	(28)
Commodity contracts3	(102)	69	(120)	25
Other contracts4	2	(3)	12	(11)
Total unrealized derivative fair value gain/(loss), net	(534)	624	(86)	(200)

1 For the respective nine months ended periods, reported within Transportation and other services revenues (2021 - $71 million gain; 2020 - $87 million loss) and Net foreign currency gain/(loss) (2021 - $53 million loss; 2020 - $99 million loss) in the Consolidated Statements of Earnings.

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

3 For the respective nine months ended periods, reported within Transportation and other services revenues (2021 - nil; 2020 - $8 million gain), Commodity sales (2021 - $5 million loss; 2020 - $176 million loss), Commodity costs (2021 - $124 million loss; 2020 - $195 million gain) and Operating and administrative expense (2021 - $8 million gain; 2020 - $2 million loss) in the Consolidated Statements of Earnings.

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

LIQUIDITY RISK

Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. We also maintain current shelf prospectuses with securities regulators which enables ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We are in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at September 30, 2021. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.

CREDIT RISK

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

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


	September 30, 2021	December 31, 2020
(millions of Canadian dollars)
Canadian financial institutions	471	481
US financial institutions	240	99
European financial institutions	176	28
Asian financial institutions	24	167
Other1	124	97
	1,035	872

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

As at September 30, 2021, we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association agreements. We held no cash collateral on derivative asset exposures as at September 30, 2021 and December 31, 2020.

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

Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within Enbridge Gas Inc., credit risk is mitigated by the utility's large and diversified customer base and the ability to recover an estimate for expected 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 utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and 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 instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.

FAIR VALUE OF FINANCIAL INSTRUMENTS

We categorize our derivative instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

Level 1

Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations.

Level 2

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

We have also categorized the fair value of our available-for-sale preferred share investment and long-term debt as Level 2. The fair value of our available-for-sale preferred share investment is based on the 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.

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, NGL and natural gas contracts, basis swaps, commodity swaps, and power and energy swaps. We do not have any other financial instruments categorized in Level 3.

We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps 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) as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit default swap spreads associated with our counterparties in our estimation of fair value.

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


September 30, 2021	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	225	—	225

Commodity contracts	129	150	41	320
Other contracts	—	8	—	8
	129	383	41	553
Long-term derivative assets
Foreign exchange contracts	—	248	—	248
Interest rate contracts	—	168	—	168
Commodity contracts	32	46	5	83
Other contracts	—	3	—	3
	32	465	5	502
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(261)	—	(261)
Interest rate contracts	—	(35)	—	(35)
Commodity contracts	(149)	(200)	(200)	(549)

	(149)	(496)	(200)	(845)
Long-term derivative liabilities
Foreign exchange contracts	—	(499)	—	(499)
Interest rate contracts	—	(138)	—	(138)
Commodity contracts	(35)	(34)	(80)	(149)

	(35)	(671)	(80)	(786)
Total net financial assets/(liabilities)
Foreign exchange contracts	—	(287)	—	(287)
Interest rate contracts	—	(5)	—	(5)
Commodity contracts	(23)	(38)	(234)	(295)
Other contracts	—	11	—	11
	(23)	(319)	(234)	(576)


December 31, 2020	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	180	—	180

Commodity contracts	43	33	67	143
	43	213	67	323
Long-term derivative assets
Foreign exchange contracts	—	466	—	466
Interest rate contracts	—	56	—	56
Commodity contracts	1	24	14	39
	1	546	14	561
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(185)	—	(185)
Interest rate contracts	—	(425)	—	(425)
Commodity contracts	(39)	(18)	(223)	(280)
Other contracts	—	(4)	—	(4)
	(39)	(632)	(223)	(894)
Long-term derivative liabilities
Foreign exchange contracts	—	(760)	—	(760)
Interest rate contracts	—	(241)	—	(241)
Commodity contracts	(1)	(8)	(49)	(58)
	(1)	(1,009)	(49)	(1,059)
Total net financial assets/(liabilities)
Foreign exchange contracts	—	(299)	—	(299)
Interest rate contracts	—	(610)	—	(610)
Commodity contracts	4	31	(191)	(156)
Other contracts	—	(4)	—	(4)
	4	(882)	(191)	(1,069)

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


September 30, 2021	Fair Value	Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	(20)	Forward gas price	3.34	9.66	4.95	$/mmbtu2
Crude	(2)	Forward crude price	68.14	94.91	81.51	$/barrel
NGL	—	Forward NGL price				$/gallon
Power	(65)	Forward power price	37.91	128.70	76.20	$/MW/H
Commodity contracts - physical1
Natural gas	(94)	Forward gas price	2.86	9.85	6.30	$/mmbtu2
Crude	(53)	Forward crude price	75.66	96.75	90.70	$/barrel
NGL	—	Forward NGL price	—	—	—	$/gallon
	(234)

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

2 One million British thermal units (mmbtu).

If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives.

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


	Nine months ended September 30,
	2021	2020
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(191)	(69)
Total gain/(loss)
Included in earnings1	(181)	(40)
Included in OCI	(29)	7
Settlements	167	38
Level 3 net derivative liability at end of period	(234)	(64)

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

There were no transfers into or out of Level 3 as at September 30, 2021 or December 31, 2020.

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.

During the nine months ended September 30, 2021 and 2020, we recognized an unrealized foreign exchange gain of $18 million and a loss of $226 million, respectively, on the translation of US dollar denominated debt and unrealized gain of nil and $13 million, respectively, on the change in fair value of our outstanding foreign exchange forward contracts in OCI. During the nine months ended September 30, 2021 and 2020, we recognized realized losses of nil and $15 million, respectively, 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

Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $52 million as at September 30, 2021 and December 31, 2020.

We have Restricted long-term investments held in trust totaling $575 million and $553 million as at September 30, 2021 and December 31, 2020, respectively, which are recognized at fair value.

During the nine months ended September 30, 2021, we entered into a definitive agreement to sell our 38.9% noncontrolling interest in Noverco, which is comprised of both common shares and preferred shares. Historically, the preferred shares have been classified as held-to-maturity and carried at amortized cost. As a result of our intent to sell our interest in Noverco, the preferred shares were reclassified from held-to-maturity to available-for-sale at fair value during the second quarter of 2021. The fair value of the preferred shares was $580 million and $567 million as at September 30, 2021 and December 31, 2020, respectively. There were no gains or losses recognized in OCI on reclassification.

As at September 30, 2021 and December 31, 2020, our long-term debt had a carrying value of $70.0 billion and $66.1 billion, respectively, before debt issuance costs and a fair value of $76.5 billion and $75.1 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at September 30, 2021 and December 31, 2020, the non-current notes receivable had a carrying value of $1.0 billion and $1.1 billion, respectively, which also approximates their fair value.

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

10. INCOME TAXES

The effective income tax rates for the three months ended September 30, 2021 and 2020 were 19.6% and 17.3%, respectively, and for the nine months ended September 30, 2021 and 2020 were 18.0% and 15.3%, respectively.

The period-over-period increases in the effective income tax rates are due to the effect of rate-regulated accounting for income taxes, the benefit of foreign tax rate differentials and an adjustment related to regulatory balances from prior year. The increase is partially offset by a reduction in US minimum tax and the release of previously recognized uncertain tax positions.

11. PENSION AND OTHER POSTRETIREMENT BENEFITS


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars)
Service cost	48	50	144	150
Interest cost	32	44	96	131
Expected return on plan assets	(84)	(90)	(252)	(270)
Amortization of actuarial loss and prior service costs	14	9	42	28
Net periodic benefit costs	10	13	30	39

For the three and nine months ended September 30, 2020, we incurred nil and $236 million in severance costs related to our voluntary workforce reduction program. For the three and nine months ended September 30, 2021, there were no such costs incurred. Severance costs are included in Operating and administrative expense in the Consolidated Statements of Earnings.

12. CONTINGENCIES

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

TAX MATTERS

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

13. SUBSEQUENT EVENT

On October 12, 2021, through a wholly-owned US subsidiary, we acquired all of the outstanding membership interests in Moda Midstream Operating, LLC (Moda) for US$3 billion of cash plus contingent consideration dependent on performance of the assets (the Acquisition). The Acquisition is also subject to customary closing and working capital adjustments. Moda owns and operates a light crude export platform with very large crude carrier capability. The Acquisition aligns with and advances our US Gulf Coast export strategy and enables connectivity to low-cost and long-lived reserves in the Permian and Eagle Ford basins.

We will account for the Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations. The acquired assets and assumed liabilities will be recorded at their estimated fair values as at the date of acquisition, with any remaining amount allocated to goodwill. Due to the proximity of the acquisition date to the release date of our interim consolidated financial statements, we have not performed our initial accounting for the Acquisition. The preliminary purchase price allocation will be disclosed in the fourth quarter of 2021 after asset and liability valuations become available.

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 our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of our annual report on Form 10-K for the year ended December 31, 2020.

We continue to qualify as a 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 (SEC) instead of filing the reporting forms available to foreign private issuers. We also intend to maintain our Form S-3 registration statements.

RECENT DEVELOPMENTS

ACQUISITION OF MODA MIDSTREAM OPERATING, LLC

On October 12, 2021, we closed the purchase of Moda Midstream Operating, LLC (Moda) for US$3.0 billion of cash plus contingent consideration dependent on performance of the assets (the Acquisition). Moda owns and operates a vertically integrated crude export system of pipeline and storage assets on the US Gulf Coast, including the Ingleside Energy Center (IEC) located near Corpus Christi, Texas. IEC, North America's largest crude export terminal, controls 15.6 million barrels of storage and 1.6 million bpd of export capacity and volumes are underpinned by 925 thousand barrels per day (kbpd) of long term take-or-pay vessel loading contracts and 15.3 million barrels of long-term storage contracts. The Acquisition significantly advances our US Gulf Coast export strategy and connectivity to low-cost and long-lived reserves in the Permian and Eagle Ford basins.

RENEWABLE ENERGY PARTNERSHIP

On September 28, 2021, we announced a partnership with Vanguard Renewables (Vanguard) to design and build up to eight anaerobic digesters, used to convert food and farm waste into renewable natural gas (RNG), across the US. Vanguard will build and operate the digesters and we will invest approximately $100 million in RNG upgrading equipment to convert the RNG into pipeline quality gas. We will also provide transportation and marketing services to market that gas to US customers.

COVID-19 PANDEMIC

In 2020, the COVID-19 pandemic had a significant negative impact on crude oil market fundamentals which resulted in elevated risks to our business and to that of our customers. Global crude oil demand experienced an unprecedented drop in mid-2020, as the economy slowed and personal mobility decreased due to government imposed restrictions. This, in turn, led to a decrease in crude oil throughput on our liquids pipelines systems as refinery runs decreased across North America.

During 2021, there has since been a substantial recovery in crude oil demand as vaccination rates rise and economies continue to reopen following successive COVID-19 waves. Crude oil prices have risen significantly since the 2020 collapse as the recovery in global demand has outpaced the return of crude oil supply. As at the third quarter of 2021, our Mainline System has remained substantially full, however, we continue to monitor the fundamental landscape for emerging supply and demand risks.

We continue to proactively monitor and follow COVID-19 guidance and orders from governments and public health authorities, which vary by jurisdiction, and to employ workplace safety processes and procedures including a COVID-19 vaccine and testing policy. We continue to implement a phased return to workplace plan in certain of our office locations where public health restrictions allow.

Despite ongoing uncertainty as to the duration and impact of the pandemic and corresponding public health measures, our business continuity plans are designed to enable us to manage operational developments related to COVID-19 as they unfold, including those related to construction and integrity projects. We provide an essential service across North America. Our customers, and the communities where we operate, depend on us to safely and reliably provide the energy they need.

UNITED STATES LINE 3 REPLACEMENT PROGRAM

Construction of the US portion of the Line 3 Replacement Program in Minnesota is now complete and was placed into service on October 1, 2021. This step marks the completion of the Line 3 Replacement (L3R) Program. The L3R Program was a replacement of 1,660 kilometers of pipeline from Hardisty, AB to Superior, WI and restores Line 3 to its historic capacity of 760 kbpd from western Canada into Superior, WI. With new state-of-the-art, thicker-walled pipe, its completion provides a safe, reliable supply of North American crude oil to US and Canadian refineries.

CANADIAN MAINLINE SYSTEM CONTRACTING

On December 19, 2019, we submitted an application to the Canada Energy Regulator (CER) to implement contracting on our Canadian Mainline System. The application for contracted and uncommitted service included the associated terms, conditions and tolls of each service, which would be offered in an open season following approval by the CER.

Procedural steps with all participants before the CER are now complete. A decision by the CER is expected in late November 2021.

In accordance with the terms of the Competitive Tolling Settlement (CTS), which expired on June 30, 2021, the tolls in place on June 30, 2021 will continue on an interim basis, subject to finalization and adjustment applicable to the interim period, if any.

GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS

Texas Eastern Transmission

Texas Eastern Transmission, LP (Texas Eastern) filed a rate case on July 30, 2021. On August 31, 2021 the Federal Energy Regulatory Commission (FERC) issued an order rejecting the July 30, 2021 filing in its entirety noting the proposed US federal income tax rate in the filing was not known and measurable. Additionally, the August 31, 2021 order directed Texas Eastern to show cause that its reservation charge crediting process is in accordance with FERC policy. On September 30, 2021 Texas Eastern responded to the show cause directive and filed a new rate case using the current US federal income tax rate. On October 29, 2021, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures for the rate case filed on September 30, 2021. Texas Eastern expects settlement discussions with shippers will commence in the first quarter of 2022.

East Tennessee

East Tennessee Natural Gas, LLC (ETNG) filed a rate case in the second quarter of 2020 and an agreement in principle was reached with shippers in April 2021. A Stipulation and Agreement was filed on May 21, 2021, approved by the FERC on September 10, 2021, and was effective on November 1, 2021.

Maritimes & Northeast Pipeline

The US portion of Maritimes & Northeast Pipeline filed a rate case in the second quarter of 2020 and an agreement in principle was reached with shippers in December 2020. A Stipulation and Agreement was filed on February 21, 2021, approved by the FERC on April 30, 2021, and was effective on June 1, 2021.

Alliance Pipeline

The US portion of Alliance Pipeline filed a rate case in the second quarter of 2020 and an agreement in principle was reached with shippers in January 2021. A Stipulation and Agreement was filed on March 31, 2021, approved by the FERC on July 15, 2021, and was effective on September 1, 2021.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

2021 Rate Application

Enbridge Gas Inc. (Enbridge Gas) rate applications are filed in two phases. As part of an Ontario Energy Board (OEB) Decision and Order issued in November 2020, Phase 1 of the application for 2021 rates (the 2021 Application), exclusive of 2021 capital investment funding requested through the incremental capital module (ICM) mechanism, was approved on an interim basis effective January 1, 2021. Through a subsequent OEB Rate Order issued on June 3, 2021, Phase 2 of the 2021 Application, inclusive of funding for $124 million of Enbridge Gas requested 2021 ICM amounts, was approved effective July 1, 2021, and interim rates in effect for 2021 were made final. The 2021 Application, which represented the third year of a five-year term, was filed in accordance with the parameters of the Enbridge Gas OEB approved Price Cap Incentive Regulation (IR) rate setting mechanism.

2022 Rate Application

On June 30, 2021, Enbridge Gas filed Phase 1 of the application with the OEB for the setting of rates for 2022 (the 2022 Application). The 2022 Application was filed in accordance with the parameters of the Enbridge Gas OEB approved Price Cap IR rate setting mechanism and represents the fourth year of a five-year term. On October 28, 2021, the OEB approved a Phase 1 Settlement Proposal and Interim Rate Order effective January 1, 2022. Phase 2 of the 2022 Application addressing ICM funding requirements was filed on October 15, 2021.

SOLAR SELF-POWER PROJECTS

Alberta Solar One

In March 2021, we commenced commercial operations on our first self-powering solar generation facility in Alberta. The 10.5-megawatts (MW) solar project, located near Burdett, Alberta, will supply a portion of our Canadian Mainline power requirements with solar energy.

Heidlersburg Solar Project

On May 15, 2021, a 2.5 MW self-power facility, located at the Heidlersburg compressor station on the Texas Eastern system, was placed into service.

An additional four projects along our US Mainline and Flanagan South liquids systems, with a combined 35 MW of generation, are in pre-construction and expected to enter service in late 2022, further lowering our emissions.

FINANCING UPDATE

On February 10, 2021, we entered into a three year, revolving, extendible, sustainability-linked credit facility for $1.0 billion with a syndicate of lenders. We concurrently cancelled a one-year, revolving, syndicated credit facility for $3.0 billion, ahead of its scheduled March 2021 maturity.

On February 19, 2021, we closed our inaugural US$500 million two-year Secured Overnight Financing Rate (SOFR) based Floating Rate Note offering. Proceeds of this offering were used for repayment of two United States dollars (USD) term loans for the equivalent aggregate amount which matured on February 25, 2021.

On May 12, 2021, Enbridge Pipelines Inc. closed an $800 million dual-tranche medium-term notes (MTN) offering in the Canadian public debt market, split evenly between 10 and 30-year tranches. Proceeds of this offering were used to repay short-term debt, for capital expenditures and for general corporate purposes.

On June 28, 2021, we closed a dual-tranche debt offering consisting of an inaugural US$1.0 billion 12-year Sustainability-Linked senior note issuance and a US$500 million 30-year senior note issuance. The Sustainability-Linked senior notes follow the guidance of our Sustainability-Linked Bond Framework published on June 17, 2021, by incorporating greenhouse gas emissions intensity reduction and workforce diversity sustainability performance targets (SPTs) into the financing terms. If the SPTs are not met, the interest rate on the Sustainability-Linked senior notes will increase, helping to align our funding strategies with our environmental, social and governance ambitions. The proceeds from the issuance were used to repay existing indebtedness, partially fund capital projects and for other general corporate purposes.

On September 2, 2021, Texas Eastern completed a private placement of US$400 million 10-year senior notes, payable semi-annually maturing on September 2, 2031.

On September 15, 2021, Enbridge Gas closed a $900 million dual-tranche MTN offering in the Canadian debt capital markets, consisting of a $475 million 10-year tranche and a $425 million 30-year tranche, payable semi-annually, due September 15, 2031 and 2051, respectively.

On September 21, 2021, we closed a dual-tranche debt offering consisting of an inaugural $1.1 billion Canadian 12-year Sustainability-Linked MTN issuance and a $400 million 30-year MTN issuance. The Sustainability-Linked MTN issuance follows the Sustainability-Linked Bond Framework by incorporating greenhouse gas emissions intensity reduction, workforce diversity and representation of women on the Board of Directors SPTs into the financing terms. If the SPTs are not met, the interest rate on the Sustainability-Linked senior notes will increase, helping to further align our funding strategies with our environmental, social and governance ambitions. Proceeds of this offering have been used for repayment of short-term debt, capital expenditures and for general corporate purposes.

On October 4, 2021, we closed a three tranche offering of aggregate US$1.5 billion senior notes consisting of US$500 million 2-year notes, US$500 million 5-year notes, and a US$500 million re-opening of the 2051 notes issued in June 2021. Each tranche is payable semi-annually in arrears and matures on October 4, 2023, October 4, 2026, and August 1, 2051, respectively.

Through these financing activities, we have now completed our 2021 financing plan requirements. In combination with the financing activities executed in 2020, the 2021 financing activity is expected to provide significant liquidity and to enable us to fund our current portfolio of capital projects without requiring access to the capital markets for the next 12 months if market access is restricted or pricing is unattractive. Refer to Liquidity and Capital Resources.

Credit Rating Action

On June 1, 2021, Moody's Investors Service (Moody's) upgraded the credit ratings of Enbridge Inc. including our senior unsecured and issuer ratings to Baa1 from Baa2. Moody's also upgraded the credit ratings of our subsidiaries: Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Limited Partnership (EELP), Spectra Energy Partners, LP (SEP) and Texas Eastern. The outlooks of all five entities are stable.

ASSET MONETIZATION

Éolien Maritime France SAS

On March 18, 2021, we sold 49% of an entity that holds our 50% interest in Éolien Maritime France SAS (EMF) to the Canada Pension Plan Investment Board (CPP Investments). CPP Investments will fund their 49% share of all ongoing future development capital. Through our investment in EMF, we own equity interests in three French offshore wind projects, including Saint-Nazaire (25.5%), Fécamp (17.9%) and Calvados (21.7%). The Calvados Offshore Wind Project reached a positive final investment decision in February 2021 and all three projects are now considered commercially secured and are under construction.

Noverco Inc.

On June 7, 2021, we entered into a definitive agreement to sell our 38.9% non-operating minority ownership interest in Noverco Inc. (Noverco) to Trencap L.P. for $1.1 billion in cash, subject to purchase price adjustments. Closing of the transaction is expected to occur by late 2021 or early 2022 and is subject to customary closing conditions.

RESULTS OF OPERATIONS


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization
Liquids Pipelines	1,673	2,090	5,756	5,280
Gas Transmission and Midstream	884	334	2,725	230
Gas Distribution and Storage	282	298	1,374	1,285
Renewable Power Generation	91	93	362	376
Energy Services	(204)	(34)	(379)	(12)
Eliminations and Other	(121)	207	191	(498)
Earnings before interest, income taxes and depreciation and amortization	2,605	2,988	10,029	6,661
Depreciation and amortization	(944)	(935)	(2,805)	(2,766)
Interest expense	(648)	(718)	(1,923)	(2,105)
Income tax expense	(199)	(231)	(952)	(273)
Earnings attributable to noncontrolling interests	(34)	(20)	(93)	(25)
Preference share dividends	(98)	(94)	(280)	(284)
Earnings attributable to common shareholders	682	990	3,976	1,208
Earnings per common share attributable to common shareholders	0.34	0.49	1.97	0.60
Diluted earnings per common share attributable to common shareholders	0.34	0.49	1.96	0.60

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended September 30, 2021, compared with the three months ended September 30, 2020

Earnings attributable to common shareholders were negatively impacted by $531 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, unrealized derivative fair value loss of $436 million ($332 million after-tax) in 2021, compared with a gain of $569 million ($427 million after-tax) in 2020, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;

•a non-cash, unrealized loss of $88 million ($67 million after-tax) in 2021, compared with an unrealized gain of $73 million ($55 million after-tax) in 2020, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices; and

•an impairment loss of $111 million ($83 million after-tax) in 2021 to our investment in the PennEast pipeline project after a decision by project partners to cease development, compared to a combined impairment loss of $615 million ($452 million after-tax) in 2020 to our investments in Southeast Supply Header, L.L.C. (SESH) and Steckman Ridge, LP (Steckman), which partially offset the factors above.

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

After taking into consideration the factors above, the remaining $223 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:

•stronger contributions from our Liquids Pipeline segment this year as COVID-19 restrictions lift and demand continues to recover;

•increased earnings from the Atlantic Bridge Phase III project in our Gas Transmission and Midstream segment which commenced service in January 2021; and

•lower interest expense primarily due to lower rates.

The positive factors above were partially offset by the net unfavorable effect of translating US dollar EBITDA to Canadian dollars at a lower average exchange rate in 2021 compared to the same period in 2020.

Nine months ended September 30, 2021, compared with the nine months ended September 30, 2020

Earnings attributable to common shareholders were positively impacted by $2.4 billion due to certain unusual, infrequent or other non-operating factors, primarily explained by the following factors:

•a non-cash, unrealized derivative fair value gain of $85 million ($65 million after-tax) in 2021, compared with a loss of $201 million ($151 million after-tax) in 2020, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks, partially offset by a non-cash, unrealized loss of $102 million ($78 million after-tax) in 2021, compared with an unrealized gain of $24 million ($18 million after-tax) in 2020 reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions and the exposure to movements in commodity prices;

•employee severance, transition and transformation costs of $106 million ($82 million after-tax) in 2021, compared to $303 million ($229 million after-tax) in 2020 primarily related to our voluntary workforce reduction program offered in the second quarter of 2020;

•the absence in 2021 of a non-cash impairment to the carrying value of our investment in DCP Midstream, LLC (DCP Midstream) of $1.7 billion ($1.3 billion after-tax) recognized in 2020;

•the absence in 2021 of a loss of $324 million ($244 million after-tax) resulting from asset and goodwill impairment losses within DCP Midstream recognized in 2020; and

•the absence in 2021 of a loss of $159 million ($119 million after-tax) in 2020 resulting from the Texas Eastern rate case settlement that re-established the Excess Accumulated Deferred Income Tax (EDIT) regulated liability that was previously eliminated in December 2018.

After taking into consideration the factors above, the remaining $413 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:

•stronger contributions from our Liquids Pipelines segment due to increased volumes and a higher International Joint Tariff (IJT) Benchmark Toll;

•increased earnings from our Gas Distribution and Storage segment due to increased rates and customer base;

•increased earnings from the Atlantic Bridge Phase III project in our Gas Transmission and Midstream segment which commenced service in January 2021; and

•lower interest expense primarily due to lower rates.

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

•decreased earnings from our Energy Services segment due to the significant compression of location and quality differentials in certain markets, fewer storage opportunities due to market backwardation, adverse impacts from the major winter storm experienced across the US Midwest during February 2021 and fewer opportunities to achieve profitable transportation margins on facilities in which Energy Services holds capacity obligations;

•the net unfavorable effect of translating US dollar EBITDA to Canadian dollars at a lower average exchange rate in 2021 compared to the same period in 2020; and

•the absence in 2021 of the recognition of revenue in 2020 from a rate settlement on Texas Eastern, partially offset by increased revenue due to the absence of pressure restrictions that existed on the Texas Eastern system in 2020.

BUSINESS SEGMENTS

LIQUIDS PIPELINES


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	1,673	2,090	5,756	5,280

Three months ended September 30, 2021, compared with the three months ended September 30, 2020

EBITDA was negatively impacted by $583 million due to non-operating factors, primarily explained by non-cash, unrealized loss of $222 million in 2021, compared with unrealized gains of $360 million in 2020, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks.

After taking into consideration the factors above, the remaining $166 million increase is primarily explained by the following significant business factors:

•higher Mainline System ex-Gretna throughput of 2.7 million barrels per day (mmbpd) in 2021 compared with 2.6 mmbpd in 2020 driven by the rebounding demand for crude oil and related products as economies continue to recover from the impacts of the COVID-19 pandemic;

•higher equity income from our investment in the Seaway Crude Pipeline System driven by increased volumes;

•higher throughput on our Wood Buffalo Extension and Waupisoo Pipeline as production in the Athabasca Basin continues to recover; and

•a higher foreign exchange hedge rate used to lock-in US dollar denominated Canadian Mainline revenue.

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

•lower throughput on our Flanagan South Pipeline (Flanagan South) driven by robust PADD II refinery demand resulting in less volumes available to move towards the US Gulf Coast; and

•the net unfavorable effect of translating US dollar EBITDA to Canadian dollars at a lower average exchange rate in 2021 compared with 2020.

Nine months ended September 30, 2021, compared with the nine months ended September 30, 2020

EBITDA was positively impacted by $248 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•non-cash, unrealized gains of $84 million in 2021, compared with unrealized losses of $90 million in 2020, 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

•a receipt of a property tax settlement of $57 million related to the resolution of Minnesota property tax appeals for 2012-2018.

After taking into consideration the factors above, the remaining $228 million increase is primarily explained by the following significant business factors:

•higher Mainline system ex-Gretna average throughput of 2.7 mmbpd in 2021 as compared to 2.6 mmbpd in 2020 driven by the rebounding demand for crude oil and related products as economies continue to recover from the impacts of the COVID-19 pandemic;

•a higher average IJT Benchmark Toll on our Mainline System of US$4.27 in 2021, compared with US$4.23 in 2020;

•a higher foreign exchange hedge rate used to lock-in US dollar denominated Canadian Mainline revenue;

•an increased CTS surcharge of US$0.11 per barrel in 2021, compared to US$0.07 per barrel in 2020;

•higher equity income from our investment in the Seaway Crude Pipeline System driven by increased volumes; and

•higher throughput on our Wood Buffalo Expansion and Waupisoo Pipeline as production in the Athabasca Basin continues to recover.

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

•lower throughput on Flanagan South as a result of robust refinery demand in PADD II resulting in less volumes available to move towards the US Gulf Coast; and

•the net unfavorable effect of translating US dollar EBITDA to Canadian dollars at a lower average exchange rate in 2021, compared with the same period in 2020.

GAS TRANSMISSION AND MIDSTREAM


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	884	334	2,725	230

Three months ended September 30, 2021, compared with the three months ended September 30, 2020

EBITDA was positively impacted by $509 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following factors:

•an impairment loss of $111 million in 2021 to our investment in the PennEast pipeline project after a decision by project partners to cease development, compared to a combined impairment loss of $615 million in 2020 to our investments in SESH and Steckman; and

•a non-cash, equity earnings decline of $38 million in 2021, compared with a decline of $5 million in 2020 relating to changes in the mark-to-market value of derivative financial instruments of our equity method investee, DCP Midstream, which partially offset the positive factors above.

After taking into consideration the factors above, the remaining $41 million increase is primarily explained by the following significant business factors:

•higher commodity prices benefiting our Aux Sable and DCP joint ventures;

•increased revenue due to the absence of pressure restrictions that existed on the Texas Eastern system in 2020;

•contributions from the Atlantic Bridge Phase III project after service commenced in January 2021; and

•the net unfavorable effect of translating US dollar EBITDA to Canadian dollars at a lower average exchange rate in 2021, compared to the same period in 2020, which partially offset the positive factors above.

Nine months ended September 30, 2021, compared with the nine months ended September 30, 2020

EBITDA was positively impacted by $2.6 billion due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:

•the absence in 2021 of a non-cash impairment to the carrying value of our investment in DCP Midstream of $1.7 billion recognized in 2020;

•the absence in 2021 of a loss of $324 million resulting from asset and goodwill impairment losses within DCP Midstream recognized in 2020;

•the absence in 2021 of a loss of $159 million in 2020 resulting from the Texas Eastern rate case settlement that re-established the EDIT regulated liability that was previously eliminated in December 2018; and

•a decline in equity earnings of $104 million in 2021, compared with a positive impact of $26 million in 2020 relating to changes in the mark-to-market value of derivative financial instruments of our equity method investee, DCP Midstream, which partially offset the positive factors above.

After taking into consideration the factors above, the remaining $89 million decrease is primarily explained by the following significant business factors:

•the net unfavorable effect of translating US dollar EBITDA at a lower Canadian to US dollar average exchange rate in 2021, compared to the same period in 2020; and

•the absence in 2021 of the recognition of revenue in 2020 that related to the settlement of interim rates collected from shippers on Texas Eastern, retroactive to June 1, 2019.

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

•higher commodity prices benefiting our Aux Sable and DCP Midstream joint ventures;

•increased revenue due to the absence of pressure restrictions that existed on the Texas Eastern system in 2020; and

•contributions from the Atlantic Bridge Phase III project after service commenced in January 2021.

GAS DISTRIBUTION AND STORAGE


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	282	298	1,374	1,285

Three months ended September 30, 2021, compared with the three months ended September 30, 2020

EBITDA was negatively impacted by $16 million primarily explained by higher operating and administrative expense largely driven by the timing in spend, partially offset by higher distribution charges resulting from increases in rates and customer base.

Nine months ended September 30, 2021, compared with the nine months ended September 30, 2020

EBITDA was positively impacted by $16 million due to certain unusual, infrequent and other non-operating factors, primarily explained by a non-cash, unrealized gain of $12 million in 2021, compared with an unrealized gain of $2 million in 2020 arising from the change in the mark-to-market value of Noverco's derivative financial instruments and COVID-19 costs of $3 million in 2021 compared with $8 million in 2020.

After taking into consideration the factors above, the remaining $73 million increase is primarily explained by the following business factors:

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

•higher storage revenue, mainly relating to storage optimization activities.

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

•higher operating and administrative costs largely related to operational, pipeline integrity and safety costs; and

•when compared with the normal weather forecast embedded in rates, weather was warmer in both 2021 and 2020, negatively impacting EBITDA in both years. Warmer than normal weather in 2021 negatively impacted 2021 EBITDA by approximately $24 million while the warmer than normal weather in 2020 negatively impacted 2020 EBITDA by approximately $18 million.

RENEWABLE POWER GENERATION


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	91	93	362	376

Three months ended September 30, 2021, compared with the three months ended September 30, 2020

EBITDA was lower by $2 million primarily due to lower wind resources at Canadian wind facilities, which was partially offset by lower mechanical repair costs at certain US wind facilities.

Nine months ended September 30, 2021, compared with the nine months ended September 30, 2020

EBITDA was negatively impacted by $9 million due to certain unusual, infrequent and other non-operating factors, primarily explained by an absence in 2021 of a gain of $13 million related to the sale of the Montana Alberta Tie Line transmission net assets in 2020.

After taking into consideration the factor above, the remaining $5 million decrease is primarily explained by the following business factors:

• weaker wind resources at Canadian wind facilities and the effects from the winter storm in Texas during February 2021; and

• the absence in 2021 of reimbursements received in 2020 at certain Canadian wind facilities resulting from a change in operator.

The business factors above were partially offset by the sale of a 49% interest of an entity that holds our 50% interest in EMF.

ENERGY SERVICES


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars)
Loss before interest, income taxes and depreciation and amortization	(204)	(34)	(379)	(12)

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 September 30, 2021, compared with the three months ended September 30, 2020

EBITDA was negatively impacted by $164 million due to certain non-operating factors, primarily explained by a non-cash, unrealized loss of $88 million in 2021, compared with an unrealized gain of $73 million in 2020, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices.

After taking into consideration the factors above, the remaining $6 million decrease is primarily explained by the significant compression of location and quality differentials in certain markets and limited storage opportunities in 2021 due to market backwardation compared to favorable storage opportunities in 2020.

Nine months ended September 30, 2021, compared with the nine months ended September 30, 2020

EBITDA was negatively impacted by $127 million due to certain non-operating factors, explained primarily by a non-cash, unrealized loss of $102 million in 2021, compared with an unrealized gain of $24 million in 2020, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices.

After taking into consideration the factors above, the remaining $240 million decrease is primarily explained by the following significant factors:

•significant compression of location and quality differentials in certain markets;

•limited storage opportunities in 2021 due to market backwardation compared to favorable storage opportunities in 2020;

•adverse impacts from the major winter storm experienced across the US Midwest during February 2021; and

•fewer opportunities to achieve profitable transportation margins on facilities in which Energy Services holds capacity obligations.

ELIMINATIONS AND OTHER


	Three months ended September 30,		Nine months ended September 30,
	2021	2020	2021	2020
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	(121)	207	191	(498)

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

Three months ended September 30, 2021, compared with the three months ended September 30, 2020

EBITDA was negatively impacted by $422 million due to certain non-operating factors, primarily explained by an unrealized loss of $214 million in 2021, compared with an unrealized gain of $198 million in 2020, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk.

After taking into consideration the non-operating factors above, the remaining $94 million increase is primarily explained by realized gains related to settlements under our enterprise-wide foreign exchange risk management program which substantially offset the foreign currency exposures realized within our business segments' results.

Nine months ended September 30, 2021, compared with the nine months ended September 30, 2020

EBITDA was positively impacted by $414 million due to certain unusual, infrequent and other non-operating factors, primarily explained by the following:

•a non-cash, unrealized loss of $17 million in 2021, compared with an unrealized loss of $115 million in 2020, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;

•employee severance, transition and transformation costs of $60 million in 2021, compared to $259 million in 2020;

•the absence in 2021 of a loss of $74 million in 2020 relating to the recognition of a corporate guarantee obligation; and

•the absence in 2021 of a loss of $43 million in 2020 relating to the write-down of certain investments in emerging energy and other technologies.

After taking into consideration the non-operating factors above, the remaining $275 million increase is primarily explained by realized gains related to settlements under our enterprise-wide foreign exchange risk management program which substantially offset the foreign currency exposures realized within our business segments' results.

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

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

Enbridge's Ownership Interest

Estimated
Capital

Cost1

Expenditures
to Date2

Status2

Expected
In-Service
Date

(Canadian dollars, unless stated otherwise)

LIQUIDS PIPELINES

US Line 3 Replacement Program

100

US$4.0 billion

Complete

In-service

Southern Access Expansion

100

US$0.5 billion

Complete

In-service

Other - US

100

US$0.1 billion

Complete

In-service

GAS TRANSMISSION AND MIDSTREAM

T-South Reliability & Expansion Program3

100

$1.0 billion

$0.9 billion

Under construction

Q4 - 2021

Spruce Ridge Project3

100

$0.5 billion

$0.4 billion

Under construction

Q4 - 2021

Other - US4

Various

US$0.6 billion

US$0.4 billion

Various stages

2021 - 2023

GAS DISTRIBUTION AND STORAGE

System Enhancement Projects

100

$0.4 billion

$0.1 billion

Various stages

2021 - 2023

Storage Enhancements

100

$0.1 billion

No significant expenditures to date

Under construction

2021 - 2022

Natural Gas Expansion Program5

100

$0.1 billion

No significant expenditures to date

Pre-construction

2022 - 2027

RENEWABLE POWER GENERATION

10.

East-West Tie Line

25.0

$0.2 billion

Under construction

1H - 2022

11.

Solar Self-Power Projects6

100

US$0.1 billion

No significant expenditures to date

Pre-construction

2H - 2022

12.

Saint-Nazaire France Offshore Wind Project7

25.5

$0.9 billion

$0.4 billion

Under construction

2H - 2022

(€0.6 billion)

(€0.3 billion)

13.

Fécamp Offshore Wind Project8

17.9

$0.7 billion

$0.2 billion

Under construction

2023

(€0.5 billion)

(€0.1 billion)

14.

Calvados Offshore Wind Project9

21.7

$0.9 billion

$0.1 billion

Under construction

2024

(€0.6 billion)

(€0.1 billion)

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 and status of the project are determined as at September 30, 2021.

3 The T-South Reliability & Expansion Program and the Spruce Ridge Project commenced service on November 1, 2021.

4 Includes the US$0.1 billion Texas Eastern Middlesex Extension placed into service in the third quarter of 2021.

5 Represents Phase 2 of the Natural Gas Expansion Program (the Program) and the estimated capital cost is presented net of 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.

6 Self-Power Projects consists of four solar projects along our US Mainline and Flanagan South liquids systems. All four will be located at existing pump stations—Adams (6.9 MW), Vesper (8.8 MW) and Portage (8 MW) in central Wisconsin, and Flanagan (10 MW) in north-central Illinois.

7 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments that closed in the first quarter of 2021. Our equity contribution is $0.15 billion, with the remainder of the project financed through non-recourse project level debt.

8 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments that closed in the first quarter of 2021. Our equity contribution is $0.1 billion, with the remainder of the project financed through non-recourse project level debt.

9 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments that closed in the first quarter of 2021. Our equity contribution is $0.1 billion, with the remainder of the project financed through non-recourse project level debt.

A full description of each of our projects is provided in our annual report on Form 10-K for the year ended December 31, 2020. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.

GAS TRANSMISSION AND MIDSTREAM

•PennEast Pipeline Project - an approximately 190-kilometer pipeline that would run from Pennsylvania to New Jersey. It was designed to deliver approximately 1.1 billion cubic feet per day (bcf/day) of additional natural gas pipeline capacity to serve local distribution companies and power generators in Southeastern Pennsylvania and New Jersey. On September 27, 2021, PennEast Pipeline Company, L.L.C. (PennEast) announced that further development of the project was no longer viable. Accordingly, PennEast has ceased further development of the project and our investment in the project has been impaired. For additional disclosure on the PennEast impairment, refer to Part I. Item 1 - Financial Statements - Note 8. Impairment of Equity Investments.

GAS DISTRIBUTION AND STORAGE

•System Enhancement Projects – Consists of the London Line Replacement Project, the Lake Shore KOL Replacement Project and St. Laurent Ottawa North Replacement Project. The London Line Replacement Project will replace the two current pipelines known collectively as the London Line and includes the construction of approximately 90.5-kilometers of natural gas pipeline and ancillary facilities in southern Ontario. The project is expected to be placed into service in the fourth quarter of 2021. The Lake Shore Kipling Oshawa Loop (KOL) Replacement Project is a replacement of approximately 4.5-kilometers of natural gas pipeline and ancillary facilities of the Cherry to Bathurst segment of the KOL along Lake Shore Boulevard in the City of Toronto. The project is expected to be placed into service in the second half of 2022. The St. Laurent Ottawa North Replacement Project is a replacement of approximately 16-kilometers of natural gas pipeline in the City of Ottawa. The project will be completed in multiple phases over multiple years with the first two phases already complete. Phases 3 and 4 represent approximately 11.4-kilometers of pipeline and are expected to be in service in late 2022 and late 2023, respectively.

•Natural Gas Expansion Program – The Program was created under Ontario's Access to Natural Gas Act, 2018 to help expand access to natural gas to areas of Ontario that currently do not have access to the natural gas distribution system. Funding assistance was approved for Enbridge Gas under Phase 1 of the Program. To date, Enbridge Gas has initiated five of the projects approved for funding under the Program, with continued progress through 2021. On June 8, 2021, the Government of Ontario approved additional funding for projects under Phase 2 of the Program, under which Enbridge Gas will be provided up to $214 million in funding assistance to deliver 27 expansion projects throughout Ontario.

RENEWABLE POWER GENERATION

•Solar Self-Power Projects – four solar projects co-located at existing pump stations with behind-the-meter interconnections. The projects are expected to support our emissions reduction goals and are expected to be placed into service in the second half of 2022.

•Calvados Offshore Wind Project – an offshore wind project located off the northwest coast of France that is expected to generate approximately 448 MW. Project revenues are underpinned by a 20-year fixed price power purchase agreement.

During the first quarter of 2021, we sold 49% of an entity that holds our 50% interest in EMF to CPP Investments. EMF holds equity interests in the Fécamp Offshore Wind Project, the Saint-Nazaire France Offshore Wind Project and the Calvados Offshore Wind Project. CPP Investments will fund their 49% share of all ongoing future development capital.

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT

We have announced the following projects, but they have not yet met our criteria to be classified as commercially secured:

GAS TRANSMISSION AND MIDSTREAM

•Rio Bravo Pipeline – The Rio Bravo Pipeline is designed to transport up to 4.5 bcf/day of natural gas from the Agua Dulce supply area to NextDecade's Rio Grande LNG export facility in the Port of Brownsville, Texas. We have acquired the Rio Bravo Pipeline development project from NextDecade. In addition, we have executed a precedent agreement with NextDecade under which we will provide firm transportation capacity on the Rio Bravo Pipeline to NextDecade's Rio Grande LNG export facility for a term of at least 20 years. Construction of the pipeline will be subject to the Rio Grande LNG export facility reaching a final investment decision.

•Ridgeline Expansion Project Opportunity – We are working on a potential expansion of the ETNG system which would provide additional natural gas for the Tennessee Valley Authority (TVA) to support the replacement of an existing coal-fired power plant as it continues to transition its generation mix towards lower-carbon fuels. The TVA environmental review scoping process has begun for this proposed plant; TVA published a Notice of Intent on the Federal Register on June 15, 2021 to initiate their review process. Several options to replace the retiring coal-fired generation would be assessed in TVA’s Environmental Impact Statement (EIS). Should the onsite natural gas option of building a combined cycle plant be selected through TVA’s review, we would deliver on the required expansion of the East Tennessee system. ETNG’s proposed project would consist of the installation of additional pipeline primarily along the ETNG system, the installation of one electric-powered compressor station and solar facilities behind the meter, as well as other design features all contributing to minimizing greenhouse gas emissions. Should TVA’s environmental assessment determine that the natural gas solution of building an onsite combined cycle plant is the optimal supply source, and pending the approval and receipt of all necessary permits, construction of the pipeline would begin in 2025 with a target in-service date of fall 2026.

•Valley Crossing Expansion Project - We are pursuing an expansion of the existing Valley Crossing Pipeline to supply Texas LNG Brownsville, LLC with feed gas for their proposed liquefaction and export facility in Port of Brownsville, Texas.

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

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 and pay common and preference share dividends. We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.

Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives. Our current financing plan does not include any issuances of additional common equity.

CAPITAL MARKET ACCESS

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

Credit Facilities and Liquidity

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities as at September 30, 2021:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2022-2026	9,169	7,378	1,791
Enbridge (U.S.) Inc.	2023-2026	6,968	2,515	4,453
Enbridge Pipelines Inc.	2023	3,000	469	2,531
Enbridge Gas Inc.	2023	2,000	1,205	795
Total committed credit facilities		21,137	11,567	9,570

1Maturity date is inclusive of the one-year term out option for certain credit facilities.

2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

On February 25, 2021, two term loans with an aggregate total of US$500 million were repaid with proceeds from a floating rate notes issuance.

Our net available liquidity of $10.0 billion as at September 30, 2021, was inclusive of $451 million of unrestricted cash and cash equivalents as reported in the Consolidated Statements of Financial Position.

LONG-TERM DEBT ISSUANCES

During the nine months ended September 30, 2021, we completed the following long-term debt issuances totaling US$2.4 billion and $3.2 billion:


Company	Issue Date		Principal Amount
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
	February 2021	Floating rate notes due February 20231	US$500
	June 2021	2.50% Sustainability-Linked senior notes due August 2033	US$1,000
	June 2021	3.40% senior notes due August 2051	US$500
	September 2021	3.10% Sustainability-Linked medium-term notes due September 2033	$1,100
	September 2021	4.10% medium-term notes due September 2051	$400
Enbridge Gas Inc.
	September 2021	2.35% medium-term notes due September 2031	$475
	September 2021	3.20% medium-term notes due September 2051	$425
Enbridge Pipelines Inc.
	May 2021	2.82% medium-term notes due May 2031	$400
	May 2021	4.20% medium-term notes due May 2051	$400
Spectra Energy Partners, LP
	September 2021	2.50% senior notes due September 20312	US$400

1Notes mature in two years and carry an interest rate set to equal SOFR plus a margin of 40 basis points.

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

LONG-TERM DEBT REPAYMENTS

During the nine months ended September 30, 2021, we completed the following long-term debt repayments totaling $808 million and US$880 million:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars unless otherwise stated)

Enbridge Inc.

February 2021

4.26% medium-term notes

$200

March 2021

3.16% medium-term notes

$400

Enbridge Energy Partners, L.P.

June 2021

4.20% senior notes

US$600

Enbridge Gas Inc.

May 2021

2.76% medium-term notes

$200

Enbridge Pipelines (Southern Lights) L.L.C.

June 2021

3.98% senior notes

US$30

Enbridge Southern Lights LP

June 2021

4.01% senior notes

Spectra Energy Partners, LP

March 2021

4.60% senior notes

US$250

Strong internal cash flow, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to EBITDA.

On June 1, 2021, Moody’s upgraded the credit ratings of Enbridge Inc. including our senior unsecured and issuer ratings to Baa1 from Baa2. Moody's also upgraded the credit ratings of our subsidiaries: EEP, EELP, SEP and Texas Eastern. The outlooks of all five entities are stable.

There are no material restrictions on our cash. Total restricted cash of $64 million, as reported on the Consolidated Statements of Financial Position, primarily includes cash collateral, future pipeline abandonment costs collected and held in trust, amounts received in respect of specific shipper commitments and capital projects. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative uses by us.

Excluding current maturities of long-term debt, we had a negative working capital position as at September 30, 2021. The major contributing factor to the negative working capital position was the ongoing funding of our growth capital program.

To address this negative working capital position, we maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due.

SOURCES AND USES OF CASH


	Nine months ended September 30,
		2021	2020
(millions of Canadian dollars)
Operating activities		6,954	7,527
Investing activities		(5,495)	(3,644)
Financing activities		(1,422)	(3,845)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		(12)	(22)
Net increase in cash and cash equivalents and restricted cash		25	16

Significant sources and uses of cash for the nine months ended September 30, 2021 and 2020 are summarized below:

Operating Activities

The decrease in cash provided by operating activities was primarily attributable to changes in operating assets and liabilities, which were partially offset by an increase in earnings. Our operating assets and liabilities fluctuate in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within our business segments, the timing of tax payments, as well as timing of cash receipts and payments generally.

Investing Activities

•The increase in cash used in investing activities was primarily attributable to higher capital expenditures during the nine months ended September 30, 2021 compared to the same period in 2020. We are continuing with the execution of our growth capital program which is further described in Growth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements. In addition, there were higher proceeds received from dispositions in 2020, as compared to proceeds received from the disposition of 49% of our interest in EMF to CPP Investments in 2021.

•The above factors were partially offset by the absence of contributions to our Gray Oak Holdings LLC equity investment during the nine months ended September 30, 2021 compared to the same period in 2020, due to Gray Oak Pipeline being placed into service in March 2020.

Financing Activities

•The decrease in cash used in financing activities was primarily attributable to a decrease in repayments and higher issuances of long-term debt in 2021 compared with 2020.

•The factor above was partially offset by a decrease in commercial paper and credit facility draws, as well as the redemption of Westcoast Energy Inc.'s preferred shares in the first quarter of 2021.

•Our common share dividend payments increased period-over-period primarily due to the increase in our common share dividend rate.

SUMMARIZED FINANCIAL INFORMATION

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

Consenting SEP notes and EEP notes under Guarantee


SEP Notes1			EEP Notes2
4.750% Senior Notes due 2024			5.875% Notes due 2025
3.500% Senior Notes due 2025			5.950% Notes due 2033
3.375% Senior Notes due 2026			6.300% Notes due 2034
5.950% Senior Notes due 2043			7.500% Notes due 2038
4.500% Senior Notes due 2045			5.500% Notes due 2040

			7.375% Notes due 2045

1As at September 30, 2021, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.

2As at September 30, 2021, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

Enbridge Notes under Guarantees


USD Denominated1			CAD Denominated2
Floating Rate Senior Notes due 2022			4.850% Senior Notes due 2022
Floating Rate Senior Notes due 2023			3.190% Senior Notes due 2022
2.900% Senior Notes due 2022			3.940% Senior Notes due 2023
4.000% Senior Notes due 2023			3.940% Senior Notes due 2023
3.500% Senior Notes due 2024			3.950% Senior Notes due 2024
2.500% Senior Notes due 2025			2.440% Senior Notes due 2025
4.250% Senior Notes due 2026			3.200% Senior Notes due 2027
3.700% Senior Notes due 2027			6.100% Senior Notes due 2028
3.125% Senior Notes due 2029			2.990% Senior Notes due 2029
2.500% Sustainability-Linked Senior Notes due 2033			7.220% Senior Notes due 2030
4.500% Senior Notes due 2044			7.200% Senior Notes due 2032
5.500% Senior Notes due 2046			3.100% Sustainability-Linked Senior Notes due 2033
4.000% Senior Notes due 2049			5.570% Senior Notes due 2035
3.400% Senior Notes due 2051			5.750% Senior Notes due 2039
			5.120% Senior Notes due 2040
			4.240% Senior Notes due 2042
			4.570% Senior Notes due 2044
			4.870% Senior Notes due 2044
			4.100% Senior Notes due 2051


			4.560% Senior Notes due 2064

1As at September 30, 2021, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$9.5 billion.

2As at September 30, 2021, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $9.2 billion.

The following Summarized Combined Statement of Earnings and Summarized Combined Statements of Financial Position combines the balances of EEP, SEP and Enbridge Inc.

Summarized Combined Statement of Earnings


			Nine months ended September 30, 2021
(millions of Canadian dollars)

Operating loss			(13)
Earnings			2,329
Earnings attributable to common shareholders			2,056

Summarized Combined Statements of Financial Position


	September 30, 2021	December 31, 2020
(millions of Canadian dollars)
Accounts receivable from affiliates	3,708	2,108
Short-term loans receivable from affiliates	3,970	4,926
Other current assets	466	375
Long-term loans receivable from affiliates	50,596	43,217
Other long-term assets	3,836	4,237
Accounts payable to affiliates	3,726	1,267
Short-term loans payable to affiliates	2,125	4,117
Other current liabilities	5,336	5,628
Long-term loans payable to affiliates	40,661	32,035
Other long-term liabilities	40,085	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;

•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.

LEGAL AND OTHER UPDATES

LIQUIDS PIPELINES

Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement

In 2019, the Michigan Attorney General filed a complaint in the Michigan Ingham County Circuit Court (the Court) that requests the Court to declare the easement granted in 1953 that we have for the operation of Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in the Straits “as soon as possible after a reasonable notice period to allow orderly adjustments by affected parties”. Ruling on the motions is currently being held in abeyance by the Court pending further developments in the Federal Court cases described below.

On November 13, 2020, the Governor of Michigan and the Director of the Michigan Department of Natural Resources notified us that the State of Michigan (the State) was revoking and terminating the easement granted in 1953 that allows Line 5 to operate across the Straits. The notice demanded that the portion of Line 5 that crosses the Straits must be shut down by May 2021. On November 24, 2020, we filed in the US District Court for the Western District of Michigan a Notice of Removal, which removed the State’s November Complaint to Federal Court, and a Complaint for Declaratory and Injunctive Relief that requests the US District Court to enjoin the Governor from taking any action to prevent or impede the operation of Line 5. US District Court Judge Janet T. Neff was assigned to the cases and on February 18, 2021, Judge Neff ruled that the motion to remand back to State Court will be briefed and decided first. Parties were also ordered to collaborate and identify a facilitative mediator. Accordingly, retired US District Court Judge Gerald Rosen was chosen to act as mediator. The parties had multiple mediation sessions with the mediator, which did not result in a settlement. The State has expressed no interest in further mediation discussions. On October 21, 2021, we filed our motion and supplemental brief to advise the Court that the Government of Canada had invoked the dispute resolution process under the 1977 Transit Pipelines Treaty with the US Government. The State’s remand motion remains with Judge Neff for decision.

On January 12, 2021, we responded to the Governor’s Notice of Revocation and Termination of Easement. On February 11, 2021, we sent a further letter to the Department of Natural Resources regarding our rights under the easement and renewing the request to meet and have technical discussions to better understand the State’s concerns. On May 11, 2021, the Governor sent a letter to us stating that if we continued to operate in the Straits past May 12, 2021, the State would consider us as intentionally trespassing and therefore we will be unjustly enriched entitling the State to all profits derived from wrongful use of the State's property. On May 21, 2021, we responded to the letter refuting the State's claims that the pipelines are in trespass. We will vigorously defend our ability to operate Line 5 under the 1953 easement in pending Court actions.

In March 2021, we completed the engineering and design phase of the Great Lakes Tunnel Project and we have begun the process of hiring a contractor to construct the tunnel. We are actively pursuing state and federal regulatory permits from the US Army Corps of Engineers (Army Corps), the Michigan Department of Environment, Great Lakes & Energy (EGLE) and the Michigan Public Service Commission (MPSC). The EGLE permits were granted in the first quarter of 2021; one of the EGLE permits was challenged by the Bay Mills Indian Community. An Administrative Law Judge was appointed and a schedule set for the contested case proceeding. According to the current schedule, dispositive motions will be fully briefed by December 22, 2021.

On June 23, 2021, the Army Corps announced they would proceed with an EIS for the Great Lakes Tunnel Project to replace Line 5 at the Straits. On June 23, 2021, we issued a statement stating that construction on this project would be delayed due to the EIS. Direct testimony has been filed in the MPSC contested case proceeding and the current schedule has the matter fully briefed by March 11, 2022.

Dakota Access Pipeline

We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of the DAPL. The Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed lawsuits in 2016 with the US Court for the District of Columbia (the District Court) contesting the lawfulness of the Army Corps easement for DAPL, including the adequacy of the Army Corps’ environmental review and tribal consultation process. The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018.

On June 14, 2017, the District Court found the Army Corps’ environmental review to be deficient and ordered the Army Corps to conduct further study concerning spill risks from DAPL. In August 2018, the Army Corps completed on remand the further environmental review ordered by the District Court and reaffirmed the issuance of the easement for DAPL. All four plaintiff Tribes subsequently amended their complaints to include claims challenging the adequacy of the Army Corps’ August 2018 remand decision.

On March 25, 2020, in response to amended complaints from the Tribes, the District Court found the Army Corps’ environmental review on remand was deficient and ordered the Army Corps to prepare an EIS to address unresolved controversy pertaining to potential spill impacts resulting from DAPL. On July 6, 2020, the District Court issued an order vacating the Army Corps’ easement for DAPL and ordering that the pipeline be shut down by August 5, 2020. Dakota Access, LLC and the Army Corps appealed the decision and filed a motion for a stay pending appeal with the US Court of Appeals for the District of Columbia Circuit. On August 5, 2020, the US Court of Appeals stayed the District Court’s July 6 order to shut down and empty the pipeline, but did not stay the District Court’s March 25 order requiring the Army Corps to prepare an EIS or the District Court’s July 6 order vacating the DAPL easement.

On January 26, 2021, the US Court of Appeals affirmed the District Court’s decision, holding that the Army Corps is required to prepare an EIS and that the Army Corps’ easement for DAPL is vacated. Dakota Access, LLC has since filed a petition asking the US Supreme Court to review the decision that an EIS is required. The US Court of Appeals also determined that, absent considering the closure of DAPL in the context of an injunction proceeding, the District Court could not order DAPL’s operations to cease. While not an issue before the US Court of Appeals, the US Court of Appeals also recognized that the Army Corps could consider whether to allow DAPL to continue to operate in the absence of an easement.

On May 21, 2021, the District Court dismissed the plaintiff Tribes’ request for an injunction enjoining DAPL from operating until the Army Corps has completed its EIS. The right of the plaintiff Tribes to appeal the denial of the injunction request expired on July 20, 2021. The Army Corps earlier indicated that it did not intend, at that time, to exercise its authority to bar DAPL’s continued operation, notwithstanding the absence of an easement and that it anticipates completing its EIS by March 2022.

On July 22, 2021, the Army Corps filed a notice with the District Court advising that the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a notice asserting violations of federal safety regulations resulting from the operation of DAPL. The Army Corps stated that it would consider PHMSA’s notice as part of its ongoing consideration of whether and how the Army Corps will enforce its rights on property crossed by the pipeline and in the context of the ongoing EIS. The Army Corps also granted the request from the Tribes to extend the EIS completion date to September 2022.

OTHER LITIGATION

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

CAPITAL EXPENDITURE COMMITMENTS

We have signed contracts for the purchase of services, pipe and other materials totaling approximately $1.8 billion which are expected to be paid over the next five years.

TAX MATTERS

CHANGES IN ACCOUNTING POLICIES

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk is described in Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our annual report on Form 10-K for the year ended December 31, 2020. 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 Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision 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 at September 30, 2021, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in ensuring that information required to be disclosed by us in reports that we file with or submit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

Changes in Internal Control over Financial Reporting

Under the supervision 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 September 30, 2021 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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.

Due to an uncontrolled groundwater flow at Clearbrook, the Minnesota Department of Natural Resources (DNR) issued an Administrative Penalty Order on September 16, 2021. We are diligently implementing the steps required under the remedial action plan to address the issues at the Clearbrook site. We have also provided all required information to date.

We are not seeking a contested case in this matter; instead, we’ve paid the penalty and mitigation amounts as directed, for the Clearbrook site. A separate US$2.75 million escrow account is being established for any potential future monitoring and mitigation. In total, Enbridge has directed US$3.3 million to address this matter.

The DNR and Enbridge are working towards an agreement for ongoing restoration, monitoring, and mitigation for the Clearbrook site and two other locations that remain under evaluation. In the meantime, we are moving forward with DNR-approved restoration plans at Clearbrook and coordinating closely with the DNR at the other sites.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I. Item 1A. Risk Factors of our annual report on Form 10-K for the year ended December 31, 2020, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers

On November 1, 2021, Marcel R. Coutu and V. Maureen Kempston Darkes each notified us of their intention to resign from the Board of Directors of Enbridge Inc., effective November 1, 2021, to avoid future potential or perceived conflicts of interest. Mr. Coutu served on the Board of Directors since 2014 and Ms. Kempston Darkes served on the Board of Directors since 2010. Neither Mr. Coutu’s nor Ms. Kempston Darkes’ decision to resign from the Board of Directors was the result of any disagreement relating to our operations, policies or practices.

ITEM 6. EXHIBITS

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


Exhibit No.						Description
22.1*						Subsidiary Guarantors
31.1*						Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*						Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*						Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*						Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*						XBRL Instance Document.
101.SCH*						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.
104						Cover 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.


			ENBRIDGE INC.
			(Registrant)

Date:	November 5, 2021	By:	/s/ Al Monaco
			Al Monaco President and Chief Executive Officer (Principal Executive Officer)

Date:	November 5, 2021	By:	/s/ Vern D. Yu
			Vern D. Yu Executive Vice President and Chief Financial Officer (Principal Financial Officer)