Enhanced Investments - Financial Portal

Published: 2023-11-03 00:00:00 ET

enb-20230930

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, 2023


☐						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 001-15254



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


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

200, 425 - 1st Street S.W.

Calgary, Alberta, Canada T2P 3L8

(Address of Principal Executive Offices) (Zip Code)

(403) 231-3900

(Registrant’s Telephone Number, Including Area Code)

_______________________________

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Shares

ENB

New York Stock Exchange

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

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

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

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

Large accelerated filer

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 2,125,574,412 common shares outstanding as at October 27, 2023.


	PART I	PAGE

Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 4.	Controls and Procedures	64

	PART II

Item 1.	Legal Proceedings	65
Item 1A.	Risk Factors	65
Item 2.	Unregistered Sales of Equity Securities, Use of Proceeds, and Issuer Purchase s of Equity Securities	66
Item 3.	Defaults Upon Senior Securities	66
Item 4.	Mine Safety Disclosures	66
Item 5.	Other Information	66
Item 6.	Exhibits	67
	Signatures	68

GLOSSARY


AG			Attorney General
AOCI			Accumulated other comprehensive income/(loss)



Aux Sable			Aux Sable Canada LP, Aux Sable Liquid Products LP and Aux Sable Midstream LLC
CER			Canada Energy Regulator


DCP			DCP Midstream, LP
EBITDA			Earnings before interest, income taxes and depreciation and amortization

EEP			Enbridge Energy Partners, L.P.




Enbridge			Enbridge Inc.
Enbridge Gas			Enbridge Gas Inc.


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

Gray Oak			Gray Oak Pipeline, LLC
















OCI			Other comprehensive income/(loss)

OEB			Ontario Energy Board
OPEB			Other postretirement benefits
P66			Phillips 66



SEP			Spectra Energy Partners, LP






the Acquisitions			On September 5, 2023, we announced that Enbridge had entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina




the Band			Bad River Band of the Lake Superior Tribe of Chippewa Indians
the Court			United States District Court for the Western District Wisconsin

the Partnerships			Spectra Energy Partners, LP and Enbridge Energy Partners, L.P.
the Reservation			Bad River Reservation



US			United States

CONVENTIONS

The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. and its subsidiaries 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 "$" are to Canadian dollars and all references to "US$" 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: the characteristics, value drivers and anticipated benefits of our acquisitions of three US gas utilities (the Gas Utilities) from Dominion Energy, Inc. (the Acquisitions); our corporate vision and strategy, including strategic priorities and enablers; expected supply of, demand for, exports of and prices of crude oil, natural gas, natural gas liquids (NGL), liquified natural gas (LNG) and renewable energy; energy transition and lower-carbon energy, and our approach thereto; environmental, social and governance goals, practices and performance; industry and market conditions; anticipated utilization of our assets; 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, benefits and in-service dates related to announced projects and projects under construction; expected capital expenditures; investable capacity and capital allocation priorities; expected equity funding requirements for our commercially secured growth program; expected future growth, development and expansion opportunities; expected optimization and efficiency opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; our ability to complete the Acquisitions and successfully integrate the Gas Utilities; expected closing of other acquisitions and dispositions and the timing thereof; expected benefits of transactions, including the Acquisitions; expected future actions of regulators and courts, and the timing and impact thereof; toll and rate cases discussions and proceedings and anticipated timeline and impact therefrom, including Mainline Tolling and those relating to the Gas Transmission and Midstream and Gas Distribution and Storage businesses; operational, industry, regulatory, climate change and other risks associated with our businesses; the other sources we expect to use to finance the remainder of the aggregate purchase price for the Acquisitions and the timing thereof; and our assessment of the potential impact of the various risk factors identified herein.

Although we believe these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of, demand for, export of and prices of crude oil, natural gas, NGL, LNG and renewable energy; anticipated utilization of assets; exchange rates; inflation; interest rates; availability and price of labor and construction materials; the stability of our supply chain; operational reliability; maintenance of support and regulatory approvals for our projects; anticipated in-service dates; weather; the timing, terms and closing of acquisitions and dispositions, including the Acquisitions; the realization of anticipated benefits of transactions, including the Acquisitions; 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 earnings before interest, income taxes and depreciation and amortization (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, LNG and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. 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 stability of our supply chain; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes.

Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities; operating performance; legislative and regulatory parameters; litigation; acquisitions (including the Acquisitions), dispositions and other transactions and the realization of anticipated benefits therefrom; operational dependence on third parties; 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; inflation; interest rates; commodity prices; access to and cost of capital; political decisions; global geopolitical conditions; and the supply of, demand for and prices of commodities and other alternative energy, 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 US securities regulators. The impact of any one assumption, 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.

NON-GAAP AND OTHER FINANCIAL MEASURES

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

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

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	4,652	6,415	14,114	22,880
Gas distribution sales	516	695	3,587	3,698
Transportation and other services	4,676	4,463	14,650	13,307
Total operating revenues (Note 2)	9,844	11,573	32,351	39,885
Operating expenses
Commodity costs	4,648	6,300	13,833	22,772
Gas distribution costs	183	330	2,145	2,242
Operating and administrative	2,055	2,089	6,120	5,958
Depreciation and amortization	1,164	1,076	3,447	3,195

Total operating expenses	8,050	9,795	25,545	34,167
Operating income	1,794	1,778	6,806	5,718
Income from equity investments	343	536	1,338	1,537

Gain on joint venture merger transaction (Note 5)	—	1,076	—	1,076
Other income/(expense) (Note 10)	(465)	(883)	212	(924)



Interest expense	(921)	(806)	(2,709)	(2,316)
Earnings before income taxes	751	1,701	5,647	5,091
Income tax expense	(128)	(318)	(1,157)	(1,044)
Earnings	623	1,383	4,490	4,047
Earnings attributable to noncontrolling interests	(2)	(21)	(117)	(61)
Earnings attributable to controlling interests	621	1,362	4,373	3,986
Preference share dividends	(89)	(83)	(260)	(330)
Earnings attributable to common shareholders	532	1,279	4,113	3,656
Earnings per common share attributable to common shareholders (Note 4)	0.26	0.63	2.02	1.80
Diluted earnings per common share attributable to common shareholders (Note 4)	0.26	0.63	2.02	1.80

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,
	2023	2022	2023	2022
(unaudited; millions of Canadian dollars)
Earnings	623	1,383	4,490	4,047
Other comprehensive income/(loss), net of tax
Change in unrealized gain on cash flow hedges	238	171	359	817
Change in unrealized gain/(loss) on net investment hedges	(358)	(934)	42	(1,187)
Other comprehensive income/(loss) from equity investees	7	(7)	7	(7)
Excluded components of fair value hedges	2	(33)	11	(38)
Reclassification to earnings of loss on cash flow hedges	39	36	58	145
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(5)	(2)	(13)	(7)
Reclassification to earnings of loss on equity investees	—	16	—	16
Foreign currency translation adjustments	1,386	4,135	(131)	5,308
Other comprehensive income, net of tax	1,309	3,382	333	5,047
Comprehensive income	1,932	4,765	4,823	9,094
Comprehensive income attributable to noncontrolling interests	(45)	(116)	(143)	(187)
Comprehensive income attributable to controlling interests	1,887	4,649	4,680	8,907
Preference share dividends	(89)	(83)	(260)	(330)
Comprehensive income attributable to common shareholders	1,798	4,566	4,420	8,577

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,
	2023	2022	2023	2022
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares
Balance at beginning of period	6,818	6,818	6,818	7,747
Redemption of preference shares	—	—	—	(929)
Balance at end of period	6,818	6,818	6,818	6,818
Common shares
Balance at beginning of period	64,694	64,755	64,760	64,799
Shares issued, net of issue costs	4,485	—	4,485	—
Shares issued on exercise of stock options	1	2	3	50
Shares issued on vesting of restricted stock units (RSU)	—	—	12	—
Share purchases at stated value	—	—	(80)	(88)
Other	—	—	—	(4)
Balance at end of period	69,180	64,757	69,180	64,757
Additional paid-in capital
Balance at beginning of period	291	305	275	365
Stock-based compensation	35	9	53	27
Stock options exercised	(1)	(2)	(3)	(47)
Vested RSUs, net of withholding tax	(20)	—	(20)	—
Purchase of noncontrolling interests	(29)	—	(29)	—
Other	—	—	—	(33)
Balance at end of period	276	312	276	312
Deficit
Balance at beginning of period	(13,746)	(10,418)	(15,486)	(10,989)
Earnings attributable to controlling interests	621	1,362	4,373	3,986
Preference share dividends	(89)	(83)	(260)	(330)
Common share dividends declared	(1,795)	(1,741)	(3,591)	(3,484)

Share purchases in excess of stated value	—	—	(45)	(63)

Balance at end of period	(15,009)	(10,880)	(15,009)	(10,880)
Accumulated other comprehensive income/(loss) (Note 7)
Balance at beginning of period	2,561	538	3,520	(1,096)
Other comprehensive income attributable to common shareholders, net of tax	1,266	3,287	307	4,921
Balance at end of period	3,827	3,825	3,827	3,825




Total Enbridge Inc. shareholders’ equity	65,092	64,832	65,092	64,832
Noncontrolling interests
Balance at beginning of period	3,420	2,539	3,511	2,542
Earnings attributable to noncontrolling interests	2	21	117	61
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain/(loss) on cash flow hedges	11	(8)	29	(14)
Foreign currency translation adjustments	32	103	(3)	140
	43	95	26	126
Comprehensive income attributable to noncontrolling interests	45	116	143	187
Distributions	(86)	(62)	(281)	(189)
Contributions	2	2	10	10
Purchase of noncontrolling interests	2	—	2	—
Other	(1)	3	(3)	48
Balance at end of period	3,382	2,598	3,382	2,598
Total equity	68,474	67,430	68,474	67,430
Dividends paid per common share	0.89	0.86	2.67	2.58

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,
	2023	2022
(unaudited; millions of Canadian dollars)
Operating activities
Earnings	4,490	4,047
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	3,447	3,195
Deferred income tax expense	923	600
Unrealized derivative fair value (gain)/loss, net (Note 8)	(270)	1,691
Income from equity investments	(1,338)	(1,537)
Distributions from equity investments	1,539	1,293


Gain on joint venture merger transaction (Note 5)	—	(1,076)

Other	137	6
Changes in operating assets and liabilities	1,461	(602)
Net cash provided by operating activities	10,389	7,617
Investing activities
Capital expenditures	(3,284)	(3,204)
Long-term, restricted and other investments	(487)	(566)
Distributions from equity investments in excess of cumulative earnings	865	426
Additions to intangible assets	(165)	(131)
Acquisitions	(487)	(295)
Proceeds from joint venture merger transaction (Note 5)	—	522

Affiliate loans, net	86	90
Other	(31)	—
Net cash used in investing activities	(3,503)	(3,158)
Financing activities
Net change in short-term borrowings	(412)	367
Net change in commercial paper and credit facility draws	(9,855)	386
Debenture and term note issues, net of issue costs	9,611	4,739
Debenture and term note repayments	(2,881)	(2,244)
Contributions from noncontrolling interests	10	10
Distributions to noncontrolling interests	(281)	(189)
Common shares issued, net of issue costs	4,450	3
Common shares repurchased	(125)	(151)
Preference share dividends	(260)	(254)
Common share dividends	(5,390)	(5,226)
Redemption of preference shares	—	(1,003)
Affiliate loans, net	69	—
Other	(82)	(223)
Net cash used in financing activities	(5,146)	(3,785)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	—	63
Net change in cash and cash equivalents and restricted cash	1,740	737
Cash and cash equivalents and restricted cash at beginning of period	907	320
Cash and cash equivalents and restricted cash at end of period	2,647	1,057

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

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	September 30, 2023	December 31, 2022
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	2,608	861
Restricted cash	39	46
Trade receivables and unbilled revenues	3,976	5,616
Other current assets	2,757	3,255
Accounts receivable from affiliates	185	114
Inventory	1,566	2,255
	11,131	12,147
Property, plant and equipment, net	105,580	104,460
Long-term investments	15,271	15,936
Restricted long-term investments	635	593
Deferred amounts and other assets	9,276	9,542
Intangible assets, net	3,730	4,018
Goodwill	32,390	32,440
Deferred income taxes	397	472
Total assets	178,410	179,608

Liabilities and equity
Current liabilities
Short-term borrowings	1,584	1,996
Trade payables and accrued liabilities	4,375	6,172
Other current liabilities	2,851	5,220
Accounts payable to affiliates	54	105
Interest payable	723	763
Current portion of long-term debt	7,138	6,045
	16,725	20,301
Long-term debt	68,793	72,939
Other long-term liabilities	9,467	9,189
Deferred income taxes	14,951	13,781
	109,936	116,210
Contingencies (Note 11)
Equity
Share capital
Preference shares	6,818	6,818
Common shares (2,126 and 2,025 outstanding at September 30, 2023 and December 31, 2022, respectively)	69,180	64,760
Additional paid-in capital	276	275
Deficit	(15,009)	(15,486)
Accumulated other comprehensive income (Note 7)	3,827	3,520

Total Enbridge Inc. shareholders’ equity	65,092	59,887
Noncontrolling interests	3,382	3,511
	68,474	63,398
Total liabilities and equity	178,410	179,608

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, 2022. 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, 2022. 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.

Certain comparative figures in our interim consolidated financial statements have been reclassified to conform to the current year's presentation.

2. REVENUES

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services


Three months ended September 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	2,856	1,294	148	—	—	—	4,298
Storage and other revenue	65	118	83	—	—	—	266

Gas distribution revenue	—	—	528	—	—	—	528
Electricity revenue	—	—	—	79	—	—	79

Total revenue from contracts with customers	2,921	1,412	759	79	—	—	5,171
Commodity sales	—	—	—	—	4,652	—	4,652
Other revenue1,2	61	11	(9)	(42)	—	—	21
Intersegment revenue	102	—	1	3	6	(112)	—
Total revenue	3,084	1,423	751	40	4,658	(112)	9,844


Three months ended September 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	2,962	1,264	143	—	—	—	4,369
Storage and other revenue	58	91	63	—	—	—	212

Gas distribution revenue	—	—	699	—	—	—	699
Electricity revenue	—	—	—	68	—	—	68

Total revenue from contracts with customers	3,020	1,355	905	68	—	—	5,348
Commodity sales	—	—	—	—	6,415	—	6,415
Other revenue1,2	(258)	10	3	54	—	1	(190)
Intersegment revenue	137	1	1	(2)	4	(141)	—
Total revenue	2,899	1,366	909	120	6,419	(140)	11,573


Nine months ended September 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	8,800	3,968	593	—	—	—	13,361
Storage and other revenue	191	326	267	—	—	—	784

Gas distribution revenue	—	—	3,611	—	—	—	3,611
Electricity revenue	—	—	—	220	—	—	220

Total revenue from contracts with customers	8,991	4,294	4,471	220	—	—	17,976
Commodity sales	—	—	—	—	14,114	—	14,114
Other revenue1,2	170	29	(50)	112	—	—	261
Intersegment revenue	358	1	5	2	24	(390)	—
Total revenue	9,519	4,324	4,426	334	14,138	(390)	32,351

Nine months ended September 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	8,212	3,658	551	—	—	—	12,421
Storage and other revenue	173	258	209	—	—	—	640
Gas gathering and processing revenue	—	21	—	—	—	—	21
Gas distribution revenue	—	—	3,716	—	—	—	3,716
Electricity revenue	—	—	—	211	—	—	211

Total revenue from contracts with customers	8,385	3,937	4,476	211	—	—	17,009
Commodity sales	—	—	—	—	22,880	—	22,880
Other revenue1,2	(225)	28	(30)	222	—	1	(4)
Intersegment revenue	432	2	12	(2)	14	(458)	—
Total revenue	8,592	3,967	4,458	431	22,894	(457)	39,885

1Includes realized and unrealized gains and losses from our hedging program which for the three months ended September 30, 2023 were a net $97 million loss (2022 - $345 million loss) and for the nine months ended September 30, 2023 were a net $149 million loss (2022 - $483 million loss).

2Includes revenues from lease contracts for the three months ended September 30, 2023 and 2022 of $107 million and $128 million, respectively, and for the nine months ended September 30, 2023 and 2022 of $387 million and $435 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, 2023	2,161	230	2,448
Balance as at December 31, 2022	3,183	230	2,241

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

Contract assets represent the amount of revenues which has been recognized in advance of payments received for performance obligations we have fulfilled (or have 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, 2023 included in contract liabilities at the beginning of the period was $90 million and $179 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three and nine months ended September 30, 2023 were $213 million and $380 million, respectively.

Performance Obligations

There were no material revenues recognized in the three and nine months ended September 30, 2023 from performance obligations satisfied in previous periods.

Revenues to be Recognized from Unfulfilled Performance Obligations

Total revenues from performance obligations expected to be fulfilled in future periods is $57.5 billion, of which $2.0 billion and $6.6 billion are expected to be recognized during the remaining three months ending December 31, 2023 and the year ending December 31, 2024, respectively.

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

Variable Consideration

During the first six months of 2023, revenue for the Canadian Mainline was recognized 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 continued on an interim basis until July 1, 2023 when new interim tolls took effect. Until a new commercial arrangement is approved, the tolls 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 (CER) decision and potential customer negotiations, interim toll revenue recognized during the three and nine months ended September 30, 2023 is considered variable consideration.

Recognition and Measurement of Revenues


Three months ended September 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	38	—	38
Revenues from products and services transferred over time1	2,921	1,412	721	79	5,133
Total revenue from contracts with customers	2,921	1,412	759	79	5,171

Three months ended September 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	41	—	41
Revenues from products and services transferred over time1	3,020	1,355	864	68	5,307
Total revenue from contracts with customers	3,020	1,355	905	68	5,348

Nine months ended September 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	105	—	105
Revenues from products and services transferred over time1	8,991	4,294	4,366	220	17,871
Total revenue from contracts with customers	8,991	4,294	4,471	220	17,976

Nine months ended September 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	77	—	77
Revenues from products and services transferred over time1	8,385	3,937	4,399	211	16,932
Total revenue from contracts with customers	8,385	3,937	4,476	211	17,009

1Revenue 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.

3. SEGMENTED INFORMATION


Three months ended September 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Operating revenues	3,084	1,423	751	40	4,658	(112)	9,844
Commodity and gas distribution costs	—	1	(190)	(13)	(4,749)	120	(4,831)
Operating and administrative	(1,088)	(578)	(305)	(63)	(10)	(11)	(2,055)


Income/(loss) from equity investments	231	94	—	21	—	(3)	343


Other income/(expense)	20	33	15	45	(5)	(573)	(465)
Earnings/(loss) before interest, income taxes and depreciation and amortization	2,247	973	271	30	(106)	(579)	2,836
Depreciation and amortization							(1,164)
Interest expense							(921)
Income tax expense							(128)
Earnings							623
Capital expenditures1	598	989	679	54	—	27	2,347


Three months ended September 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Operating revenues	2,899	1,366	909	120	6,419	(140)	11,573
Commodity and gas distribution costs	27	—	(327)	(5)	(6,465)	140	(6,630)
Operating and administrative	(1,173)	(545)	(311)	(58)	(9)	7	(2,089)


Income from equity investments	193	321	—	22	—	—	536

Gain on joint venture merger transaction (Note 5)	—	1,076	—	—	—	—	1,076
Other income/(expense)	—	33	15	26	(15)	(942)	(883)
Earnings/(loss) before interest, income taxes and depreciation and amortization	1,946	2,251	286	105	(70)	(935)	3,583
Depreciation and amortization							(1,076)
Interest expense							(806)
Income tax expense							(318)
Earnings							1,383
Capital expenditures1	268	525	405	9	—	8	1,215


Nine months ended September 30, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Operating revenues	9,519	4,324	4,426	334	14,138	(390)	32,351
Commodity and gas distribution costs	—	1	(2,173)	(19)	(14,179)	392	(15,978)
Operating and administrative	(3,294)	(1,715)	(939)	(178)	(40)	46	(6,120)


Income/(loss) from equity investments	733	531	1	83	—	(10)	1,338


Other income/(expense)	103	79	39	75	(2)	(82)	212
Earnings/(loss) before interest, income taxes and depreciation and amortization	7,061	3,220	1,354	295	(83)	(44)	11,803
Depreciation and amortization							(3,447)
Interest expense							(2,709)
Income tax expense							(1,157)
Earnings							4,490
Capital expenditures1	835	1,332	1,025	77	—	54	3,323


Nine months ended September 30, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Operating revenues	8,592	3,967	4,458	431	22,894	(457)	39,885
Commodity and gas distribution costs	—	—	(2,258)	(13)	(23,197)	454	(25,014)
Operating and administrative	(3,096)	(1,620)	(891)	(159)	(34)	(158)	(5,958)


Income/(loss) from equity investments	561	877	1	100	—	(2)	1,537

Gain on joint venture merger transaction (Note 5)	—	1,076	—	—	—	—	1,076
Other income/(expense)	36	84	58	30	(11)	(1,121)	(924)
Earnings/(loss) before interest, income taxes and depreciation and amortization	6,093	4,384	1,368	389	(348)	(1,284)	10,602
Depreciation and amortization							(3,195)
Interest expense							(2,316)
Income tax expense							(1,044)
Earnings							4,047
Capital expenditures1	1,086	1,087	1,005	26	—	32	3,236

1Includes allowance for equity funds used during construction.

4. 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.

DILUTED

The treasury stock method is used to determine the dilutive impact of stock options and RSUs. This method assumes any proceeds from the exercise of stock options and vesting of RSUs 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,
	2023	2022	2023	2022
(number of shares in millions)
Weighted average shares outstanding	2,048	2,025	2,033	2,026
Effect of dilutive options and RSUs	1	3	2	3
Diluted weighted average shares outstanding	2,049	2,028	2,035	2,029

For the three months ended September 30, 2023 and 2022, 21.6 million and 11.4 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $53.69 and $56.49, respectively, were excluded from the diluted earnings per common share calculation.

For the nine months ended September 30, 2023 and 2022, 18.2 million and 9.2 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $54.81 and $56.63, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE

On October 31, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2023 to shareholders of record on November 15, 2023.


			Dividend per share
Common Shares1			$0.88750
Preference Shares, Series A			$0.34375
Preference Shares, Series B			$0.32513
Preference Shares, Series D2			$0.33825
Preference Shares, Series F3			$0.34613
Preference Shares, Series G4			$0.47245
Preference Shares, Series H5			$0.38200
Preference Shares, Series I6			$0.44814
Preference Shares, Series L			US$0.36612
Preference Shares, Series N			$0.31788
Preference Shares, Series P			$0.27369
Preference Shares, Series R			$0.25456
Preference Shares, Series 17			US$0.41898
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 198			$0.38825

1The quarterly dividend per common share was increased 3.2% to $0.8875 from $0.86, effective March 1, 2023.

2The quarterly dividend per share paid on Preference Shares, Series D was increased to $0.33825 from $0.27875 on March 1, 2023 due to reset of the annual dividend on March 1, 2023.

3The quarterly dividend per share paid on Preference Shares, Series F was increased to $0.34613 from $0.29306 on June 1, 2023 due to reset of the annual dividend on June 1, 2023.

4On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G. The quarterly dividend per share paid on Preference Shares, Series G was increased to $0.47245 from $0.43858 on September 1, 2023 due to reset on a quarterly basis following the date of issuance.

5The quarterly dividend per share paid on Preference Shares, Series H was increased to $0.38200 from $0.27350 on September 1, 2023 due to reset of the annual dividend on September 1, 2023.

6On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I. The first quarterly dividend on Preference Shares, Series I will be paid on December 1, 2023.

7The quarterly dividend per share paid on Preference Shares, Series 1 was increased to US$0.41898 from US$0.37182 on June 1, 2023 due to reset of the annual dividend on June 1, 2023.

8The quarterly dividend per share paid on Preference Shares, Series 19 was increased to $0.38825 from $0.30625 on March 1, 2023 due to reset of the annual dividend on March 1, 2023.

5. ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS OF US GAS UTILITIES

On September 5, 2023, we announced that Enbridge had entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina for an aggregate purchase price of $19.1 billion (US$14.0 billion), comprised of $12.8 billion (US$9.4 billion) of cash consideration and $6.3 billion (US$4.6 billion) of assumed debt, subject to customary closing adjustments (together, the Acquisitions). The Acquisitions are expected to close in 2024, subject to the satisfaction of customary closing conditions including the receipt of certain regulatory approvals, which are not cross conditional.

In September 2023, we closed two offerings for aggregate principal amounts of US$2.0 billion and $1.0 billion. The proceeds from the offerings are intended to finance a portion of the aggregate cash consideration payable for the Acquisitions. Refer to Note 6 - Debt for further details on the debt issuances and credit facility obtained to support the Acquisitions.

TRES PALACIOS HOLDINGS LLC

On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for $451 million (US$335 million) of cash. Tres Palacios is a natural gas storage facility located in the United States (US) Gulf Coast and its infrastructure serves Texas gas-fired power generation and liquefied natural gas exports, as well as Mexico pipeline exports.

We allocated assets with a fair value of $790 million (US$588 million) to Property, plant and equipment, net, of which $254 million (US$189 million) relates to storage cavern right-of-use assets, and recorded the related lease liabilities of $7 million (US$5 million) and $248 million (US$184 million) to Current portion of long-term debt and Long-term debt, respectively, in the Consolidated Statements of Financial Position. The acquired assets are included in our Gas Transmission and Midstream segment.

DCP MIDSTREAM, LLC

On August 17, 2022, we completed a joint venture merger transaction with Phillips 66 resulting in a single joint venture, DCP Midstream, LLC, holding both our and Phillips 66's indirect ownership interests in Gray Oak Pipeline, LLC (Gray Oak) and DCP Midstream, LP (DCP). Our ownership in DCP Midstream, LLC consists of Class A and Class B Interests which track to our investments in DCP, included in the Gas Transmission and Midstream segment, and Gray Oak, included in the Liquids Pipelines segment, respectively. Through our investment in DCP Midstream, LLC, we increased our effective economic interest in Gray Oak to 58.5% from 22.8% and reduced our effective economic interest in DCP to 13.2% from 28.3%. As a result of the transaction, Enbridge assumed operatorship of Gray Oak in the second quarter of 2023.

We determined the fair value of our decrease in economic interest in DCP based on the unadjusted quoted market price of DCP’s publicly traded common units on the transaction closing date. The fair value of our increased economic interest in Gray Oak was determined using the fair value prescribed to the change in our economic interest in DCP. As a result of the merger transaction and the realignment of our economic interests in DCP and Gray Oak, we also received cash consideration of approximately $522 million (US$404 million) and recorded an accounting gain of $1.1 billion (US$832 million) to Gain on joint venture merger transaction in the Consolidated Statements of Earnings. Both DCP and Gray Oak continue to be accounted for as equity method investments.

TRI GLOBAL ENERGY, LLC

On September 27, 2022, through a wholly-owned US subsidiary, we acquired all of the outstanding common units in Tri Global Energy, LLC (TGE) for cash consideration of $295 million (US$215 million) plus potential contingent payments of up to $72 million (US$53 million) dependent on the achievement of performance milestones by TGE (the TGE Acquisition). TGE is an onshore renewable project developer in the US with a development portfolio of wind and solar projects. The TGE Acquisition enhances Enbridge's renewable power platform and accelerates our North American growth strategy.

We accounted for the TGE Acquisition using the acquisition method as prescribed by ASC 805 Business

Combinations. In accordance with valuation methodologies described in ASC 820 Fair Value

Measurements, the acquired assets and assumed liabilities are recorded at their estimated fair values

as at the date of acquisition.

The following table summarizes the estimated fair values that were assigned to the net assets of TGE:


			September 27, 2022
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets			5
Property, plant and equipment			3
Long-term investments			8
Intangible assets (a)			117
Long-term assets			3
Current liabilities			61
Long-term debt			18
Long-term liabilities (b)			105
Goodwill (c)			392
Purchase price:
Cash			295
Contingent consideration (d)			49
			344

a) Intangible assets consist of compensation expected to be earned by TGE on existing development contracts once certain project development milestones are met. Fair value was determined using a discounted cash flow method which is an income-based approach to valuation that estimates the present value of future projected benefits from the contracts. The intangible assets will be amortized on a straight-line basis over an expected useful life of three and a half years.

b) Long-term liabilities consist primarily of obligations payable to third parties which are contingent on milestones being met for certain projects. Fair value represents the present value of the future cash flow payments at the date of the TGE Acquisition.

c) Goodwill is primarily attributable to expected future returns from new opportunities to develop wind and solar projects, as well as enhanced scale and operational diversity of our renewable projects portfolio. The goodwill balance recognized has been assigned to our Renewable Power Generation segment and is tax deductible over 15 years.

d) We agreed to pay additional contingent consideration of up to US$53 million to TGE's former

common unit holders if performance milestones are met on certain projects. The US$36 million of contingent consideration recognized in the purchase price represents the fair value of contingent

consideration at the date of acquisition. The fair value was determined using an income-based approach.

Upon completion of the TGE Acquisition, we began consolidating TGE. For the period beginning September 27, 2022 through to September 30, 2022, operating revenues and earnings attributable to common shareholders generated by TGE were immaterial. The impact to our supplemental pro forma consolidated operating revenues and earnings attributable to common shareholders for the three and nine months ended September 30, 2022, as if the TGE Acquisition had been completed on January 1, 2021, was also immaterial.

ATHABASCA REGIONAL OIL SANDS SYSTEM

On September 28, 2022, we entered into an agreement to sell an 11.6% non-operating interest in seven pipelines in the Athabasca region of northern Alberta from our Regional Oil Sands System to Athabasca Indigenous Investments Limited Partnership, an entity representing 23 First Nation and Métis communities. On October 5, 2022, we closed the sale for total consideration of approximately $1.1 billion, less customary closing adjustments. Subsequent to the sale, we maintained an 88.4% controlling interest in these assets, which are a component of our Liquids Pipelines segment, and continue to manage, operate and provide administrative services to them.

6. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at September 30, 2023:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2024-2028	8,853	1,272	7,581
Enbridge (U.S.) Inc.	2025-2028	8,585	1,064	7,521
Enbridge Pipelines Inc.	2025	2,000	265	1,735
Enbridge Gas Inc.	2025	2,500	1,585	915
Total committed credit facilities		21,938	4,186	17,752

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.

In March 2023, Enbridge Gas Inc. (Enbridge Gas) increased its 364-day extendible credit facility from $2.0 billion to $2.5 billion and in July 2023, the facility's maturity date was extended to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, we renewed approximately $6.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2025, which includes a one-year term out provision from July 2024. We also renewed approximately $7.6 billion of our five-year credit facilities, extending the maturity dates to July 2028. Further, we extended our three-year credit facilities, extending the maturity dates to July 2026.

In September 2023, we obtained commitments for a US$9.4 billion senior unsecured bridge term loan credit facility to support the Acquisitions. The commitment for this facility was subsequently reduced to US$3.4 billion as at September 30, 2023 as a result of the $4.6 billion equity offering and the September 2023 subordinated long-term debt issuances.

In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $712 million was unutilized as at September 30, 2023. As at December 31, 2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $689 million was unutilized.

Our credit facilities, excluding the bridge term loan facility, 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 2024 to 2028.

As at September 30, 2023 and December 31, 2022, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $2.1 billion and $10.5 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, 2023, we completed the following long-term debt issuances totaling US$5.0 billion and $2.9 billion:

Company

Issue Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

March 2023

5.70%

sustainability-linked senior notes due March 20331

US$2,300

March 2023

5.97%

senior notes due March 20262

US$700

May 2023

4.90%

medium-term notes due May 2028

$600

May 2023

5.36%

sustainability-linked medium-term notes due May 20333

$400

May 2023

5.76%

medium-term notes due May 2053

$500

September 2023

8.50%

fixed-to-fixed subordinated notes due January 20844

US$1,250

September 2023

8.25

fixed-to-fixed subordinated notes due January 20845

US$750

September 2023

8.75

fixed-to-fixed subordinated notes due January 20846

$700

September 2023

8.50

fixed-to-fixed subordinated notes due January 20847

$300

Enbridge Pipelines Inc.

August 2023

5.82%

medium-term notes due August 2053

$350

1The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on September 8, 2031, the interest rate will be set to equal 5.70% plus 50 basis points.

2We have the option to call the notes at par after one year from issuance. Refer to Note 8 - Risk Management and Financial Instruments.

3The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on November 26, 2031, the interest rate will be set to equal 5.36% plus 50 basis points.

4For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.43%. Subsequent to year 10, every five years, the Five-year US treasury rate is reset. At year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.18%.

5For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 3.79%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 4.04%. Subsequent to year 10, every five years, the Five-Year US Treasury rate is reset. At year 25, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.79%.

6For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.96%. Subsequent to year 10, every five years, the Government of Canada bond yield rate is reset. At year 30, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 5.71%.

7For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.30%. At year 10, the interest rate will be reset to equal the Five-Year Government of Canada bond yield plus a margin of 4.55%. Subsequent to year 10, every five years, the Five-Year Government of Canada bond yield is reset. At year 25, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 5.30%.

In October 2023, Enbridge Gas closed a three-tranche offering consisting of five-year medium-term notes, 10-year medium-term notes, and 30-year medium-term notes, for an aggregate principal amount of $1.0 billion, which mature in October 2028, October 2033, and October 2053, respectively.

LONG-TERM DEBT REPAYMENTS

During the nine months ended September 30, 2023, we completed the following long-term debt repayments totaling US$1.2 billion and $1.3 billion:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

January 2023

3.94%

medium-term notes

$275

February 2023

Floating rate notes1

US$500

April 2023

6.38%

fixed-to-floating rate subordinated notes2

US$600

June 2023

3.94%

medium-term notes

$450

Enbridge Gas Inc.

July 2023

6.05%

medium-term notes

$100

July 2023

3.79%

medium-term notes

$250

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

June 2023

3.98%

senior notes

US$38

Enbridge Pipelines Inc.

August 2023

3.79%

medium-term notes

$250

Enbridge Southern Lights LP

June 2023

4.01%

senior notes

Tri Global Energy, LLC

January 2023

10.00%

senior notes

US$4

January 2023

14.00%

senior notes

US$9

1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 40 basis points.

2The five-year callable notes, with an original maturity date of April 2078, were all redeemed at par.

SUBORDINATED TERM NOTES

As at September 30, 2023 and December 31, 2022, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $13.2 billion and $10.3 billion, respectively.

FAIR VALUE ADJUSTMENT

As at September 30, 2023 and December 31, 2022, the net fair value adjustments to total debt assumed in a historical acquisition were $551 million and $608 million, respectively. Amortization of the fair value adjustment is recorded as a reduction to Interest expense in the Consolidated Statements of Earnings:


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Amortization of fair value adjustment	12	11	34	33

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, 2023, we were in compliance with all covenant provisions.

7. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to our common shareholders for the nine months ended September 30, 2023 and 2022 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, 2023	121	(35)	(1,137)	4,348	5	218	3,520
Other comprehensive income/(loss) retained in AOCI	447	11	42	(128)	8	—	380
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	63	—	—	—	—	—	63


Other contracts2	1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(16)	(16)

	511	11	42	(128)	8	(16)	428
Tax impact
Income tax on amounts retained in AOCI	(117)	—	—	—	(1)	—	(118)
Income tax on amounts reclassified to earnings	(6)	—	—	—	—	3	(3)
	(123)	—	—	—	(1)	3	(121)

Balance as at September 30, 2023	509	(24)	(1,095)	4,220	12	205	3,827


	Cash Flow Hedges	Excluded Components of Fair Value Hedges	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees	Pension and OPEB Adjustment	Total
(millions of Canadian dollars)
Balance as at January 1, 2022	(897)	—	(166)	56	(5)	(84)	(1,096)
Other comprehensive income/(loss) retained in AOCI	1,073	(38)	(1,187)	5,168	(6)	—	5,010
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	187	—	—	—	—	—	187

Foreign exchange contracts4	(4)	—	—	—	—	—	(4)
Other contracts2	3	—	—	—	—	—	3
Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(9)	(9)
Other	—	—	—	—	16	—	16
	1,259	(38)	(1,187)	5,168	10	(9)	5,203
Tax impact
Income tax on amounts retained in AOCI	(242)	—	—	—	(1)	—	(243)
Income tax on amounts reclassified to earnings	(41)	—	—	—	—	2	(39)
	(283)	—	—	—	(1)	2	(282)

Balance as at September 30, 2022	79	(38)	(1,353)	5,224	4	(91)	3,825

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

2Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

3These components are included in the computation of net periodic benefit credit and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

4Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.

8. 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 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 US dollar-denominated investments and subsidiaries using foreign currency derivatives and US dollar-denominated debt.

The foreign exchange risks inherent within the CTS framework are not present in the negotiated settlement. Accordingly, our foreign exchange hedging program related to the Canadian Mainline will no longer be required, and the related derivatives were terminated in the first quarter of 2023 for a realized loss of $638 million.

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 hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps and costless collars. These swaps have an average fixed rate of 4.2%.

On March 8, 2023, we issued US$700 million three-year fixed rate notes, which include the right for us to call at par after the first year. A corresponding fix-to-floating cancellable swap was also executed which gives the swap counterparty a similar right to cancel the swap after the first year. This swap has a fixed rate of 6.0%.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via the execution of floating-to-fixed interest rate swaps with an average swap rate of 2.7%.

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 natural gas liquids (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 the revaluation of outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, RSUs. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

TOTAL DERIVATIVE INSTRUMENTS

We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. (ISDA) 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 Consolidated Statements of Financial Position location and carrying value of our derivative instruments, as well as the maximum potential settlement amounts, in the event of the specific circumstances described above. All amounts are presented gross in the Consolidated Statements of Financial Position.


September 30, 2023	Derivative Instruments Used as Cash Flow Hedges	Derivative Instruments Used as Fair Value Hedges	Non- Qualifying Derivative Instruments	Total Gross Derivative Instruments as Presented	Amounts Available for Offset	Total Net Derivative Instruments
(millions of Canadian dollars)
Other current assets
Foreign exchange contracts	—	71	32	103	(25)	78
Interest rate contracts	318	—	66	384	(3)	381
Commodity contracts	—	—	206	206	(153)	53

	318	71	304	693	(181)	512
Deferred amounts and other assets
Foreign exchange contracts	—	31	109	140	(90)	50
Interest rate contracts	130	—	19	149	—	149
Commodity contracts	—	—	57	57	(36)	21

	130	31	185	346	(126)	220
Other current liabilities
Foreign exchange contracts	—	(49)	(163)	(212)	25	(187)
Interest rate contracts	—	—	(3)	(3)	3	—
Commodity contracts	(19)	—	(343)	(362)	153	(209)
Other contracts	—	—	(2)	(2)	—	(2)
	(19)	(49)	(511)	(579)	181	(398)
Other long-term liabilities
Foreign exchange contracts	—	(36)	(1,004)	(1,040)	90	(950)
Interest rate contracts	(2)	—	—	(2)	—	(2)
Commodity contracts	(10)	—	(166)	(176)	36	(140)
Other contracts	(1)	—	(1)	(2)	—	(2)
	(13)	(36)	(1,171)	(1,220)	126	(1,094)
Total net derivative asset/(liability)
Foreign exchange contracts	—	17	(1,026)	(1,009)	—	(1,009)
Interest rate contracts	446	—	82	528	—	528
Commodity contracts	(29)	—	(246)	(275)	—	(275)
Other contracts	(1)	—	(3)	(4)	—	(4)
	416	17	(1,193)	(760)	—	(760)


December 31, 2022	Derivative Instruments Used as Cash Flow Hedges	Derivative Instruments Used as Fair Value Hedges	Non- Qualifying Derivative Instruments	Total Gross Derivative Instruments as Presented	Amounts Available for Offset	Total Net Derivative Instruments
(millions of Canadian dollars)
Other current assets
Foreign exchange contracts	—	—	46	46	(41)	5
Interest rate contracts	649	—	11	660	—	660
Commodity contracts	—	—	302	302	(182)	120
Other contracts	—	—	7	7	—	7
	649	—	366	1,015	(223)	792
Deferred amounts and other assets
Foreign exchange contracts	—	156	153	309	(138)	171
Interest rate contracts	254	—	—	254	—	254
Commodity contracts	—	—	61	61	(25)	36
Other contracts	1	—	2	3	—	3
	255	156	216	627	(163)	464
Other current liabilities
Foreign exchange contracts	—	(42)	(524)	(566)	41	(525)

Commodity contracts	(48)	—	(284)	(332)	182	(150)

	(48)	(42)	(808)	(898)	223	(675)
Other long-term liabilities
Foreign exchange contracts	—	—	(1,116)	(1,116)	138	(978)
Interest rate contracts	(3)	—	(1)	(4)	—	(4)
Commodity contracts	(37)	—	(133)	(170)	25	(145)

	(40)	—	(1,250)	(1,290)	163	(1,127)
Total net derivative asset/(liability)
Foreign exchange contracts	—	114	(1,441)	(1,327)	—	(1,327)
Interest rate contracts	900	—	10	910	—	910
Commodity contracts	(85)	—	(54)	(139)	—	(139)
Other contracts	1	—	9	10	—	10
	816	114	(1,476)	(546)	—	(546)

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


September 30, 2023	2023	2024	2025	2026	2027	Thereafter	Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)	114	1,000	500	—	—	—	1,614
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)	1,593	5,440	4,955	4,325	3,647	2,886	22,846
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	7	30	30	28	32	—	127

Foreign exchange contracts - Euro forwards - sell (millions of Euro)	27	91	86	85	81	262	632
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	—	—	84,800	—	—	—	84,800
Interest rate contracts - short-term debt pay fixed rate (millions of Canadian dollars)	2,656	5,645	1,364	1,097	75	39	10,876
Interest rate contracts - short-term debt receive fixed rate (millions of Canadian dollars)	229	946	946	179	—	—	2,300
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	1,726	400	588	—	—	—	2,714
Interest rate contracts - costless collar (millions of Canadian dollars)	—	—	394	11	—	—	405
Equity contracts (millions of Canadian dollars)	—	33	12	—	—	—	45
Commodity contracts - natural gas (billions of cubic feet)	6	45	27	9	7	—	94
Commodity contracts - crude oil (millions of barrels)	5	(3)	—	—	—	—	2

Commodity contracts - power (megawatt per hour) (MW/H)	61	3	(42)	(49)	(53)	(50)	(33)	1

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

Fair Value Derivatives

For foreign exchange derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative is included in Other income/(expense) or Interest expense in the Consolidated Statements of Earnings. The offsetting loss or gain on the hedged item attributable to the hedged risk is included in Other income/(expense) 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,
	2023	2022	2023	2022
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	35	122	(107)	221
Unrealized gain/(loss) on hedged item	(35)	(122)	106	(211)
Realized loss on derivative	(11)	(5)	(34)	(101)
Realized gain on hedged item	—	—	—	85

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

The following table presents the effect of cash flow hedges and fair value 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,
	2023	2022	2023	2022
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	—	1	—	3
Interest rate contracts	313	230	423	1,087
Commodity contracts	20	(16)	56	(27)
Other contracts	(1)	(4)	(3)	(4)
Fair value hedges
Foreign exchange contracts	2	(33)	11	(38)


	334	178	487	1,021
Amount of loss reclassified from AOCI to earnings
Foreign exchange contracts1	—	—	—	13
Interest rate contracts2	40	45	63	187
Commodity contracts3	1	—	—	—
Other contracts4	—	1	1	3
	41	46	64	203

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

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

3Reported within Transportation and other services in the Consolidated Statements of Earnings.

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

We estimate that a gain of $20 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 27 months as at September 30, 2023.

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,
	2023	2022	2023	2022
(millions of Canadian dollars)
Foreign exchange contracts1	(650)	(1,379)	415	(1,752)
Interest rate contracts2	17	17	72	1
Commodity contracts3	(229)	89	(206)	59
Other contracts4	(3)	(3)	(11)	1
Total unrealized derivative fair value gain/(loss), net	(865)	(1,276)	270	(1,691)

1For the respective nine months ended periods, reported within Transportation and other services revenues (2023 - $645 million gain; 2022 - $375 million loss) and Other income/(expense) (2023 - $230 million loss; 2022 - $1,377 million loss) in the Consolidated Statements of Earnings.

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

3For the respective nine months ended periods, reported within Transportation and other services revenues (2023 - $85 million loss; 2022 - $12 million gain), Commodity sales (2023 - $75 million gain; 2022 - $151 million gain), Commodity costs (2023 - $136 million loss; 2022 - $116 million loss) and Operating and administrative expense (2023 - $60 million loss; 2022 - $12 million gain) in the Consolidated Statements of Earnings.

4Reported 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. Our shelf prospectuses with securities regulators enable 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 were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at September 30, 2023. As a result, all credit facilities are available to us and the banks are obligated to fund 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 the 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, 2023	December 31, 2022
(millions of Canadian dollars)
Canadian financial institutions	495	644
US financial institutions	226	277
European financial institutions	123	334
Asian financial institutions	120	224
Other1	66	105
	1,030	1,584

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

As at September 30, 2023, we did not provide any letters of credit in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on derivative asset exposures as at September 30, 2023 and December 31, 2022.

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, the assessment of credit ratings and netting arrangements. Within Enbridge Gas, 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 derivatives and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.

FAIR VALUE OF FINANCIAL INSTRUMENTS

We categorize our financial 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 financial instruments measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a financial instrument is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations, US and Canadian treasury bills, investments in exchange-traded funds held by our captive insurance subsidiaries, as well as restricted long-term investments in exchange-traded funds that are held in trust in accordance with the CER's regulatory requirements under the Land Matters Consultation Initiative (LMCI).

Level 2

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

We have also categorized the fair value of our long-term debt, investments in debt securities held by our captive insurance subsidiaries, and restricted long-term investments in Canadian government bonds held in trust in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. When possible, the fair value of our restricted long-term investments is based on quoted market prices for similar instruments and, if not available, based on broker quotes.

Level 3

Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives' fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on the 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, as well as physical forward commodity contracts. We do not have any other financial instruments categorized in Level 3.

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

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


September 30, 2023	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	103	—	103
Interest rate contracts	—	384	—	384
Commodity contracts	58	36	112	206

	58	523	112	693
Long-term derivative assets
Foreign exchange contracts	—	140	—	140
Interest rate contracts	—	149	—	149
Commodity contracts	—	16	41	57

	—	305	41	346
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(212)	—	(212)
Interest rate contracts	—	(3)	—	(3)
Commodity contracts	(93)	(50)	(219)	(362)
Other contracts	—	(2)	—	(2)
	(93)	(267)	(219)	(579)
Long-term derivative liabilities
Foreign exchange contracts	—	(1,040)	—	(1,040)
Interest rate contracts	—	(2)	—	(2)
Commodity contracts	—	(20)	(156)	(176)
Other contracts	—	(2)	—	(2)
	—	(1,064)	(156)	(1,220)
Total net financial asset/(liability)
Foreign exchange contracts	—	(1,009)	—	(1,009)
Interest rate contracts	—	528	—	528
Commodity contracts	(35)	(18)	(222)	(275)
Other contracts	—	(4)	—	(4)
	(35)	(503)	(222)	(760)


December 31, 2022	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	46	—	46
Interest rate contracts	—	660	—	660
Commodity contracts	65	90	147	302
Other contracts	—	7	—	7
	65	803	147	1,015
Long-term derivative assets
Foreign exchange contracts	—	309	—	309
Interest rate contracts	—	254	—	254
Commodity contracts	—	17	44	61
Other contracts	—	3	—	3
	—	583	44	627
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(566)	—	(566)

Commodity contracts	(60)	(77)	(195)	(332)

	(60)	(643)	(195)	(898)
Long-term derivative liabilities
Foreign exchange contracts	—	(1,116)	—	(1,116)
Interest rate contracts	—	(4)	—	(4)
Commodity contracts	—	(38)	(132)	(170)

	—	(1,158)	(132)	(1,290)
Total net financial asset/(liability)
Foreign exchange contracts	—	(1,327)	—	(1,327)
Interest rate contracts	—	910	—	910
Commodity contracts	5	(8)	(136)	(139)
Other contracts	—	10	—	10
	5	(415)	(136)	(546)

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


September 30, 2023	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	1.69	10.93	4.67	$/mmbtu2
Crude	(32)	Forward crude price	83.38	120.51	98.08	$/barrel

Power	(77)	Forward power price	30.75	160.92	65.98	$/MW/H
Commodity contracts - physical1
Natural gas	(13)	Forward gas price	1.58	23.92	5.04	$/mmbtu2
Crude	(19)	Forward crude price	84.35	128.65	107.59	$/barrel

Power	(61)	Forward power price	24.47	164.58	61.70	$/MW/H
	(222)

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

2One 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,
	2023	2022
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(136)	(108)
Total gain/(loss)
Included in earnings1	(205)	41
Included in OCI	—	(28)
Settlements	119	(2)
Level 3 net derivative liability at end of period	(222)	(97)

1Reported 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, 2023 or December 31, 2022.

NET INVESTMENT HEDGES

We currently have designated a portion of our US dollar-denominated debt as a hedge of our net investment in US dollar-denominated investments and subsidiaries.

During the nine months ended September 30, 2023 and 2022, we recognized unrealized foreign exchange gains of $86 million and losses of $1,191 million, respectively, on the translation of US dollar-denominated debt, in OCI. No unrealized gains or losses on the change in fair value of our outstanding foreign exchange forward contracts were recognized in OCI during the nine months ended September 30, 2023 and 2022. No realized gains or losses associated with the settlement of foreign exchange forward contracts were recognized in OCI during the nine months ended September 30, 2023 and 2022. During the nine months ended September 30, 2023 and 2022, we recognized a realized loss of $44 million and nil, respectively, associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.

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 $209 million and $102 million as at September 30, 2023 and December 31, 2022, respectively.

As at September 30, 2023, we had investments with a fair value of $635 million included in Restricted long-term investments in the Consolidated Statements of Financial Position (December 31, 2022 - $593 million). These securities are classified as available-for-sale and represent restricted funds which are collected from customers and held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements.

We had restricted long-term investments held in trust totaling $252 million as at September 30, 2023, which are classified as Level 1 in the fair value hierarchy (December 31, 2022 - $236 million). We also had restricted long-term investments held in trust totaling $383 million (cost basis - $474 million) and $357 million (cost basis - $437 million) as at September 30, 2023 and December 31, 2022, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding losses of $44 million and $7 million on these investments for the three and nine months ended September 30, 2023, respectively (2022 - gains of $11 million and losses of $120 million, respectively).

We have wholly-owned captive insurance subsidiaries whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. As at September 30, 2023, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiaries was $273 million and $353 million, respectively (December 31, 2022 - $335 million and $298 million, respectively). Our investments in debt securities had a cost basis of $346 million as at September 30, 2023 (December 31, 2022 - $295 million). These investments in equity funds and debt securities are recognized at fair value, classified as Level 1 and Level 2 in the fair value hierarchy, respectively, and are recorded in Other current assets and Long-term investments in the Consolidated Statements of Financial Position. There were unrealized holding losses of $8 million and gains of $14 million for the three and nine months ended September 30, 2023, respectively (2022 - losses of $13 million and $40 million, respectively).

As at September 30, 2023 and December 31, 2022, our long-term debt including finance lease liabilities had a carrying value of $76.3 billion and $79.3 billion, respectively, before debt issuance costs and a fair value of $68.9 billion and $73.5 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at September 30, 2023 and December 31, 2022, the non-current notes receivable had a carrying value of $660 million and $752 million, respectively, which also approximates their fair value.

The fair value of financial assets and liabilities other than derivative instruments, certain long-term investments in other entities, restricted long-term investments, investments held by our captive insurance subsidiaries, long-term debt and non-current notes receivable described above approximate their carrying value due to the short period to maturity.

9. INCOME TAXES

The effective income tax rates for the three months ended September 30, 2023 and 2022 were 17.0% and 18.7%, respectively, and for the nine months ended September 30, 2023 and 2022 was 20.5%.

The period-over-period changes in the effective income tax rates are due to an increase in earnings attributable to noncontrolling interests, a decrease in US minimum tax, and the effects of rate-regulated accounting for income taxes, relative to the change in earnings over the comparative periods, offset by the absence of the benefit of a Pennsylvania state corporate tax rate decrease recorded in the three months ended September 30, 2022.

10. OTHER INCOME/(EXPENSE)


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Gain on dispositions	4	1	15	—
Realized foreign currency gain	31	106	177	110
Unrealized foreign currency loss	(652)	(1,129)	(348)	(1,345)
Net defined pension and OPEB credit	34	59	101	176
Other	118	80	267	135
	(465)	(883)	212	(924)

11. CONTINGENCIES

LITIGATION

We and our subsidiaries are subject to 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.

AUX SABLE

On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim.

On November 27, 2019, the counterparty filed an amended amended claim providing further particulars of its claim against Aux Sable, increasing its damages claimed, and adding defendants Aux Sable Liquid Products Inc. and Aux Sable Extraction LLC (general partners of the previously existing defendants). Aux Sable filed an amended Statement of Defence responding to the amended amended claim on January 31, 2020.

During the third quarter of 2023, a provision was recognized in relation to the claim impacting Enbridge's share of earnings from Aux Sable. While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on our 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.

INSURANCE

We maintain an insurance program for us, our subsidiaries and certain of our affiliates to mitigate a certain portion of our risks. However, not all potential risks arising from our operations are insurable, or are insured by us as a result of availability, high premiums and for various other reasons. We self-insure a significant portion of certain risks through our wholly-owned captive insurance subsidiaries, and our insurance coverage is subject to terms and conditions, exclusions and large deductibles or self-insured retentions which may reduce or eliminate coverage in certain circumstances.

Our insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, terms, policy limits and/or deductibles, can vary substantially. We can give no assurance that we will be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable. In such case, we may decide to self-insure additional risks.

In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among entities on an equitable basis based on an insurance allocation agreement we have entered into with us and other subsidiaries. Insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices and the selection of estimated loss among estimates derived using different methods.

12. SUBSEQUENT EVENTS

AITKEN CREEK GAS STORAGE

On November 1, 2023, through a wholly-owned Canadian subsidiary, we acquired a 93.8% interest in Aitken Creek Gas Storage Facility and a 100% interest in Aitken Creek North Gas Storage Facility (collectively, Aitken Creek), located in British Columbia, Canada, for $400 million of cash plus payment for derivative contracts and gas inventory, subject to other customary closing adjustments. The acquired assets are included in our Gas Transmission and Midstream segment.

HOHE SEE & ALBATROS

In November 2023, we signed a definitive agreement to acquire an additional 24.45% interest in the Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities (the Offshore Wind Facilities), through the acquisition of a 49% interest in Enbridge Renewable Infrastructure Investments S.à.r.l (ERII), for $391 million (€267 million) of cash and assumed debt of $524 million (€358 million), subject to customary closing adjustments, bringing our interest in the Offshore Wind Facilities to 49.9%. The Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities are located approximately 100 kilometers off the northern coast of Germany and came into service in 2019 and 2020, respectively. Subsequent to the purchase, our interest in ERII will be consolidated and our interest in the Offshore Wind Facilities will continue to be accounted for as an equity method investment included in the Renewable Power Generation segment.

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, 2022.

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 United States (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

MAINLINE TOLLING AGREEMENT

Enbridge Inc. (Enbridge) has reached an agreement in principle on a negotiated settlement (the Settlement) with shippers for tolls on its Mainline pipeline system. The Settlement covers both the Canadian and US portions of the Mainline and would see the Mainline continuing to operate as a common carrier system available to all shippers on a monthly nomination basis. The Settlement is subject to regulatory and other approvals and the term is seven and a half years through the end of 2028, with new interim tolls effective on July 1, 2023.

The Settlement includes:

•an International Joint Toll (IJT), for heavy crude oil movements from Hardisty to Chicago, comprised of a Canadian Mainline Toll of $1.65 per barrel plus a Lakehead System Toll of US$2.57 per barrel, plus the applicable Line 3 Replacement surcharge;

•toll escalation for operation, administration, and power costs tied to US consumer price and power indices;

•tolls continue to be distance and commodity adjusted, and utilize a dual currency IJT; and

•a financial performance collar providing incentives for Enbridge to optimize throughput and cost, but also providing downside protection in the event of extreme supply or demand disruptions or unforeseen operating cost exposure. This performance collar is intended to ensure the Mainline earns 11% to 14.5% returns, on a deemed 50% equity capitalization, which is similar to the returns earned on average during the previous tolling agreement.

Approximately 70% of Mainline deliveries are tolled under this settlement, while approximately 30% of deliveries are tolled on a full path basis to markets downstream of the Mainline. The other continuing feature is that the Mainline toll flexes up or down US$0.035 per barrel for 50,000 barrel per day changes in throughput.

The expected financial outcome from this settlement is in line with previously reported financial results after taking into consideration the previously recognized provision, inflationary cost adjustments and increased volumes. Enbridge expects to file the Settlement with the Canada Energy Regulator (CER) by the end of the year.

On May 24, 2023, Enbridge filed an Offer of Settlement with the Federal Energy Regulatory Commission (FERC) for the Lakehead System. In addition to resolving litigation related to the Index portion of the Lakehead System rate, the Settlement also includes a depreciation truncation date of December 31, 2048 for the rate base applicable to the Index and Facilities Surcharge and agreement on the terms for future recovery through the Facilities Surcharge of costs related to two Line 5 projects: the Wisconsin Relocation Project and the Straits of Mackinac Tunnel. The Settlement Judge certified the Settlement on June 23, 2023 and the Settlement is awaiting approval by the FERC Commissioners. Lakehead System tolls will be updated to reflect the new Settlement pending approval by the FERC.

ACQUISITIONS

US Gas Utilities

On September 5, 2023, we announced that Enbridge had entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina, Incorporated, for an aggregate purchase price of $19.1 billion (US$14.0 billion), comprised of $12.8 billion (US$9.4 billion) of cash consideration and $6.3 billion (US$4.6 billion) of assumed debt, subject to customary closing adjustments (together, the Acquisitions). If completed, the Acquisitions will create North America's largest natural gas utility platform delivering over 9 billion cubic feet (bcf) per day to approximately 7 million customers across multiple regulatory jurisdictions. The Acquisitions are expected to close in 2024, subject to the satisfaction of customary closing conditions including the receipt of certain regulatory approvals, which are not cross conditional.

On September 8, 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions. Refer to Financing Update for further details on the debt issuances and credit facility obtained to support the Acquisitions.

Aitken Creek Gas Storage

Hohe See & Albatros

Acquisition of RNG Facilities

In November 2023, Enbridge entered into a definitive agreement to acquire seven operating landfill gas-to-renewable natural gas (RNG) production facilities located in Texas and Arkansas for total consideration of $1.7 billion (US$1.2 billion), of which $0.7 billion (US$0.5 billion) is payable at close and $1.0 billion (US$0.7 billion) is payable within two years. Combined RNG production of the facilities is approximately 4.5 bcf per year. The transaction is expected to close in the first quarter of 2024, subject to the satisfaction of customary closing conditions.

GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS

Maritimes & Northeast Pipeline

The current toll settlement agreement for the Canadian portion of Maritimes & Northeast (M&N) Pipeline expires in December 2023. Settlement negotiations with M&N Pipeline shippers are ongoing with the objective of reaching a toll settlement which would be effective January 1, 2024. It is expected that a settlement agreement will be filed in the fourth quarter of 2023 with the CER for review and approval. A CER decision is expected in the first quarter of 2024.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

Incentive Regulation Rate Application

In October 2022, Enbridge Gas Inc. (Enbridge Gas) filed its application with the Ontario Energy Board (OEB) to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application initially sought approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term (2025–2028). A third phase (Phase 3) has been established with the OEB as part of the Phase 1 Partial Settlement Proposal (Settlement Proposal).

On August 17, 2023, the OEB approved the Settlement Proposal to support the determination of just and reasonable rates effective January 1, 2024. Items resolved in whole or in part include:

•additions to the rate base up to and including 2022;

•interest rates on debt and return on equity;

•deferral and variance accounts;

•Indigenous engagement; and

•rate implementation approach for 2024.

The Phase 1 hearing to examine issues not resolved as part of the Settlement Proposal has concluded. A decision from the OEB on the outstanding Phase 1 issues is expected in the fourth quarter of 2023. Phase 2 will establish and determine the 2025-2028 incentive rate mechanism, and gas cost and unregulated storage allocation issues. Phase 3 will address cost allocation and the harmonization of rates and rate classes between legacy rate zones.

Purchase Gas Variance

The Purchase Gas Variance Account (PGVA) captures the difference between actual and forecasted natural gas prices reflected in rates. Account balances are typically recovered or refunded over a prospective 12-month period through Quarterly Rate Adjustment Mechanism (QRAM) applications.

In March 2023, the April 1, 2023 QRAM application was filed and approved by the OEB, which included an adjustment to the prior rate mitigation approved as part of the July 1, 2022 QRAM. The recovery of the outstanding PGVA balance from the extended recovery period approved as part of the July 1, 2022 QRAM will now be completed by March 31, 2024. In June and September 2023, the July 1, 2023 and October 1, 2023 QRAM applications, respectively, were filed and approved by the OEB with no adjustments to the prior period rate mitigation plans and they did not include any additional rate mitigation measures.

As at September 30, 2023, Enbridge Gas' PGVA receivable balance was $266 million.

FINANCING UPDATE

In March 2023, we closed a two-tranche US debt offering consisting of three-year senior notes, callable at par after one year at our option, and 10-year sustainability-linked senior notes, for an aggregate principal amount of US$3.0 billion, which mature in March 2026 and March 2033, respectively.

In March 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to $2.5 billion and in July 2023, the facility's maturity date was extended to July 2025, which includes a one-year term out provision from July 2024.

On April 15, 2023 call date, we redeemed at par all of the outstanding US$600 million five-year callable, 6.38% fixed-to-floating rate subordinated notes that carried an original maturity date of April 2078.

In May 2023, we closed a three-tranche debt offering consisting of five-year medium-term notes, 10-year sustainability-linked medium-term notes, and 30-year medium-term notes for an aggregate principal amount of $1.5 billion, which mature in May 2028, May 2033, and May 2053, respectively.

In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024.

In August 2023, Enbridge Pipelines Inc. closed an offering of $350 million 30-year medium-term notes which mature in August 2053.

In September 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions.

In September 2023, we closed two offerings, each consisting of a tranche of 60-year non-call five-year fixed-to-fixed subordinated notes and a tranche of 60-year non-call 10-year fixed-to-fixed subordinated notes, all of which mature in January 2084, for aggregate principal amounts of US$2.0 billion and $1.0 billion. The proceeds from the offerings are intended to finance a portion of the aggregate cash consideration payable for the Acquisitions.

These financing activities, in combination with the financing activities executed in 2022, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects and other operating working capital requirements without requiring access to the capital markets for the next 12 months, should market access be restricted or pricing be unattractive. Refer to Liquidity and Capital Resources.

As at September 30, 2023, after adjusting for the impact of floating-to-fixed interest rate swap hedges, none of our total debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements - Note 8 - Risk Management and Financial Instruments for more information on our interest rate hedging program.

RESULTS OF OPERATIONS


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
Liquids Pipelines	2,247	1,946	7,061	6,093
Gas Transmission and Midstream	973	2,251	3,220	4,384
Gas Distribution and Storage	271	286	1,354	1,368
Renewable Power Generation	30	105	295	389
Energy Services	(106)	(70)	(83)	(348)
Eliminations and Other	(579)	(935)	(44)	(1,284)
Earnings before interest, income taxes and depreciation and amortization1	2,836	3,583	11,803	10,602
Depreciation and amortization	(1,164)	(1,076)	(3,447)	(3,195)
Interest expense	(921)	(806)	(2,709)	(2,316)
Income tax expense	(128)	(318)	(1,157)	(1,044)
Earnings attributable to noncontrolling interests	(2)	(21)	(117)	(61)
Preference share dividends	(89)	(83)	(260)	(330)
Earnings attributable to common shareholders	532	1,279	4,113	3,656
Earnings per common share attributable to common shareholders	0.26	0.63	2.02	1.80
Diluted earnings per common share attributable to common shareholders	0.26	0.63	2.02	1.80

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

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

Earnings attributable to common shareholders were negatively impacted by $655 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•the absence in 2023 of a gain of $1,076 million ($732 million after-tax) on the closing of the joint venture merger transaction with Phillips 66 (P66) realigning our indirect economic interests in Gray Oak Pipeline LLC (Gray Oak) and DCP Midstream, LP (DCP);

•a non-cash, net unrealized loss of $66 million ($51 million after-tax) in 2023, compared to a net gain of $58 million ($44 million after-tax) in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, and exposure to movements in commodity prices;

•a provision adjustment of $124 million ($95 million after-tax) related to a litigation matter;

•the absence in 2023 of a deferred tax benefit of $95 million recognized as a result of the reduced Pennsylvania state corporate income tax;

•the absence in 2023 of a net positive adjustment of $85 million ($75 million after-tax) due to the release of reserves associated with our enterprise insurance strategy; and

•transaction costs of $21 million ($16 million after-tax) incurred during the quarter ended September 30, 2023 as a result of the Acquisitions.

The factors above were partially offset by a non-cash, net unrealized derivative fair value loss of $732 million ($552 million after-tax) in 2023, compared with a net unrealized loss of $1,334 million ($1,021 million after-tax) in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.

The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of our comprehensive economic hedging program to mitigate foreign exchange, interest rate and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on 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 $92 million decrease in earnings attributable to common shareholders is primarily explained by:

•lower contributions from our Liquids Pipelines segment as a result of new Mainline System interim tolls effective July 1, 2023 and lower volumes on the Flanagan South Pipeline due to decreased demand;

•a reduction in earnings from our Gas Transmission and Midstream segment primarily due to our decreased interest in DCP as a result of a joint venture merger transaction with P66 that closed in the third quarter of 2022;

•lower commodity prices impacting the DCP and Aux Sable joint ventures in our Gas Transmission and Midstream segment;

•higher storage demand and transportation costs in our Gas Distribution and Storage segment which represents a partial reversal of previously favorable timing of recognition of these costs; and

•higher interest expense primarily due to higher interest rates and higher average principal; partially offset by

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; and

•higher contributions from our Liquids Pipelines segment due to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and higher volumes from the Enbridge Ingleside Energy Center (EIEC) due to higher demand.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

Earnings attributable to common shareholders were positively impacted by $498 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized derivative fair value gain of $376 million ($287 million after-tax) in 2023, compared with a net unrealized loss of $1,751 million ($1,340 million after-tax) in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate, and commodity price risks;

•a net positive adjustment to crude oil and natural gas inventories in our Energy Services business segment of $4 million ($3 million after-tax) in 2023, compared with a net negative adjustment of $67 million ($50 million after-tax) in 2022;

•the receipt of a litigation claim settlement of $68 million ($52 million after-tax) in 2023;

•a net unrealized gain of $14 million ($12 million after-tax) in 2023, compared with a net loss of $39 million ($33 million after-tax) in 2022, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries;

•the absence in 2023 of an impairment of $44 million ($34 million after-tax) for lease assets due to office relocation plans;

•the absence in 2023 of an asset impairment loss of $40 million ($30 million after-tax) relating to the MacKay River line within our Alberta Regional Oil Sands System; and

•a non-cash, net positive equity earnings adjustment of $5 million ($4 million after-tax) in 2023, compared to a net negative adjustment of $30 million ($22 million after-tax) in 2022 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP and Aux Sable.

The factors above were partially offset by:

•the absence in 2023 of a gain of $1,076 million ($732 million after-tax) on the closing of the joint venture merger transaction with P66 realigning our indirect economic interests in Gray Oak and DCP;

•a realized loss of $638 million ($479 million after-tax) due to termination of foreign exchange hedges, as foreign exchange risks inherent within the Competitive Toll Settlement (CTS) framework are not present in the negotiated Mainline tolling agreement;

•a provision adjustment of $124 million ($95 million after-tax) related to a litigation matter;

•the absence in 2023 of a deferred tax benefit of $95 million recognized as a result of the reduced Pennsylvania state corporate income tax;

•a non-cash, net unrealized loss of $13 million ($10 million after-tax) in 2023, compared to a net gain of $22 million ($17 million after-tax) in 2022, 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

•transaction costs of $21 million ($16 million after-tax) incurred during the quarter ended September 30, 2023 as a result of the Acquisitions.

After taking into consideration the factors above, the remaining $41 million decrease in earnings attributable to common shareholders is primarily explained by the following significant business factors:

•higher operating and administrative costs in our Gas Transmission and Midstream and Gas Distribution and Storage segments;

•lower commodity prices impacting the DCP and Aux Sable joint ventures in our Gas Transmission and Midstream segment;

•higher interest expense primarily due to higher interest rates and higher average principal; and

•higher depreciation and amortization due to assets placed into service in the second half of 2022; partially offset by

•higher contributions from the Mainline System in our Liquids Pipelines segment driven by increased volumes due to increased crude demand, net of a lower Line 3 Replacement (L3R) surcharge and lower Mainline System tolls as a result of new interim tolls effective July 1, 2023;

•higher contributions from our Liquids Pipelines segment due to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and the EIEC due to higher demand;

•the recognition of revenues in our Gas Transmission and Midstream segment attributable to the Texas Eastern Transmission, LP (Texas Eastern) rate case settlement;

•higher distribution charges at our Gas Distribution and Storage segment resulting from increases in rates and customer base as well as higher demand in the contract market;

•higher contributions from our Energy Services segment primarily due to the expiration of transportation commitments and favorable margins due to less pronounced market structure backwardation; and

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022.

BUSINESS SEGMENTS

LIQUIDS PIPELINES


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	2,247	1,946	7,061	6,093

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was positively impacted by $245 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized loss of $38 million in 2023, compared with a net unrealized loss of $290 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.

After taking into consideration the factors above, the remaining $56 million increase is primarily explained by the following significant business factors:

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; and

•higher contributions from the Gulf Coast and Mid-Continent System due primarily to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and higher volumes from the EIEC due to higher demand; partially offset by

•lower Mainline System tolls as a result of new interim tolls effective July 1, 2023 and a lower L3R surcharge; and

•lower volumes on the Flanagan South Pipeline.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was positively impacted by $399 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized gain of $592 million in 2023, compared with a net unrealized loss of $364 million in 2022, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks;

•the receipt of a litigation claim settlement of $68 million in 2023;

•the absence in 2023 of an asset impairment loss of $40 million relating to MacKay River line within our Alberta Regional Oil Sands System; partially offset by

•a realized loss of $638 million due to termination of foreign exchange hedges, as foreign exchange risks inherent within the CTS framework are not present in the negotiated Mainline tolling agreement.

After taking into consideration the factors above, the remaining $569 million increase is primarily explained by the following significant business factors:

•higher Mainline System ex-Gretna average throughput of 3.0 mmbpd in 2023 as compared to 2.9 mmbpd in 2022, net of a lower L3R surcharge and lower Mainline System tolls as a result of new interim tolls effective July 1, 2023;

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; and

•higher power costs as a result of increased volumes and power prices.

GAS TRANSMISSION AND MIDSTREAM


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	973	2,251	3,220	4,384

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was negatively impacted by $1,212 million due to certain infrequent or other non-operating factors, primarily explained by:

•the absence in 2023 of a gain of $1,076 million on the closing of the joint venture merger transaction with P66 realigning our indirect economic interests in Gray Oak and DCP; and

•a provision adjustment of $124 million related to a litigation matter.

The remaining $66 million decrease is primarily explained by the following significant business factors:

•lower commodity prices impacting our DCP and Aux Sable joint ventures;

•a reduction in earnings from our investment in DCP as a result of our decreased interest due to the joint venture merger transaction with P66 that closed during the third quarter of 2022; and

•lower AECO-Chicago basis differential impacting our investment in Alliance Pipeline; partially offset by

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; and

•contributions from the acquisition of Tres Palacios Holdings LLC (Tres Palacios) in the second quarter of 2023.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was negatively impacted by $1,178 million due to certain infrequent or other non-operating factors, primarily explained by:

•the absence in 2023 of a gain of $1,076 million on the closing of the joint venture merger transaction with P66 realigning our indirect economic interests in Gray Oak and DCP; and

•a provision adjustment of $124 million related to a litigation matter; partially offset by

•a non-cash, net positive equity earnings adjustment of $5 million in 2023, compared to a net negative adjustment of $30 million in 2022 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP and Aux Sable.

The remaining $14 million increase is primarily explained by the following significant business factors:

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022;

•the recognition of revenues attributable to the Texas Eastern rate case settlement effective for 2023;

•favorable contracting on our US Gas Transmission and Storage assets; and

•contributions from the Tres Palacios acquisition in the second quarter of 2023; partially offset by

•a reduction in earnings from our investment in DCP as a result of our decreased interest due to the joint venture merger transaction with P66 that closed during the third quarter of 2022;

•lower commodity prices impacting our DCP and Aux Sable joint ventures;

•higher operating and administrative costs; and

•lower AECO-Chicago basis differential impacting our investment in Alliance Pipeline.

GAS DISTRIBUTION AND STORAGE


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	271	286	1,354	1,368

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was negatively impacted by $15 million primarily due to the following significant business factors:

•higher storage demand and transportation costs of $35 million which represents a partial reversal of previously favorable timing of recognition of these costs; partially offset by

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

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was negatively impacted by $14 million primarily due to the following significant business factors:

•when compared with the normal weather forecast embedded in rates, warmer weather in 2023 and colder weather in 2022 negatively impacted EBITDA by approximately $68 million year over year; and

•higher operating and administrative costs primarily due to higher costs for line locates, higher integrity spend and higher pension related costs; partially offset by

•higher distribution charges resulting from increases in rates and customer base as well as higher demand in the contract market.

RENEWABLE POWER GENERATION


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	30	105	295	389

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was negatively impacted by $81 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized loss of $83 million in 2023, compared with a net unrealized gain of $2 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks.

The remaining $6 million increase is primarily explained by the following significant business factors:

•fees earned on certain wind and solar development contracts; partially offset by

•weaker wind resources and lower energy pricing at European offshore wind facilities.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was negatively impacted by $84 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized loss of $79 million in 2023, compared with a net unrealized gain of $6 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks.

The remaining $10 million decrease is primarily explained by the following significant business factors:

•weaker wind resources at North American and European wind facilities; and

•lower energy pricing at European offshore wind facilities; partially offset by

•fees earned on certain wind and solar development contracts; and

•contributions from the Saint-Nazaire Offshore Wind Project, which reached full operating capacity in December 2022.

ENERGY SERVICES


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Loss before interest, income taxes and depreciation and amortization	(106)	(70)	(83)	(348)

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, 2023, compared with the three months ended September 30, 2022

EBITDA was negatively impacted by $130 million due to certain non-operating factors, primarily explained by a non-cash, net unrealized loss of $66 million in 2023, compared with a net gain of $58 million in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as to manage the exposure to movements in commodity prices.

After taking into consideration the factors above, the remaining $94 million increase is primarily explained by:

•expiration of transportation commitments;

•favorable margins realized on facilities where we hold capacity obligations and storage opportunities; and

•less pronounced market structure backwardation as compared to the same period of 2022.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was positively impacted by $37 million due to certain non-operating factors, primarily explained by:

•a net positive adjustment to crude oil and natural gas inventories of $4 million in 2023, compared with a net negative adjustment of $67 million in 2022; partially offset by

•a non-cash, unrealized loss of $13 million in 2023, compared with an unrealized gain of $22 million in 2022, 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 $228 million increase is primarily explained by the same significant business factors as discussed in the three months ended September 30, 2023 results.

ELIMINATIONS AND OTHER


	Three months ended September 30,		Nine months ended September 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Loss before interest, income taxes and depreciation and amortization	(579)	(935)	(44)	(1,284)

Eliminations and Other includes operating and administrative costs that are not allocated to business segments, and the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. Eliminations and Other also includes the impact of new business development activities and corporate investments.

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was positively impacted by $311 million due to certain infrequent or non-operating factors, primarily explained by:

•a non-cash, net unrealized loss of $652 million in 2023, compared with a net loss of $1,046 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk; partially offset by

•the absence in 2023 of a net positive adjustment of $85 million due to the release of reserves associated with our enterprise insurance strategy; and

•transaction costs of $21 million incurred during the quarter ended September 30, 2023 as a result of the Acquisitions.

After taking into consideration the non-operating factors above, the remaining $45 million increase is primarily explained by higher investment income and higher realized foreign exchange gains on hedge settlements in 2023.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was positively impacted by $1,279 million due to certain infrequent or non-operating factors, primarily explained by:

•a non-cash, unrealized loss of $250 million in 2023, compared with an unrealized loss of $1,393 million in 2022, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;

•a net unrealized gain of $14 million in 2023, compared with a net loss of $39 million in 2022, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries; and

•the absence in 2023 of an impairment of $44 million for lease assets due to office relocation plans; partially offset by

•transaction costs of $21 million incurred during the quarter ended September 30, 2023 as a result of the Acquisitions.

After taking into consideration the non-operating factors above, the remaining $39 million decrease is primarily explained by lower realized foreign exchange gains on hedge settlements in 2023, as well as the timing of certain operating and administrative cost recoveries from the business units.

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)


GAS TRANSMISSION AND MIDSTREAM
1.	Texas Eastern Venice Extension3	100	%	US$477 million	US$118 million	Pre-construction	2023 - 2024
2.	Texas Eastern Modernization	100	%	US$394 million	US$27 million	Pre-construction	2024 - 2025
3.	T-North Expansion4	100	%	$1.2 billion	$43 million	Pre-construction	2026
4.	Rio Bravo Pipeline5	100	%	US$1.2 billion	US$45 million	Pre-construction	2026
5.	Woodfibre LNG6	30	%	US$1.5 billion	US$245 million	Pre-construction	2027
6.	T-South Expansion4	100	%	$3.6 billion	$44 million	Pre-construction	2028


RENEWABLE POWER GENERATION
7.	Fécamp Offshore Wind7	17.9	%	$692 million	$476 million	Under construction	1Q-2024
				(€471 million)	(€327 million)
8	Calvados Offshore Wind8	21.7	%	$954 million	$295 million	Under construction	2025
				(€645 million)	(€203 million)

1These 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.

2Expenditures to date and status of the project are determined as at September 30, 2023.

3Includes the $37 million Gator Express Project placed into service in August 2023. Total estimated capital cost consists of the reversal and expansion of Texas Eastern's Line 40 expected to be completed in 2024.

4Capital cost estimates will be updated prior to filing the regulatory applications.

5Rio Grande LNG has reached a final investment decision for three liquefaction trains. Current estimated capital cost is based on two liquefaction trains and an update to the estimated capital cost is expected to be provided in 2024.

6Our equity contribution is approximately US$893 million, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated prior to the 60% engineering milestone, at which point Enbridge's preferred return will be set.

7Our equity contribution is $103 million, with the remainder financed through non-recourse project level debt.

8Our equity contribution is $181 million, with the remainder 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, 2022. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.

GAS TRANSMISSION AND MIDSTREAM

Rio Bravo Pipeline

In July 2023, the Rio Grande LNG export facility, owned by NextDecade Corporation (NextDecade), reached a final investment decision. As a result, the construction on our previously announced Rio Bravo Pipeline project is anticipated to proceed after obtaining necessary regulatory approvals. The first phase of the Rio Bravo Pipeline is designed to transport 2.6 bcf per day of natural gas feedstock to NextDecade's Rio Grande LNG export facility in the Port of Brownsville, Texas. The project is expected to achieve commercial operations in 2026.

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 issuances and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures and acquisitions, 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.

We have signed capital obligation contracts for the purchase of services, pipe and other materials totaling approximately $1.2 billion, which are expected to be paid over the next four years.

Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives. 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 issuances 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, 2023:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2024-2028	8,853	1,272	7,581
Enbridge (U.S.) Inc.	2025-2028	8,585	1,064	7,521
Enbridge Pipelines Inc.	2025	2,000	265	1,735
Enbridge Gas Inc.	2025	2,500	1,585	915
Total committed credit facilities		21,938	4,186	17,752

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.

In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024.

As at September 30, 2023, our net available liquidity totaled $20.4 billion (December 31, 2022 - $10.0 billion), consisting of available credit facilities of $17.8 billion (December 31, 2022 - $9.1 billion) and unrestricted cash and cash equivalents of $2.6 billion (December 31, 2022 - $861 million) as reported in the Consolidated Statements of Financial Position.

LONG-TERM DEBT ISSUANCES

During the nine months ended September 30, 2023, we completed the following long-term debt issuances totaling US$5.0 billion and $2.9 billion:


Company	Issue Date				Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
	March 2023	5.70	%	sustainability-linked senior notes due March 20331	US$2,300
	March 2023	5.97	%	senior notes due March 20262	US$700
	May 2023	4.90	%	medium-term notes due May 2028	$600
	May 2023	5.36	%	sustainability-linked medium-term notes due May 20333	$400
	May 2023	5.76	%	medium-term notes due May 2053	$500
	September 2023	8.50	%	fixed-to-fixed subordinated notes due January 20844	US$1,250
	September 2023	8.25	%	fixed-to-fixed subordinated notes due January 20845	US$750
	September 2023	8.75	%	fixed-to-fixed subordinated notes due January 20846	$700
	September 2023	8.50	%	fixed-to-fixed subordinated notes due January 20847	$300



Enbridge Pipelines Inc.
	August 2023	5.82	%	medium-term notes due August 2053	$350

2We have the option to call the notes at par after one year from issuance. Refer to Part 1. Item 1. Financial Statements - Note 8 - Risk Management and Financial Instruments.

5For the initialfive years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 3.79%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 4.04%. Subsequent to year 10, every five years, the Five-Year US Treasury rate is reset. At year 25, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.79%.

LONG-TERM DEBT REPAYMENTS

During the nine months ended September 30, 2023, we completed the following long-term debt repayments totaling US$1.2 billion and $1.3 billion:


Company	Repayment Date				Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
	January 2023	3.94	%	medium-term notes	$275
	February 2023	Floating rate notes1			US$500
	April 2023	6.38	%	fixed-to-floating rate subordinated notes2	US$600
	June 2023	3.94	%	medium-term notes	$450



Enbridge Gas Inc.
	July 2023	6.05	%	medium-term notes	$100
	July 2023	3.79	%	medium-term notes	$250
Enbridge Pipelines (Southern Lights) L.L.C.
	June 2023	3.98	%	senior notes	US$38
Enbridge Pipelines Inc.
	August 2023	3.79	%	medium-term notes	$250
Enbridge Southern Lights LP
	June 2023	4.01	%	senior notes	$9


Tri Global Energy, LLC
	January 2023	10.00	%	senior notes	US$4
	January 2023	14.00	%	senior notes	US$9

1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 40 basis points.

2The five-year callable notes, with an original maturity date of April 2078, were all redeemed at par.

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.

There are no material restrictions on our cash. Total restricted cash of $39 million, as reported on the Consolidated Statements of Financial Position, primarily includes reinsurance security, 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, as at September 30, 2023 and December 31, 2022, we had positive and negative working capital positions of $1.5 billion and $2.1 billion, respectively. During the nine months ended September 30, 2023, the major contributing factor to the positive working capital position was due to settlement of current liabilities, while during the year ended December 31, 2022, the negative working capital position was due to current liabilities associated with our growth capital program. 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,
		2023	2022
(millions of Canadian dollars)
Operating activities		10,389	7,617
Investing activities		(3,503)	(3,158)
Financing activities		(5,146)	(3,785)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		—	63
Net change in cash and cash equivalents and restricted cash		1,740	737

Significant sources and uses of cash for the nine months ended September 30, 2023 and 2022 are summarized below:

Operating Activities

Typically, the primary factors impacting cash provided by operating activities period-over-period include changes in our operating assets and liabilities 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 and cash receipts and payments generally. Cash provided by operating activities is also impacted by changes in earnings and certain infrequent or other non-operating factors, as discussed in Results of Operations, as well as Distributions from equity investments.

Changes in operating assets and liabilities increased period-over-period primarily due to a decline in gas inventory balances in 2023 compared to an increase in 2022 and the timing of natural gas cost recovery through rates, in Enbridge Gas.

Investing Activities

Cash used in investing activities primarily relates to capital expenditures to execute our 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. Cash used in investing activities is also impacted by acquisitions and changes in contributions to, and distributions from, our equity investments. Factors impacting the increase in cash used in investing activities period-over-period primarily include:

•the absence in 2023 of the proceeds received from the completion of a joint venture merger transaction for DCP Midstream, LLC on August 17, 2022; and

•our acquisition of Tres Palacios on April 3, 2023.

The factors above were partially offset by higher equity distributions in 2023 mainly related to our investment in NEXUS Gas Transmission, LLC.

Financing Activities

Cash used in financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances, share redemptions and common share repurchases under our normal course issuer bid (NCIB). Cash used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting the increase in cash used in financing activities period-over-period primarily include:

•net repayments of short-term borrowings and commercial paper and credit facilities in 2023 when compared to net draws during the same period in 2022;

•higher long-term debt repayments in 2023 when compared to the same period in 2022; and

•increase in common share dividend payments due to the increase in the common share dividend rate.

The factors above were partially offset by:

•higher long-term debt issuances in 2023 when compared to the same period in 2022;

•our public offering of common shares, which closed on September 8, 2023, resulting in the issuance of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion, which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions; and

•the absence in 2023 of the redemption of Preference Shares, Series 17 and Series J in the first and second quarters of 2022, respectively.

SUMMARIZED FINANCIAL INFORMATION

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

Consenting SEP notes and EEP notes under Guarantee


SEP Notes1			EEP Notes2
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, 2023, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.

2As at September 30, 2023, 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 2024			3.950% Senior Notes due 2024
4.000% Senior Notes due 2023			2.440% Senior Notes due 2025
0.550% Senior Notes due 2023			3.200% Senior Notes due 2027
3.500% Senior Notes due 2024			5.700% Senior Notes due 2027
2.150% Senior Notes due 2024			6.100% Senior Notes due 2028
2.500% Senior Notes due 2025			4.900% Senior Notes due 2028
2.500% Senior Notes due 2025			2.990% Senior Notes due 2029
4.250% Senior Notes due 2026			7.220% Senior Notes due 2030
1.600% Senior Notes due 2026			7.200% Senior Notes due 2032
5.969% Senior Notes due 2026			6.100% Sustainability-Linked Senior Notes due 2032
3.700% Senior Notes due 2027			3.100% Sustainability-Linked Senior Notes due 2033
3.125% Senior Notes due 2029			5.360% Sustainability-Linked Senior Notes due 2033
2.500% Sustainability-Linked Senior Notes due 2033			5.570% Senior Notes due 2035
5.700% Sustainability-Linked Senior Notes due 2033			5.750% Senior Notes due 2039
4.500% Senior Notes due 2044			5.120% Senior Notes due 2040
5.500% Senior Notes due 2046			4.240% Senior Notes due 2042
4.000% Senior Notes due 2049			4.570% Senior Notes due 2044
3.400% Senior Notes due 2051			4.870% Senior Notes due 2044
			4.100% Senior Notes due 2051
			6.510% Senior Notes due 2052
			5.760% Senior Notes due 2053
			4.560% Senior Notes due 2064

1As at September 30, 2023, the aggregate outstanding principal amount of the Enbridge US dollar-denominated notes was approximately US$13.5 billion.

2As at September 30, 2023, the aggregate outstanding principal amount of the Enbridge Canadian dollar-denominated notes was approximately $11.0 billion.

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

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

Summarized Combined Statement of Earnings


Nine months ended September 30,			2023
(millions of Canadian dollars)

Operating loss			(39)
Earnings			2,269
Earnings attributable to common shareholders			2,009

Summarized Combined Statements of Financial Position


	September 30, 2023	December 31, 2022
(millions of Canadian dollars)
Cash and cash equivalents	1,790	425
Accounts receivable from affiliates	4,176	2,486
Short-term loans receivable from affiliates	3,537	5,232
Other current assets	774	969
Long-term loans receivable from affiliates	46,304	43,873
Other long-term assets	3,404	4,111
Accounts payable to affiliates	2,251	1,375
Short-term loans payable to affiliates	1,355	1,745
Other current liabilities	6,828	8,752
Long-term loans payable to affiliates	35,473	37,626
Other long-term liabilities	47,139	47,447

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.

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

LEGAL AND OTHER UPDATES

Line 5 Easement (Bad River Band)

On July 23, 2019, the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) filed a complaint in the US District Court for the Western District of Wisconsin (the Court) over our Line 5 pipeline and right-of-way across the Bad River Reservation (the Reservation). Only a small portion of the total easements across 12 miles of the Reservation are at issue. The Band alleges that our continued use of Line 5 to transport crude oil and related liquids across the Reservation is a public nuisance under federal and state law and that the pipeline is in trespass on certain tracts of land in which the Band possesses ownership interests. The complaint seeks an Order prohibiting us from using Line 5 to transport crude oil and related liquids across the Reservation and requiring removal of the pipeline from the Reservation. Subsequently amended versions of the complaint also seek recovery of profits-based damages based on an unjust enrichment theory. Enbridge has responded to each claim in the initial and amended complaints with an answer, defenses and counterclaims.

On August 29, 2022, the Government of Canada released a statement formally invoking the dispute settlement provisions of the 1977 Transit Pipelines Treaty in respect of this litigation; reiterating its concerns about the uninterrupted transmission of hydrocarbons through Line 5. On September 7, 2022, the Court issued a decision on cross-motions for summary judgment. The Court determined that the Band's nuisance claim raised factual issues that could not be resolved on summary judgment. The Court further determined that Enbridge is in trespass on 12 parcels on the Reservation and that the Band is entitled to some measure of profits-based damages and to an injunction, with the level of damages and scope of the injunction to be determined at trial, which occurred October 24 through November 1, 2022.

On May 9, 2023, the Band filed an Emergency Motion for Injunctive Relief asking the Court to require Enbridge to purge and shutdown Line 5 on the Reservation due to significant erosion at the Meander. Enbridge responded and a hearing was held on May 18, 2023 in front of Judge Conley who indicated that he did not find the Band had proven imminence but his final ruling on all issues would be provided soon.

On June 26, 2023, the Court issued its Final Order ruling that (1) Enbridge shall adopt and implement its 2022 Monitoring and Shutdown Plan with the Court's modifications by July 5, 2023; (2) Enbridge owes the Band $5,151,668 for past trespass on the 12 allotted parcels; (3) Enbridge must continue to pay money on a quarterly basis using the formula set in its Order as long as Line 5 operates in trespass on the 12 allotted parcels (approximately $400,000 per year); (4) Enbridge must cease operation of Line 5 on any parcel within the Band's tribal territory without a valid right of way by June 16, 2026 and thereafter arrange prompt, reasonable remediation at those sites; and (5) The Court declined to allow for the Relocation to be completed prior to having to cease operations. The Final Judgment was entered on June 29, 2023. Enbridge filed its Notice of Appeal on June 30, 2023 and the Band filed its Notice of Cross Appeal on July 27, 2023. The 7th Circuit Court of Appeals (7th Circuit) issued a Notice of Telephonic Mediation for July 21, 2023, which occurred as scheduled. On July 31, 2023, the Court entered the parties agreed upon briefing schedule. According to that schedule, briefing should be complete on or before December 11, 2023, with oral argument and a decision expected in 2024.

Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement

In 2019, the Michigan Attorney General (AG) filed a complaint in the Michigan Ingham County Circuit Court (the Circuit Court) that requests the Circuit 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. On December 15, 2021, Enbridge removed the case to the US District Court in the Western District of Michigan (US District Court), where it was assigned to Judge Janet T. Neff. The removal of the AG's case to federal court followed a November 16, 2021 ruling which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force Line 5's shutdown raised important federal issues that should be heard in federal court. On December 21, 2021, the AG made a request to file a motion to remand the 2019 case, which the US District Court allowed on January 5, 2022. However, after full briefing, on August 18, 2022, Judge Neff denied the AG's motion to remand. On August 30, 2022, the AG filed a motion to certify the August 18 Order to pursue an appeal on the jurisdictional issue, which Enbridge opposed. On February 21, 2023, that motion was granted and shortly after, on March 2, 2023, the AG filed her Petition for Permission to Appeal in the 6th Circuit Court of Appeals (6th Circuit).

On July 21, 2023, the 6th Circuit granted the AG's Petition for Permission to appeal the US District Court's August 18 Order denying remand to state court. The 6th Circuit's briefing schedule has briefing being complete by the end of 2023. Once briefing concludes, the 6th Circuit will schedule an oral argument date. We anticipate a decision in 2024.

Dakota Access Pipeline

We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of the Dakota Access Pipeline (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.

On March 25, 2020, in response to amended complaints from the Tribes, the District Court found that the Army Corps' subsequent environmental review completed in August 2018 was also deficient and ordered the Army Corps to prepare an Environmental Impact Statement (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. On that day, the US Court of Appeals for the District of Columbia Circuit stayed the District Court's July 6 order to shut down and empty the pipeline.

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. The US Supreme Court subsequently denied the request of Dakota Access, LLC to review the decision that an EIS is required. The US Court of Appeals also determined that, absent an injunction proceeding, the District Court could not order DAPL's operations to cease. While not an issue before, 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.

The Army Corps earlier indicated that it did not intend to exercise its authority to bar DAPL's continued operation, notwithstanding the absence of an easement.

On September 8, 2023, the Army Corps issued its draft EIS, which assesses the impacts of DAPL under five alternative scenarios: denying the easement removing the pipeline; denying the easement and leaving the pipeline in place; granting the easement with the prior conditions (which allow for the ongoing operation, maintenance and ultimate removal of the pipeline and its related facilities); granting the easement with some new safety conditions; and rerouting the pipeline. The Army Corps did not identify a preferred alternative. A public comment period commenced on the issuance of the draft EIS, with comments due by November 13, 2023. The pipeline will remain operational while the environmental review process continues.

Aux Sable

On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim.

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.

TAX MATTERS

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, 2022. 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, 2023, 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, 2023 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.

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, 2022, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors, other than as set forth below.

RISKS RELATING TO THE ACQUISITIONS

One or all of the Acquisitions may not occur on the terms contemplated in the applicable Purchase and Sale Agreement or at all, or may not occur within the expected time frame, which may negatively affect the benefits we expect to obtain from the Acquisitions.

We cannot provide any assurance that the Acquisitions will be completed in the manner, on the terms and on the time frame currently anticipated, or at all. Completion of each of the Acquisitions is subject to the satisfaction or waiver of a number of conditions as set forth in the applicable Purchase and Sale Agreement that are beyond our control and may prevent, delay or otherwise materially adversely affect its completion.

The success of the Acquisitions will depend on, among other things, our ability to integrate the Gas Utilities into our business in a manner that facilitates growth opportunities and achieves anticipated benefits of the Acquisitions. There is a significant degree of difficulty and management distraction inherent in the process of integrating an acquisition, including challenges consolidating certain operations and functions (including regulatory functions), integrating technologies, organizations, procedures, policies and operations, addressing differences in the business cultures of Enbridge and the Gas Utilities and retaining key personnel. The integration may be complex and time consuming and involve delays or additional and unforeseen expenses. The integration process and other disruptions resulting from the Acquisitions may also disrupt our ongoing business.

Any failure to realize the anticipated benefits of the Acquisitions, additional unanticipated costs or other factors could negatively impact our earnings or cash flows, decrease or delay any beneficial effects of the Acquisitions and negatively impact our business, financial condition and results of operations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES, USE OF PROCEEDS, AND ISSUER PURCHASES OF EQUITY SECURITIES

ISSUER PURCHASES OF EQUITY SECURITIES


Period	Total number of shares purchased	Average price paid per share	Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs1
July 2023 (July 1 - July 31)	—	N/A	—	25,433,807
August 2023 (August 1 - August 31)	—	N/A	—	25,433,807
September 2023 (September 1 - September 30)	—	N/A	—	25,433,807

1On January 4, 2023, the Toronto Stock Exchange (TSX) approved our NCIB to purchase, for cancellation, up to 27,938,163 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 billion. Purchases under the NCIB may be made through the facilities of the TSX, the New York Stock Exchange and other designated exchanges and alternative trading systems. Our NCIB commenced on January 6, 2023 and continues until January 5, 2024, when it expires, or such earlier date on which we have either acquired the maximum number of common shares allowable or otherwise decide not to make further repurchases.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Certain of our officers and directors have made elections to participate in, and are participating in, our compensation and benefit plans involving Enbridge stock, such as our 401(k) plan and directors’ compensation plan, and may from time to time make elections which may be designed to satisfy the affirmative defense conditions of Rule 10b5-1 under the Exchange Act or may constitute non-Rule 10b5-1 trading arrangements (as defined in Item 408(c) of Regulation S-K).

ITEM 6. EXHIBITS

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


Exhibit No.						Description
2.1*						Purchase and Sale Agreement, dated as of September 5, 2023, by and between Dominion Energy, Inc. and Enbridge Elephant Holdings, LLC
2.2*						Purchase and Sale Agreement, dated as of September 5, 2023, by and between Dominion Energy, Inc. and Enbridge Parrot Holdings, LLC
2.3*						Purchase and Sale Agreement, dated as of September 5, 2023, by and between Dominion Energy, Inc. and Enbridge Quail Holdings, LLC
3.1						Certificate and Articles of Amendment dated September 21, 2023, relating to the Series 2023-A Preference Shares (incorporated by reference to Exhibit 3.1 to Enbridge’s Current Report on Form 8-K filed September 25, 2023)
3.2						Certificate and Articles of Amendment dated September 21, 2023, relating to the Series 2023-B Preference Shares (incorporated by reference to Exhibit 3.2 to Enbridge’s Current Report on Form 8-K filed September 25, 2023)
3.3						Certificate and Articles of Amendment dated September 28, 2023, relating to the Series 2023-C Conversion Preference Shares (incorporated by reference to Exhibit 3.1 to Enbridge’s Current Report on Form 8-K filed October 2, 2023)
3.4						Certificate and Articles of Amendment dated September 28, 2023, relating to the Series 2023-D Conversion Preference Shares (incorporated by reference to Exhibit 3.2 to Enbridge’s Current Report on Form 8-K filed October 2, 2023)
4.1						Eleventh Supplemental Indenture between Enbridge Inc. and Deutsche Bank Trust Company Americas, dated September 25, 2023 (incorporated by reference to Exhibit 4.1 to Enbridge’s current Report on Form 8-K Filed September 25, 2023)
4.2						Twelfth Supplemental Indenture between Enbridge Inc. and Deutsche Bank Trust Company Americas, dated September 25, 2023 (incorporated by reference to Exhibit 4.2 to Enbridge’s current Report on Form 8-K Filed September 25, 2023)
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.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 3, 2023	By:	/s/ Gregory L. Ebel
			Gregory L. Ebel President, Chief Executive Officer and Director (Principal Executive Officer)

Date:	November 3, 2023	By:	/s/ Patrick R. Murray
			Patrick R. Murray Executive Vice President and Chief Financial Officer (Principal Financial Officer)