~~0000895728us-gaap:ForeignExchangeContractMemberus-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel3Member2021-12-31~~

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~~June 30, ~~2022~~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 ~~1-10934~~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~~) (403) 231-3900

(Registrant’s Telephone Number, Including Area Code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Shares

ENB

New York Stock Exchange

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

~~ENBA~~

~~New York Stock Exchange~~

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

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

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

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

Large accelerated filer

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

The registrant had ~~2,024,819,303~~2,022,660,553 common shares outstanding as at ~~October~~July 28, ~~2022.~~2023.


	PART I	PAGE

Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3835
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	6055
Item 4.	Controls and Procedures	6056

	PART II

Item 1.	Legal Proceedings	6257
Item 1A.	Risk Factors	6257
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	6357
Item 3.	Defaults Upon Senior Securities	6358
Item 4.	Mine Safety Disclosures	6358
Item 5.	Other Information	6358
Item 6.	Exhibits	6458
	Signatures	6559

GLOSSARY


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


~~ASU~~			~~Accounting Standards Update~~
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~~
~~Guaranteed Enbridge Notes~~			~~Guaranteed notes of Enbridge~~
~~L3R~~			~~Line 3 Replacement~~
~~LNG~~			~~Liquified natural gas~~










NCIB			Normal course issuer bid
~~NGL~~			~~Natural gas liquids~~

OCI			Other comprehensive income/(loss)

~~OEB~~			~~Ontario Energy Board~~
OPEB			Other postretirement benefits
~~P66~~			~~Phillips 66~~



SEP			Spectra Energy Partners, LP









Texas Eastern			Texas Eastern Transmission, LP
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 (SEP) and Enbridge Energy Partners, L.P. (EEP)
the Reservation			Bad River Reservation
Tres Palacios			Tres Palacios Holdings LLC
US			United States ~~of America~~
~~US$~~			~~United States dollars~~

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”, “$”~~"dollars" or "$" are to Canadian dollars and all references to ~~“US$”~~"US$" are to United States (US) dollars. All amounts are provided on a before-tax basis, unless otherwise stated.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this quarterly report on Form 10-Q to provide information about us and our subsidiaries and affiliates, including management’s assessment of our and our subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: our corporate vision and strategy, including strategic priorities and enablers; 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; expected earnings before interest, income taxes~~transition and ~~depreciation~~lower-carbon energy, and ~~amortization (EBITDA); expected earnings/(loss); expected future cash flows~~our approach thereto; environmental, social and ~~distributable cash flow;~~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 ~~benefits~~in-service dates related to announced projects and projects under construction; expected ~~in-service dates for announced projects~~capital expenditures; investable capacity and ~~projects~~capital allocation priorities; share repurchases under ~~construction and for maintenance; expected capital expenditures;~~our normal course issuer bid (NCIB); 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; expected closing of acquisitions and dispositions and the timing thereof; expected benefits of transactions; expected future actions of regulators and ~~courts;~~courts, and the timing and impact thereof; toll and rate cases discussions and ~~filings,~~proceedings and anticipated timeline and impact therefrom, including Mainline Tolling and those relating to the Gas Transmission and Midstream and Gas Distribution and ~~Storage.~~Storage businesses; operational, industry, regulatory, climate change and other risks associated with our businesses; 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, ~~and~~ demand for, ~~crude oil, natural gas, NGL~~export of and ~~renewable energy;~~ prices of crude oil, natural gas, NGL, LNG and renewable energy; ~~energy transition;~~ anticipated utilization of assets; exchange rates; inflation; interest rates; ~~the COVID-19 pandemic and the duration and impact thereof;~~ availability and price of labor and construction materials; the stability of our supply chain; operational reliability; ~~customer and regulatory approvals;~~ maintenance of support and regulatory approvals for our projects; anticipated in-service dates; weather; the timing and closing of acquisitions and dispositions; the realization of anticipated benefits ~~and synergies~~ of transactions; governmental legislation; litigation; estimated future dividends and impact of our dividend policy on our future cash flows; our credit ratings; capital project funding; hedging program; expected ~~EBITDA;~~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 ~~and the COVID-19 pandemic~~ impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected EBITDA, expected earnings/(loss), expected future cash flows, expected distributable cash flow or estimated future dividends. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the 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; and the COVID-19 pandemic and the duration and impact thereof.~~regimes.

Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic ~~priorities;~~priorities, operating performance; legislative and regulatory parameters; litigation; 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;~~commodities and ~~the COVID-19 pandemic,~~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 ~~accounting principles~~ in the United States of America (US GAAP) and are not US GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. A reconciliation of historical non-GAAP and other financial measures to the most directly comparable GAAP measures is set out in this MD&A and is available on our website. Additional information on non-GAAP and other financial measures may be found on our website, www.sedar.com or www.sec.gov.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS


		Three months ended September 30,		Nine months ended September 30,			Three months ended June 30,		Six months ended June 30,
		2022	2021	2022	2021		2023	2022	2023	2022
(unaudited; millions of Canadian dollars, except per share amounts)	(unaudited; millions of Canadian dollars, except per share amounts)					(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues	Operating revenues					Operating revenues
Commodity sales	Commodity sales	6,415	7,279	22,880	20,042	Commodity sales	4,679	8,108	9,462	16,433
Gas distribution sales	Gas distribution sales	695	492	3,698	2,769	Gas distribution sales	792	905	3,071	3,003
Transportation and other services	Transportation and other services	4,463	3,695	13,307	11,740	Transportation and other services	4,961	4,202	9,974	8,876
Total operating revenues (Note 3)		11,573	11,466	39,885	34,551
Total operating revenues (Note 2)						Total operating revenues (Note 2)	10,432	13,215	22,507	28,312
Operating expenses	Operating expenses					Operating expenses
Commodity costs	Commodity costs	6,300	7,347	22,772	19,975	Commodity costs	4,549	8,181	9,185	16,472
Gas distribution costs	Gas distribution costs	330	120	2,242	1,359	Gas distribution costs	368	456	1,962	1,912
Operating and administrative	Operating and administrative	2,089	1,667	5,958	4,710	Operating and administrative	2,028	1,994	4,065	3,869
Depreciation and amortization	Depreciation and amortization	1,076	944	3,195	2,805	Depreciation and amortization	1,137	1,064	2,283	2,119

Total operating expenses	Total operating expenses	9,795	10,078	34,167	28,849	Total operating expenses	8,082	11,695	17,495	24,372
Operating income	Operating income	1,778	1,388	5,718	5,702	Operating income	2,350	1,520	5,012	3,940
Income from equity investments	Income from equity investments	536	440	1,537	1,187	Income from equity investments	478	510	995	1,001
Impairment of equity investments		—	(111)	—	(111)
Other income/(expense)
Net foreign currency gain/(loss)		(1,023)	(165)	(1,235)	146
Gain on joint venture merger transaction (Note 6)		1,076	—	1,076	—
Other		140	109	311	300

Other income/(expense) (Note 10)						Other income/(expense) (Note 10)	575	(499)	677	(41)
Interest expense	Interest expense	(806)	(648)	(2,316)	(1,923)	Interest expense	(883)	(791)	(1,788)	(1,510)
Earnings before income taxes	Earnings before income taxes	1,701	1,013	5,091	5,301	Earnings before income taxes	2,520	740	4,896	3,390
Income tax expense	Income tax expense	(318)	(199)	(1,044)	(952)	Income tax expense	(519)	(133)	(1,029)	(726)
Earnings	Earnings	1,383	814	4,047	4,349	Earnings	2,001	607	3,867	2,664
Earnings attributable to noncontrolling interests	Earnings attributable to noncontrolling interests	(21)	(34)	(61)	(93)	Earnings attributable to noncontrolling interests	(66)	(12)	(115)	(40)
Earnings attributable to controlling interests	Earnings attributable to controlling interests	1,362	780	3,986	4,256	Earnings attributable to controlling interests	1,935	595	3,752	2,624
Preference share dividends	Preference share dividends	(83)	(98)	(330)	(280)	Preference share dividends	(87)	(145)	(171)	(247)
Earnings attributable to common shareholders	Earnings attributable to common shareholders	1,279	682	3,656	3,976	Earnings attributable to common shareholders	1,848	450	3,581	2,377
Earnings per common share attributable to common shareholders (Note 5)		0.63	0.34	1.80	1.97
Diluted earnings per common share attributable to common shareholders (Note 5)		0.63	0.34	1.80	1.96
Earnings per common share attributable to common shareholders (Note 4)						Earnings per common share attributable to common shareholders (Note 4)	0.91	0.22	1.77	1.17
Diluted earnings per common share attributable to common shareholders (Note 4)						Diluted earnings per common share attributable to common shareholders (Note 4)	0.91	0.22	1.77	1.17

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,			Three months ended June 30,		Six months ended June 30,
		2022	2021	2022	2021		2023	2022	2023	2022
(unaudited; millions of Canadian dollars)	(unaudited; millions of Canadian dollars)					(unaudited; millions of Canadian dollars)
Earnings	Earnings	1,383	814	4,047	4,349	Earnings	2,001	607	3,867	2,664
Other comprehensive income/(loss), net of tax	Other comprehensive income/(loss), net of tax					Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges		171	(16)	817	197
Change in unrealized gain on cash flow hedges						Change in unrealized gain on cash flow hedges	166	352	121	646
Change in unrealized gain/(loss) on net investment hedges	Change in unrealized gain/(loss) on net investment hedges	(934)	(206)	(1,187)	16	Change in unrealized gain/(loss) on net investment hedges	385	(386)	400	(253)
Other comprehensive loss from equity investees		(7)	(30)	(7)	(28)

Excluded components of fair value hedges	Excluded components of fair value hedges	(33)	(1)	(38)	(3)	Excluded components of fair value hedges	2	(4)	9	(5)
Reclassification to earnings of loss on cash flow hedges	Reclassification to earnings of loss on cash flow hedges	36	55	145	168	Reclassification to earnings of loss on cash flow hedges	12	52	19	109
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(2)	5	(7)	16	Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(4)	(3)	(8)	(5)
Reclassification to earnings of loss on equity investees		16	—	16	—

Foreign currency translation adjustments	Foreign currency translation adjustments	4,135	1,281	5,308	(350)	Foreign currency translation adjustments	(1,458)	1,881	(1,517)	1,173
Other comprehensive income, net of tax		3,382	1,088	5,047	16
Other comprehensive income/(loss), net of tax						Other comprehensive income/(loss), net of tax	(897)	1,892	(976)	1,665
Comprehensive income	Comprehensive income	4,765	1,902	9,094	4,365	Comprehensive income	1,104	2,499	2,891	4,329
Comprehensive income attributable to noncontrolling interests	Comprehensive income attributable to noncontrolling interests	(116)	(62)	(187)	(68)	Comprehensive income attributable to noncontrolling interests	(34)	(58)	(98)	(71)
Comprehensive income attributable to controlling interests	Comprehensive income attributable to controlling interests	4,649	1,840	8,907	4,297	Comprehensive income attributable to controlling interests	1,070	2,441	2,793	4,258
Preference share dividends	Preference share dividends	(83)	(98)	(330)	(280)	Preference share dividends	(87)	(145)	(171)	(247)
Comprehensive income attributable to common shareholders	Comprehensive income attributable to common shareholders	4,566	1,742	8,577	4,017	Comprehensive income attributable to common shareholders	983	2,296	2,622	4,011

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,			Three months ended June 30,		Six months ended June 30,
		2022	2021	2022	2021		2023	2022	2023	2022
(unaudited; millions of Canadian dollars, except per share amounts)	(unaudited; millions of Canadian dollars, except per share amounts)					(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares	Preference shares					Preference shares
Balance at beginning of period	Balance at beginning of period	6,818	7,747	7,747	7,747	Balance at beginning of period	6,818	7,010	6,818	7,747
Redemption of preference shares	Redemption of preference shares	—	—	(929)	—	Redemption of preference shares	—	(192)	—	(929)
Balance at end of period	Balance at end of period	6,818	7,747	6,818	7,747	Balance at end of period	6,818	6,818	6,818	6,818
Common shares	Common shares					Common shares
Balance at beginning of period	Balance at beginning of period	64,755	64,780	64,799	64,768	Balance at beginning of period	64,774	64,801	64,760	64,799
Shares issued on exercise of stock options	Shares issued on exercise of stock options	2	10	50	22	Shares issued on exercise of stock options	—	12	2	48
Shares issued on vesting of restricted stock units (RSU)						Shares issued on vesting of restricted stock units (RSU)	—	—	12	—
Share purchases at stated value	Share purchases at stated value	—	—	(88)	—	Share purchases at stated value	(80)	(58)	(80)	(88)
Other	Other	—	—	(4)	—	Other	—	—	—	(4)
Balance at end of period	Balance at end of period	64,757	64,790	64,757	64,790	Balance at end of period	64,694	64,755	64,694	64,755
Additional paid-in capital	Additional paid-in capital					Additional paid-in capital
Balance at beginning of period	Balance at beginning of period	305	324	365	277	Balance at beginning of period	274	316	275	365
Stock-based compensation	Stock-based compensation	9	7	27	23	Stock-based compensation	18	5	18	18
Options exercised	Options exercised	(2)	(7)	(47)	(15)	Options exercised	(1)	(11)	(2)	(45)
Change in reciprocal interest		—	—	—	39

Other	Other	—	—	(33)	—	Other	—	(5)	—	(33)
Balance at end of period	Balance at end of period	312	324	312	324	Balance at end of period	291	305	291	305
Deficit	Deficit					Deficit
Balance at beginning of period	Balance at beginning of period	(10,418)	(8,388)	(10,989)	(9,995)	Balance at beginning of period	(13,753)	(9,082)	(15,486)	(10,989)
Earnings attributable to controlling interests	Earnings attributable to controlling interests	1,362	780	3,986	4,256	Earnings attributable to controlling interests	1,935	595	3,752	2,624
Preference share dividends	Preference share dividends	(83)	(98)	(330)	(280)	Preference share dividends	(87)	(145)	(171)	(247)
Common share dividends declared	Common share dividends declared	(1,741)	(1,692)	(3,484)	(3,384)	Common share dividends declared	(1,796)	(1,743)	(1,796)	(1,743)
Dividends paid to reciprocal shareholder		—	1	—	6

Share purchases in excess of stated value	Share purchases in excess of stated value	—	—	(63)	—	Share purchases in excess of stated value	(45)	(43)	(45)	(63)

Balance at end of period	Balance at end of period	(10,880)	(9,397)	(10,880)	(9,397)	Balance at end of period	(13,746)	(10,418)	(13,746)	(10,418)
Accumulated other comprehensive income/(loss) (Note 8)
Accumulated other comprehensive income/(loss) (Note 7)						Accumulated other comprehensive income/(loss) (Note 7)
Balance at beginning of period	Balance at beginning of period	538	(2,420)	(1,096)	(1,401)	Balance at beginning of period	3,426	(1,308)	3,520	(1,096)
Other comprehensive income attributable to common shareholders, net of tax		3,287	1,060	4,921	41
Other comprehensive income/(loss) attributable to common shareholders, net of tax						Other comprehensive income/(loss) attributable to common shareholders, net of tax	(865)	1,846	(959)	1,634
Balance at end of period	Balance at end of period	3,825	(1,360)	3,825	(1,360)	Balance at end of period	2,561	538	2,561	538
Reciprocal shareholding
Balance at beginning of period		—	(17)	—	(29)
Change in reciprocal interest		—	—	—	12
Balance at end of period		—	(17)	—	(17)

Total Enbridge Inc. shareholders’ equity	Total Enbridge Inc. shareholders’ equity	64,832	62,087	64,832	62,087	Total Enbridge Inc. shareholders’ equity	60,618	61,998	60,618	61,998
Noncontrolling interests	Noncontrolling interests					Noncontrolling interests
Balance at beginning of period	Balance at beginning of period	2,539	2,870	2,542	2,996	Balance at beginning of period	3,486	2,536	3,511	2,542
Earnings attributable to noncontrolling interests	Earnings attributable to noncontrolling interests	21	34	61	93	Earnings attributable to noncontrolling interests	66	12	115	40
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax	Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax					Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized loss on cash flow hedges		(8)	(9)	(14)	(15)
Change in unrealized gain/(loss) on cash flow hedges						Change in unrealized gain/(loss) on cash flow hedges	1	(8)	18	(6)
Foreign currency translation adjustments	Foreign currency translation adjustments	103	37	140	(10)	Foreign currency translation adjustments	(33)	54	(35)	37
		95	28	126	(25)		(32)	46	(17)	31
Comprehensive income attributable to noncontrolling interests	Comprehensive income attributable to noncontrolling interests	116	62	187	68	Comprehensive income attributable to noncontrolling interests	34	58	98	71
Distributions	Distributions	(62)	(67)	(189)	(210)	Distributions	(103)	(67)	(195)	(127)
Contributions	Contributions	2	4	10	13	Contributions	4	2	8	8
Redemption of noncontrolling interests		—	(293)	—	(293)

Other	Other	3	(1)	48	1	Other	(1)	10	(2)	45
Balance at end of period	Balance at end of period	2,598	2,575	2,598	2,575	Balance at end of period	3,420	2,539	3,420	2,539
Total equity	Total equity	67,430	64,662	67,430	64,662	Total equity	64,038	64,537	64,038	64,537
Dividends paid per common share	Dividends paid per common share	0.860	0.835	2.580	2.505	Dividends paid per common share	0.89	0.86	1.78	1.72

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,			Six months ended June 30,
		2022	2021		2023	2022
(unaudited; millions of Canadian dollars)	(unaudited; millions of Canadian dollars)			(unaudited; millions of Canadian dollars)
Operating activities	Operating activities			Operating activities
Earnings	Earnings	4,047	4,349	Earnings	3,867	2,664
Adjustments to reconcile earnings to net cash provided by operating activities:	Adjustments to reconcile earnings to net cash provided by operating activities:			Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	Depreciation and amortization	3,195	2,805	Depreciation and amortization	2,283	2,119
Deferred income tax expense	Deferred income tax expense	600	789	Deferred income tax expense	919	469
Unrealized derivative fair value loss, net (Note 9)		1,691	86
Unrealized derivative fair value (gain)/loss, net (Note 8)				Unrealized derivative fair value (gain)/loss, net (Note 8)	(1,135)	415
Income from equity investments	Income from equity investments	(1,537)	(1,187)	Income from equity investments	(995)	(1,001)
Distributions from equity investments	Distributions from equity investments	1,293	1,197	Distributions from equity investments	1,066	878
Impairment of equity investments		—	111

Gain on joint venture merger transaction (Note 6)		(1,076)	—

Other	Other	6	(128)	Other	72	67
Changes in operating assets and liabilities	Changes in operating assets and liabilities	(602)	(656)	Changes in operating assets and liabilities	1,228	(138)
Net cash provided by operating activities	Net cash provided by operating activities	7,617	7,366	Net cash provided by operating activities	7,305	5,473
Investing activities	Investing activities			Investing activities
Capital expenditures	Capital expenditures	(3,204)	(5,887)	Capital expenditures	(2,093)	(2,002)
Long-term investments and restricted long-term investments	Long-term investments and restricted long-term investments	(566)	(241)	Long-term investments and restricted long-term investments	(472)	(388)
Distributions from equity investments in excess of cumulative earnings	Distributions from equity investments in excess of cumulative earnings	426	295	Distributions from equity investments in excess of cumulative earnings	752	296
Additions to intangible assets	Additions to intangible assets	(131)	(185)	Additions to intangible assets	(104)	(91)
Acquisition (Note 6)		(295)	—
Proceeds from joint venture merger transaction (Note 6)		522	—
Proceeds from disposition		—	122
Acquisitions				Acquisitions	(487)	—

Affiliate loans, net	Affiliate loans, net	90	19	Affiliate loans, net	71	65
Other		—	(30)

Net cash used in investing activities	Net cash used in investing activities	(3,158)	(5,907)	Net cash used in investing activities	(2,333)	(2,120)
Financing activities	Financing activities			Financing activities
Net change in short-term borrowings	Net change in short-term borrowings	367	84	Net change in short-term borrowings	(1,148)	105
Net change in commercial paper and credit facility draws	Net change in commercial paper and credit facility draws	386	(32)	Net change in commercial paper and credit facility draws	(2,847)	1,031
Debenture and term note issues, net of issue costs	Debenture and term note issues, net of issue costs	4,739	6,135	Debenture and term note issues, net of issue costs	5,598	2,642
Debenture and term note repayments	Debenture and term note repayments	(2,244)	(1,888)	Debenture and term note repayments	(2,281)	(1,333)
Contributions from noncontrolling interests	Contributions from noncontrolling interests	10	13	Contributions from noncontrolling interests	8	8
Distributions to noncontrolling interests	Distributions to noncontrolling interests	(189)	(210)	Distributions to noncontrolling interests	(195)	(127)
Common shares issued	Common shares issued	3	3	Common shares issued	—	3
Common shares repurchased	Common shares repurchased	(151)	—	Common shares repurchased	(125)	(151)
Preference share dividends	Preference share dividends	(254)	(274)	Preference share dividends	(171)	(173)
Common share dividends	Common share dividends	(5,226)	(5,074)	Common share dividends	(3,595)	(3,485)
Redemption of preferred shares held by subsidiary		—	(115)
Redemption of preference shares	Redemption of preference shares	(1,003)	—	Redemption of preference shares	—	(1,003)
Affiliate loans, net				Affiliate loans, net	50	—
Other	Other	(223)	(64)	Other	(64)	(122)
Net cash used in financing activities	Net cash used in financing activities	(3,785)	(1,422)	Net cash used in financing activities	(4,770)	(2,605)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	Effect of translation of foreign denominated cash and cash equivalents and restricted cash	63	(12)	Effect of translation of foreign denominated cash and cash equivalents and restricted cash	(19)	20
Net change in cash and cash equivalents and restricted cash	Net change in cash and cash equivalents and restricted cash	737	25	Net change in cash and cash equivalents and restricted cash	183	768
Cash and cash equivalents and restricted cash at beginning of period	Cash and cash equivalents and restricted cash at beginning of period	320	490	Cash and cash equivalents and restricted cash at beginning of period	907	320
Cash and cash equivalents and restricted cash at end of period	Cash and cash equivalents and restricted cash at end of period	1,057	515	Cash and cash equivalents and restricted cash at end of period	1,090	1,088

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

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


		September 30, 2022	December 31, 2021		June 30, 2023	December 31, 2022
(unaudited; millions of Canadian dollars; number of shares in millions)	(unaudited; millions of Canadian dollars; number of shares in millions)			(unaudited; millions of Canadian dollars; number of shares in millions)
Assets	Assets			Assets
Current assets	Current assets			Current assets
Cash and cash equivalents	Cash and cash equivalents	1,021	286	Cash and cash equivalents	1,030	861
Restricted cash	Restricted cash	36	34	Restricted cash	60	46
Accounts receivable and other		7,168	6,862
Trade receivables and unbilled revenues				Trade receivables and unbilled revenues	3,725	5,616
Other current assets				Other current assets	2,775	3,255
Accounts receivable from affiliates	Accounts receivable from affiliates	236	107	Accounts receivable from affiliates	167	114
Inventory	Inventory	2,346	1,670	Inventory	1,211	2,255
		10,807	8,959		8,968	12,147
Property, plant and equipment, net	Property, plant and equipment, net	105,251	100,067	Property, plant and equipment, net	103,955	104,460
Long-term investments	Long-term investments	15,346	13,324	Long-term investments	15,258	15,936
Restricted long-term investments	Restricted long-term investments	569	630	Restricted long-term investments	664	593
Deferred amounts and other assets	Deferred amounts and other assets	9,941	8,613	Deferred amounts and other assets	9,185	9,542
Intangible assets, net	Intangible assets, net	4,124	4,008	Intangible assets, net	3,764	4,018
Goodwill	Goodwill	35,274	32,775	Goodwill	31,886	32,440
Deferred income taxes	Deferred income taxes	463	488	Deferred income taxes	262	472
Total assets	Total assets	181,775	168,864	Total assets	173,942	179,608

Liabilities and equity	Liabilities and equity			Liabilities and equity
Current liabilities	Current liabilities			Current liabilities
Short-term borrowings	Short-term borrowings	1,882	1,515	Short-term borrowings	848	1,996
Accounts payable and other		8,867	9,767
Trade payables and accrued liabilities				Trade payables and accrued liabilities	3,660	6,172
Other current liabilities				Other current liabilities	2,559	5,220
Accounts payable to affiliates	Accounts payable to affiliates	144	90	Accounts payable to affiliates	48	105
Interest payable	Interest payable	641	693	Interest payable	824	763
Current portion of long-term debt	Current portion of long-term debt	6,376	6,164	Current portion of long-term debt	6,086	6,045
		17,910	18,229		14,025	20,301
Long-term debt	Long-term debt	73,960	67,961	Long-term debt	72,530	72,939
Other long-term liabilities	Other long-term liabilities	9,133	7,617	Other long-term liabilities	8,847	9,189
Deferred income taxes	Deferred income taxes	13,342	11,689	Deferred income taxes	14,502	13,781
		114,345	105,496		109,904	116,210
Contingencies (Note 12)
Contingencies (Note 11)				Contingencies (Note 11)
Equity	Equity			Equity
Share capital	Share capital			Share capital
Preference shares	Preference shares	6,818	7,747	Preference shares	6,818	6,818
Common shares (2,025 and 2,026 outstanding at September 30, 2022 and December 31, 2021, respectively)		64,757	64,799
Common shares (2,023 and 2,025 outstanding at June 30, 2023 and December 31, 2022, respectively)				Common shares (2,023 and 2,025 outstanding at June 30, 2023 and December 31, 2022, respectively)	64,694	64,760
Additional paid-in capital	Additional paid-in capital	312	365	Additional paid-in capital	291	275
Deficit	Deficit	(10,880)	(10,989)	Deficit	(13,746)	(15,486)
Accumulated other comprehensive income/(loss) (Note 8)		3,825	(1,096)
Accumulated other comprehensive income (Note 7)				Accumulated other comprehensive income (Note 7)	2,561	3,520

Total Enbridge Inc. shareholders’ equity	Total Enbridge Inc. shareholders’ equity	64,832	60,826	Total Enbridge Inc. shareholders’ equity	60,618	59,887
Noncontrolling interests	Noncontrolling interests	2,598	2,542	Noncontrolling interests	3,420	3,511
		67,430	63,368		64,038	63,398
Total liabilities and equity	Total liabilities and equity	181,775	168,864	Total liabilities and equity	173,942	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”~~("we", ~~“our”~~"our", ~~“us”~~"us" and ~~“Enbridge”~~"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, ~~2021.~~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, ~~2021, except for the adoption of new standards~~ ~~(Note 2)~~.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. ~~CHANGES IN ACCOUNTING POLICIES~~REVENUES

~~ADOPTION OF NEW ACCOUNTING STANDARDS~~

~~Disclosures About Government Assistance~~REVENUE FROM CONTRACTS WITH CUSTOMERS

Effective January 1, 2022, we adopted Accounting Standards Update (ASU) 2021-10 on a prospective basis. The new standard was issued in November 2021 to increase the transparency of government assistance to business entities. The ASU adds new disclosure requirements for transactions with governments that are accounted for using a grant or contribution accounting model by analogy. The required disclosures include information about the nature of transactions, accounting policy applied, impacted financial statement line itemsMajor Products and ~~significant terms and conditions. The adoption of this ASU did not have a material impact on our consolidated financial statements.~~Services

~~Accounting for Certain Lessor Leases with Variable Lease Payments~~

Effective January 1, 2022, we adopted ASU 2021-05 on a prospective basis. The new standard was issued in July 2021 to amend lessor accounting for certain leases with variable lease payments that do not depend on a reference index or a rate and would have resulted in the recognition of a loss at lease commencement if classified as a sales-type or a direct financing lease. The ASU amends the classification requirements of such leases for lessors to result in an operating lease classification. The adoption of this ASU did not have a material impact on our consolidated financial statements.

~~Accounting for Modifications or Exchanges of Certain Equity-Classified Contracts~~

Effective January 1, 2022, we adopted ASU 2021-04 on a prospective basis. The new standard was issued in May 2021 to clarify issuer accounting for modifications or exchanges of freestanding equity-classified written call options that remain equity classified after modification or exchange. The ASU requires an issuer to determine the accounting for the modification or exchange based on the economic substance of the modification or exchange. The adoption of this ASU did not have a material impact on our consolidated financial statements.


Three months ended June 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	3,002	1,290	169	—	—	—	4,461
Storage and other revenue	62	113	85	—	—	—	260

Gas distribution revenue	—	—	796	—	—	—	796
Electricity revenue	—	—	—	75	—	—	75

Total revenue from contracts with customers	3,064	1,403	1,050	75	—	—	5,592
Commodity sales	—	—	—	—	4,679	—	4,679
Other revenue1,2	79	7	(1)	76	—	—	161
Intersegment revenue	127	—	1	(1)	—	(127)	—
Total revenue	3,270	1,410	1,050	150	4,679	(127)	10,432

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

Effective January 1, 2022, we adopted ASU 2020-06 on a modified retrospective basis. The new standard was issued in August 2020 to simplify accounting for certain financial instruments. The ASU eliminates the current models that require separation of beneficial conversion and cash conversion features from convertible instruments and simplifies the derivative scope exception guidance pertaining to equity classification of contracts in an entity’s own equity. The ASU also introduces additional disclosures for convertible debt and freestanding instruments that are indexed to and settled in an entity’s own equity. The ASU amends the diluted earnings per share guidance, including the requirement to use if-converted method for all convertible instruments and an update for instruments that can be settled in either cash or shares. The adoption of this ASU did not have a material impact on our consolidated financial statements.


Three months ended June 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	2,565	1,200	157	—	—	—	3,922
Storage and other revenue	64	83	99	—	—	—	246
Gas gathering and processing revenue	—	6	—	—	—	—	6
Gas distribution revenue	—	—	919	—	—	—	919
Electricity revenue	—	—	—	81	—	—	81

Total revenue from contracts with customers	2,629	1,289	1,175	81	—	—	5,174
Commodity sales	—	—	—	—	8,108	—	8,108
Other revenue1,2	(145)	11	(37)	74	30	—	(67)
Intersegment revenue	154	1	—	—	—	(155)	—
Total revenue	2,638	1,301	1,138	155	8,138	(155)	13,215

~~3. REVENUE~~

~~REVENUE FROM CONTRACTS WITH CUSTOMERS~~

~~Major Products and Services~~

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated
Three months ended
September 30, 2022
(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 and transmission 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

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated
Three months ended
September 30, 2021
(millions of Canadian dollars)
Transportation revenue 2,340 1,081 128 — — — 3,549
Storage and other revenue 33 58 50 — — — 141
Gas gathering and processing revenue — 15 — — — — 15
Gas distribution revenue — — 496 — — — 496
Electricity and transmission revenue — — — 44 — — 44
Total revenue from contracts with customers 2,373 1,154 674 44 — — 4,245
Commodity sales — — — — 7,279 — 7,279
Other revenue1,2
(143) 4 24 78 (1) (20) (58)
Intersegment revenue 140 1 (11) — 12 (142) —
Total revenue 2,370 1,159 687 122 7,290 (162) 11,466

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated
Nine months ended
September 30, 2022
(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 and transmission 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


		Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Nine months ended September 30, 2021
Six months ended June 30, 2023									Six months ended June 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)	(millions of Canadian dollars)								(millions of Canadian dollars)
Transportation revenue	Transportation revenue	6,826	3,248	494	—	—	—	10,568	Transportation revenue	5,944	2,674	445	—	—	—	9,063
Storage and other revenue	Storage and other revenue	96	195	159	—	—	—	450	Storage and other revenue	126	208	184	—	—	—	518
Gas gathering and processing revenue		—	32	—	—	—	—	32

Gas distribution revenue	Gas distribution revenue	—	—	2,755	—	—	—	2,755	Gas distribution revenue	—	—	3,083	—	—	—	3,083
Electricity and transmission revenue		—	—	—	125	—	—	125
Electricity revenue									Electricity revenue	—	—	—	141	—	—	141

Total revenue from contracts with customers	Total revenue from contracts with customers	6,922	3,475	3,408	125	—	—	13,930	Total revenue from contracts with customers	6,070	2,882	3,712	141	—	—	12,805
Commodity sales	Commodity sales	—	—	—	—	20,042	—	20,042	Commodity sales	—	—	—	—	9,462	—	9,462
Other revenue1,2	Other revenue1,2	284	25	42	246	—	(18)	579	Other revenue1,2	109	18	(41)	154	—	—	240
Intersegment revenue	Intersegment revenue	410	1	13	—	26	(450)	—	Intersegment revenue	256	1	4	(1)	18	(278)	—
Total revenue	Total revenue	7,616	3,501	3,463	371	20,068	(468)	34,551	Total revenue	6,435	2,901	3,675	294	9,480	(278)	22,507

Six months ended June 30, 2022									Six months ended June 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)									(millions of Canadian dollars)
Transportation revenue									Transportation revenue	5,250	2,394	408	—	—	—	8,052
Storage and other revenue									Storage and other revenue	115	167	146	—	—	—	428
Gas gathering and processing revenue									Gas gathering and processing revenue	—	21	—	—	—	—	21
Gas distribution revenue									Gas distribution revenue	—	—	3,017	—	—	—	3,017
Electricity revenue									Electricity revenue	—	—	—	143	—	—	143

Total revenue from contracts with customers									Total revenue from contracts with customers	5,365	2,582	3,571	143	—	—	11,661
Commodity sales									Commodity sales	—	—	—	—	16,433	—	16,433
Other revenue1,2									Other revenue1,2	33	18	(33)	168	32	—	218
Intersegment revenue									Intersegment revenue	295	1	11	—	10	(317)	—
Total revenue									Total revenue	5,693	2,601	3,549	311	16,475	(317)	28,312

1Includes ~~mark-to-market~~realized and unrealized gains and losses f~~rom~~from our hedging program which for the three months ended ~~September~~June 30, ~~2022~~2023 were a net $3 million gain (2022 - $198 million loss) and ~~2021 of $345 million and $225 million, respectively. For~~for the ~~nine~~six months ended ~~September~~June 30, ~~2022 and 2021, Other revenue includes~~2023 were a ~~$483~~net $52 million ~~mark-to-market~~ loss ~~and a $36~~(2022 - $104 million ~~mark-to-market gain, respectively.~~loss).

2Includes revenues from lease contracts for the three months ended ~~September~~June 30, 2023 and 2022 ~~and 2021~~ of ~~$128~~$136 million and ~~$140~~$143 million, respectively, and for the ~~nine~~six months ended ~~September~~June 30, 2023 and 2022 ~~and 2021~~ of ~~$435~~$280 million and ~~$442~~$307 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, 2022 2,307 233 2,201
Balance as at December 31, 2021 2,369 213 1,898


	Contract Receivables	Contract Assets	Contract Liabilities
(millions of Canadian dollars)
Balance as at June 30, 2023	2,182	229	2,283
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 ~~have~~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~~six months ended ~~September~~June 30, ~~2022~~2023 included in contract liabilities at the beginning of the period ~~is $57~~was $53 million and ~~$139~~$89 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three and ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 were ~~$138~~$43 million and ~~$366~~$167 million, respectively.

Performance Obligations

There were no material revenues recognized in the three and ~~nine~~six months ended ~~September~~June 30, ~~2022~~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 ~~are $59.3~~is $57.9 billion, of which ~~$1.9~~$3.9 billion and ~~$6.4~~$6.7 billion are expected to be recognized during the remaining ~~three~~six months ending December 31, ~~2022~~2023 and the year ending December 31, ~~2023,~~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.

1413

Variable Consideration

During the three and ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, revenue for the Canadian Mainline has been 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 ~~continue~~continued on an interim basis until July 1, 2023 when new interim tolls took effect. Until a new commercial arrangement is ~~implemented and~~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~~six months ended ~~September~~June 30, ~~2022~~2023 is considered variable consideration.

Recognition and Measurement of Revenues

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated
Three months ended September 30, 2022
(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

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

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated
Nine months ended September 30, 2022
(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


		Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation		Consolidated
Nine months ended September 30, 2021						Consolidated
Three months ended June 30, 2023							Three months ended June 30, 2023	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution and Storage	Renewable Power Generation		Consolidated
(millions of Canadian dollars)	(millions of Canadian dollars)										(millions of Canadian dollars)
Revenues from products transferred at a point in time	Revenues from products transferred at a point in time	—	—	47	—		47		Revenues from products transferred at a point in time	—		—	37	—		37
Revenues from products and services transferred over time1	Revenues from products and services transferred over time1	6,922	3,475	3,361	125		13,883		Revenues from products and services transferred over time1	3,064		1,403	1,013	75		5,555
Total revenue from contracts with customers	Total revenue from contracts with customers	6,922	3,475	3,408	125		13,930		Total revenue from contracts with customers	3,064		1,403	1,050	75		5,592

Three months ended June 30, 2022									Three months ended June 30, 2022	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation		Consolidated
(millions of Canadian dollars)									(millions of Canadian dollars)
Revenues from products transferred at a point in time									Revenues from products transferred at a point in time	—		—	20	—		20
Revenues from products and services transferred over time1									Revenues from products and services transferred over time1	2,629		1,289	1,155	81		5,154
Total revenue from contracts with customers									Total revenue from contracts with customers	2,629		1,289	1,175	81		5,174

Six months ended June 30, 2023									Six months ended June 30, 2023	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation		Consolidated
(millions of Canadian dollars)									(millions of Canadian dollars)
Revenues from products transferred at a point in time									Revenues from products transferred at a point in time	—		—	67	—		67
Revenues from products and services transferred over time1									Revenues from products and services transferred over time1	6,070		2,882	3,645	141		12,738
Total revenue from contracts with customers									Total revenue from contracts with customers	6,070		2,882	3,712	141		12,805

Six months ended June 30, 2022									Six months ended June 30, 2022	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation		Consolidated
(millions of Canadian dollars)									(millions of Canadian dollars)
Revenues from products transferred at a point in time									Revenues from products transferred at a point in time	—		—	36	—		36
Revenues from products and services transferred over time1									Revenues from products and services transferred over time1	5,365		2,582	3,535	143		11,625
Total revenue from contracts with customers									Total revenue from contracts with customers	5,365		2,582	3,571	143		11,661

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.

1514

4.3. SEGMENTED INFORMATION


		Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated		Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Three months ended September 30, 2022
Three months ended June 30, 2023									Three months ended June 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)	(millions of Canadian dollars)								(millions of Canadian dollars)
Operating revenues	Operating revenues	2,899	1,366	909	120	6,419	(140)	11,573	Operating revenues	3,270	1,410	1,050	150	4,679	(127)	10,432
Commodity and gas distribution costs	Commodity and gas distribution costs	27	—	(327)	(5)	(6,465)	140	(6,630)	Commodity and gas distribution costs	—	—	(371)	(2)	(4,648)	104	(4,917)
Operating and administrative	Operating and administrative	(1,173)	(545)	(311)	(58)	(9)	7	(2,089)	Operating and administrative	(1,083)	(588)	(325)	(62)	(12)	42	(2,028)

Income from equity investments		193	321	—	22	—	—	536
Income/(loss) from equity investments									Income/(loss) from equity investments	254	199	1	27	—	(3)	478

Gain on joint venture merger transaction (Note 6)		—	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

Other income									Other income	10	21	12	16	3	513	575
Earnings before interest, income taxes and depreciation and amortization									Earnings before interest, income taxes and depreciation and amortization	2,451	1,042	367	129	22	529	4,540
Depreciation and amortization	Depreciation and amortization							(1,076)	Depreciation and amortization							(1,137)
Interest expense	Interest expense							(806)	Interest expense							(883)
Income tax expense	Income tax expense							(318)	Income tax expense							(519)
Earnings	Earnings							1,383	Earnings							2,001
Capital expenditures1	Capital expenditures1	268	525	405	9	—	8	1,215	Capital expenditures1	237	343	346	23	—	27	976

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated
Three months ended
September 30, 2021
(millions of Canadian dollars)
Operating revenues 2,370 1,159 687 122 7,290 (162) 11,466
Commodity and gas distribution costs (6) — (135) — (7,485) 159 (7,467)
Operating and administrative (919) (445) (280) (51) (13) 41 (1,667)
Income/(loss) from equity investments 226 211 (12) 15 — — 440
Impairment of equity investments — (111) — — — — (111)
Other income/(expense) 2 70 22 5 4 (159) (56)
Earnings/(loss) before interest, income taxes and depreciation and amortization 1,673 884 282 91 (204) (121) 2,605
Depreciation and amortization (944)
Interest expense (648)
Income tax expense (199)
Earnings 814
Capital expenditures1
1,203 602 359 — 1 20 2,185


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Three months ended June 30, 2022
(millions of Canadian dollars)
Operating revenues	2,638	1,301	1,138	155	8,138	(155)	13,215
Commodity and gas distribution costs	(16)	—	(463)	(4)	(8,305)	151	(8,637)
Operating and administrative	(976)	(545)	(281)	(53)	(11)	(128)	(1,994)


Income/(loss) from equity investments	153	335	1	23	—	(2)	510

Other income/(expense)	19	28	22	1	1	(570)	(499)
Earnings/(loss) before interest, income taxes and depreciation and amortization	1,818	1,119	417	122	(177)	(704)	2,595
Depreciation and amortization							(1,064)
Interest expense							(791)
Income tax expense							(133)
Earnings							607
Capital expenditures1	273	333	334	11	—	12	963

1615


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
Six months ended June 30, 2023									Six months ended June 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)	(millions of Canadian dollars)								(millions of Canadian dollars)
Operating revenues	Operating revenues	8,592	3,967	4,458	431	22,894	(457)	39,885	Operating revenues	6,435	2,901	3,675	294	9,480	(278)	22,507
Commodity and gas distribution costs	Commodity and gas distribution costs	—	—	(2,258)	(13)	(23,197)	454	(25,014)	Commodity and gas distribution costs	—	—	(1,983)	(6)	(9,430)	272	(11,147)
Operating and administrative	Operating and administrative	(3,096)	(1,620)	(891)	(159)	(34)	(158)	(5,958)	Operating and administrative	(2,206)	(1,137)	(634)	(115)	(30)	57	(4,065)

Income/(loss) from equity investments	Income/(loss) from equity investments	561	877	1	100	—	(2)	1,537	Income/(loss) from equity investments	502	437	1	62	—	(7)	995

Gain on joint venture merger transaction (Note 6)		—	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

Other income									Other income	83	46	24	30	3	491	677
Earnings before interest, income taxes and depreciation and amortization									Earnings before interest, income taxes and depreciation and amortization	4,814	2,247	1,083	265	23	535	8,967
Depreciation and amortization	Depreciation and amortization							(3,195)	Depreciation and amortization							(2,283)
Interest expense	Interest expense							(2,316)	Interest expense							(1,788)
Income tax expense	Income tax expense							(1,044)	Income tax expense							(1,029)
Earnings	Earnings							4,047	Earnings							3,867
Capital expenditures1	Capital expenditures1	1,086	1,087	1,005	26	—	32	3,236	Capital expenditures1	517	870	610	68	—	52	2,117


Nine months ended September 30, 2021		Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Six months ended June 30, 2022									Six months ended June 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)	(millions of Canadian dollars)								(millions of Canadian dollars)
Operating revenues	Operating revenues	7,616	3,501	3,463	371	20,068	(468)	34,551	Operating revenues	5,693	2,601	3,549	311	16,475	(317)	28,312
Commodity and gas distribution costs	Commodity and gas distribution costs	(16)	—	(1,392)	—	(20,405)	479	(21,334)	Commodity and gas distribution costs	(27)	—	(1,931)	(8)	(16,732)	314	(18,384)
Operating and administrative	Operating and administrative	(2,411)	(1,303)	(794)	(131)	(36)	(35)	(4,710)	Operating and administrative	(1,923)	(1,075)	(580)	(101)	(25)	(165)	(3,869)

Income from equity investments		560	525	37	65	—	—	1,187
Impairment of equity investments		—	(111)			—		(111)
Income/(loss) from equity investments									Income/(loss) from equity investments	368	556	1	78	—	(2)	1,001

Other income/(expense)	Other income/(expense)	7	113	60	57	(6)	215	446	Other income/(expense)	36	51	43	4	4	(179)	(41)
Earnings/(loss) before interest, income taxes and depreciation and amortization	Earnings/(loss) before interest, income taxes and depreciation and amortization	5,756	2,725	1,374	362	(379)	191	10,029	Earnings/(loss) before interest, income taxes and depreciation and amortization	4,147	2,133	1,082	284	(278)	(349)	7,019
Depreciation and amortization	Depreciation and amortization							(2,805)	Depreciation and amortization							(2,119)
Interest expense	Interest expense							(1,923)	Interest expense							(1,510)
Income tax expense	Income tax expense							(952)	Income tax expense							(726)
Earnings	Earnings							4,349	Earnings							2,664
Capital expenditures1	Capital expenditures1	3,385	1,631	878	7	1	42	5,944	Capital expenditures1	818	562	600	17	—	24	2,021

1Includes allowance for equity funds used during construction.

1716

5.4. 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. On December 30, 2021, we closed the sale of our minority ownership in Noverco Inc. (Noverco). For both the three and nine months ended September 30, 2021, the weighted average number of common shares outstanding was reduced by our pro-rata weighted average interest in our own common shares of approximately 2 million, resulting from our reciprocal investment in Noverco.

DILUTED

The treasury stock method is used to determine the dilutive impact of stock options and ~~restricted stock units (RSU).~~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,			Three months ended June 30,		Six months ended June 30,
		2022	2021	2022	2021		2023	2022	2023	2022
(number of shares in millions)	(number of shares in millions)					(number of shares in millions)
Weighted average shares outstanding	Weighted average shares outstanding	2,025	2,024	2,026	2,023	Weighted average shares outstanding	2,024	2,026	2,025	2,026
Effect of dilutive options and RSUs	Effect of dilutive options and RSUs	3	2	3	2	Effect of dilutive options and RSUs	3	4	3	4
Diluted weighted average shares outstanding	Diluted weighted average shares outstanding	2,028	2,026	2,029	2,025	Diluted weighted average shares outstanding	2,027	2,030	2,028	2,030

For the three months ended ~~September~~June 30, 2023 and 2022, ~~and 2021, 11.4~~16.3 million and ~~13.3~~3.2 million, respectively, of anti-dilutive stock options with a weighted average exercise price of ~~$56.49~~$55.46 and ~~$56.16,~~$59.29, respectively, were

excluded from the diluted earnings per common share calculation.

For the ~~nine~~six months ended ~~September~~June 30, 2023 and 2022, ~~and 2021, 9.2~~16.5 million and ~~20.5~~8.0 million, respectively, of anti-dilutive stock options with a weighted average exercise price of ~~$56.63~~$55.54 and ~~$52.19,~~$56.72, respectively, were excluded from the diluted earnings per common share calculation.

1817

DIVIDENDS PER SHARE

On ~~November 2, 2022,~~July 31, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on ~~December~~September 1, ~~2022~~2023 to shareholders of record on ~~November~~August 15, ~~2022.~~2023.


			Dividend per share
Common Shares1			$~~0.86000~~0.88750
Preference Shares, Series A			$0.34375
Preference Shares, Series B2			$0.32513
Preference Shares, Series D			$~~0.27875~~0.33825
Preference Shares, Series F1			$~~0.29306~~0.34613
Preference Shares, Series G2			$0.43858
Preference Shares, Series H			$0.27350
Preference Shares, Series L3			US$0.36612
Preference Shares, Series N			$0.31788
Preference Shares, Series P			$0.27369
Preference Shares, Series R			$0.25456
Preference Shares, Series 13			US$~~0.37182~~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 19			$~~0.30625~~0.38825

1The quarterly dividend per ~~common share was increased 3% to $0.86 from $0.835, effective March 1, 2022.~~

2~~The quarterly dividend per~~ share paid on Preference Shares, Series BF was increased to ~~$0.32513~~$0.34613 from ~~$0.21340~~$0.29306 on June 1, ~~2022~~2023 due to reset of the annual dividend on June 1, ~~2022.~~2023.

2The first quarterly dividend on Preference Shares, Series G will be paid on September 1, 2023. On June 1, ~~2022, all~~2023, 1,827,695 of the outstanding Preference Shares, Series CF were converted tointo Preference Shares, Series B.G.

3The quarterly dividend per share paid on Preference Shares, Series L1 was increased to US$~~0.36612~~0.41898 from US$~~0.30993~~0.37182 on ~~September~~June 1, ~~2022~~2023 due to reset of the annual dividend on ~~September~~June 1, ~~2022.~~2023.

~~PREFERENCE SHARE REDEMPTIONS~~

5. ACQUISITION

TRES PALACIOS HOLDINGS LLC

On ~~March 1, 2022,~~April 3, 2023, we ~~redeemed our $750~~acquired Tres Palacios Holdings LLC (Tres Palacios) for US$335 million ~~outstanding Cumulative Redeemable Minimum Rate Reset Preference Shares, Series 17. On June 1, 2022, we also redeemed our~~of cash. Tres Palacios is a natural gas storage facility located in the 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 US$~~200~~588 million ~~outstanding Cumulative Redeemable Preference Shares, Series J. Dividends are cumulative, payable quarterly~~to Property, plant and ~~are included in Preference share dividends~~equipment, net, of which US$189 million relates to storage cavern right-of-use assets, and recorded the related lease liabilities of US$5 million and US$184 million to Current portion of long-term debt and Long-term debt, respectively, in the Consolidated Statements of ~~Earnings.~~Financial Position. The acquired assets are included in our Gas Transmission and Midstream segment.

1918

6. ~~ACQUISITIONS AND DISPOSITIONS~~

~~DCP MIDSTREAM, LLC~~

On August 17, 2022, we completed a joint venture merger transaction with Phillips 66 (P66) resulting in a single joint venture, DCP Midstream, LLC, holding both our and P66'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 indirect economic interest in Gray Oak to 58.5% from 22.8% and reduced our indirect economic interest in DCP to 13.2% from 28.3%. As a result of the transaction, Enbridge will assume 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 United States (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 Acquisition). The Acquisition is subject to customary closing and working capital adjustments. TGE is an onshore renewable project developer in the US with a development portfolio of wind and solar projects. The Acquisition enhances Enbridge's renewable power platform and accelerates our North American growth strategy.

~~We accounted for the 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 preliminary 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 liabilities (b)~~			~~123~~
~~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 two 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 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 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 and 2021, as if the 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~~. We will maintain 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. On October 5, 2022, we closed the sale for total consideration of approximately $1.1 billion, less customary closing adjustments.

7. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at ~~September~~June 30, ~~2022:~~2023:


		Maturity1	Total Facilities	Draws2	Available		Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Enbridge Inc.	Enbridge Inc.	2023-2027	10,949	9,451	1,498	Enbridge Inc.	2024-2027	8,860	4,341	4,519
Enbridge (U.S.) Inc.	Enbridge (U.S.) Inc.	2024-2027	8,245	3,909	4,336	Enbridge (U.S.) Inc.	2024-2027	8,403	4,260	4,143
Enbridge Pipelines Inc.	Enbridge Pipelines Inc.	2024	2,000	858	1,142	Enbridge Pipelines Inc.	2024	2,000	930	1,070
Enbridge Gas Inc.	Enbridge Gas Inc.	2024	2,000	1,885	115	Enbridge Gas Inc.	2024	2,500	850	1,650
Total committed credit facilities	Total committed credit facilities		23,194	16,103	7,091	Total committed credit facilities		21,763	10,381	11,382

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

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

~~On February 10, 2022, we renewed our three year $1.0 billion sustainability-linked credit facility, extending the maturity date out to July 2025.~~

On May 17, 2022, we entered into a three year term loan with a syndicate of Japanese banks for approximately $806 million (¥84.8 billion), which will mature in May 2025 and replaces the approximately $499 million (¥52.5 billion) term loan that matured in May 2022. Additionally, on May 24, 2022, we entered into a 364-day term loan for approximately $1.9 billion, which will mature in May 2023.

~~On June 23, 2022, we renewed approximately $5.5 billion of our~~In March 2023, Enbridge Gas Inc. (Enbridge Gas) increased its 364-day extendible credit ~~facilities~~facility from $2.0 billion to $2.5 billion and in July 2023, the facility's maturity date was extended to July ~~2024,~~2025, which includes a one-year term out provision from July ~~2023.~~2024.

In July ~~and August 2022, we renewed $12.7 billion of our credit facilities, extending~~2023, Enbridge Pipelines Inc. extended the maturity ~~dates~~date of ~~our~~its 364-day extendible credit ~~facilities~~facility to July ~~2024, inclusive of~~2025, which includes a one-year term out provision from July 2024.

In July 2023, ~~and~~we renewed approximately $6.8 billion of our ~~five year~~364-day extendible credit facilities, ~~out~~extending the maturity dates to July ~~2027. As~~2025, which includes a ~~part~~one-year term out provision from July 2024. We also renewed approximately $7.6 billion of ~~the renewals, we increased~~ our five-year credit facilities, ~~by approximately $641 million.~~extending the maturity dates to July 2028. Further, we extended our three-year credit facilities, extending the maturity dates to July 2026.

In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which ~~$780~~$723 million was unutilized as at ~~September~~June 30, ~~2022.~~2023. As at December 31, ~~2021,~~2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which ~~$854~~$689 million was unutilized.

Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2024 to 2027.

As at ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of ~~$11.9~~$9.5 billion and ~~$11.3~~$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~~six months ended ~~September~~June 30, ~~2022,~~2023, we completed the following long-term debt issuances totaling ~~$1.4~~US$3.0 billion and ~~US$2.6~~$1.5 billion:

Company

Issue Date

Principal Amount

Company

Issue Date

Principal Amount

(millions of Canadian dollars unless otherwise stated)

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

January 2022

5.00%

fixed-to-fixed subordinated notes due January 20821

$750

March 2023

5.70%

sustainability-linked senior notes due March 20331

US$2,300

February 2022

Floating rate senior notes due February 20242

US$600

March 2023

5.97%

senior notes due March 20262

US$700

February 2022

2.15%

senior notes due February 2024

US$400

May 2023

4.90%

medium-term notes due May 2028

$600

February 2022

2.50%

senior notes due February 2025

US$500

May 2023

5.36%

sustainability-linked medium-term notes due May 20333

$400

September 2022

7.38%

fixed-to-fixed subordinated notes due January 20833

US$500

May 2023

5.76%

medium-term notes due May 2053

$500

September 2022

7.63%

fixed-to-fixed subordinated notes due January 20834

US$600

Enbridge Gas Inc.

August 2022

4.15

medium-term notes due August 2032

$325

August 2022

4.55

medium-term notes due August 2052

$325

1~~For~~The 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 ~~initial 10 years, the notes carry a fixed interest rate. At year 10,~~target is not met, on September 8, 2031, the interest rate will be ~~reset~~set to equal ~~to the Five-Year Government of Canada bond yield~~5.70% plus a margin of ~~3.54%. Subsequent~~50 basis points.

2We have the option to call the notes at par after one year ~~10, every five years,~~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 ~~Five Year Government of Canada bond yield~~target is ~~reset. At year 30,~~not met, on November 26, 2031, the interest rate will be ~~reset~~set to equal ~~to the Five-Year Government of Canada bond yield~~5.36% plus a margin of ~~4.29%.~~50 basis points.

LONG-TERM DEBT REPAYMENTS

During the six months ended June 30, 2023, we completed the following long-term debt repayments totaling US$1.2 billion and $0.7 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 Pipelines (Southern Lights) L.L.C.

June 2023

3.98

senior notes

US$38

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

1~~Notes carry~~The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 6340 basis points.

32~~For the initial five years, the~~The five-year callable notes, ~~carry a fixed interest rate. At year five, the interest rate will be set to equal to the Five-Year US Treasury rate plus a margin~~with an original maturity date of 3.71%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.96%. 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 4.71%.

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 4.42%. Subsequent to year 10, every five years, the Five-Year US Treasury rate will be reset. At year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.17%.

~~LONG-TERM DEBT REPAYMENTS~~

~~During the nine months ended September 30, 2022, we completed the following long-term debt repayments totaling US$1.5 billion and $0.3 billion:~~

Company Repayment Date Principal Amount
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
February 2022
Floating rate notes1
US$750
February 2022 4.85% medium-term notes $200
July 2022 2.90% senior notes due July 2022 US$700
Enbridge Gas Inc.
April 2022 4.85% medium-term notes $125
Enbridge Pipelines (Southern Lights) L.L.C.
June 2022 3.98% senior notes US$34
Enbridge Southern Lights LP
June 2022 4.01% senior notes $9

1~~Notes carried an interest rate set to equal the three-month London Interbank Offered Rate plus a margin of 50 basis points.~~April 2078, were all redeemed at par.

SUBORDINATED TERM NOTES

As at ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of ~~$10.4~~$9.4 billion and ~~$7.7~~$10.3 billion, respectively.

FAIR VALUE ADJUSTMENT

As at ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, the net fair value adjustments to total debt assumed in a historical acquisition were ~~$630~~$565 million and ~~$667~~$608 million, respectively.

~~During the three and nine months ended September 30, 2022, amortization~~ Amortization of the fair value adjustment is recorded as a reduction to Interest expense in the Consolidated Statements of ~~Earnings was $11 million (September 30, 2021 - $11 million) and $33 million (September 30, 2021 - $36 million), respectively.~~Earnings:


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Amortization of fair value adjustment	11	11	22	22

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 ~~are~~were to default on payment or violate certain covenants. As at ~~September~~June 30, ~~2022,~~2023, we ~~are~~were in compliance with all covenant provisions.

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

Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to our common shareholders for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021~~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, 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 contracts2
(4) — — — — — (4)
Other contracts3
3 — — — — — 3
Amortization of pension and OPEB actuarial gain4
— — — — — (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


	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	126	9	400	(1,482)	—	—	(947)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	23	—	—	—	—	—	23
Commodity contracts2	(1)	—	—	—	—	—	(1)

Other contracts3	1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial gain4	—	—	—	—	—	(10)	(10)

	149	9	400	(1,482)	—	(10)	(934)
Tax impact
Income tax on amounts retained in AOCI	(23)	—	—	—	—	—	(23)
Income tax on amounts reclassified to earnings	(4)	—	—	—	—	2	(2)
	(27)	—	—	—	—	2	(25)

Balance as at June 30, 2023	243	(26)	(737)	2,866	5	210	2,561

2421


		Cash Flow Hedges	Excluded Components of Fair Value Hedges	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees	Pension and OPEB Adjustment	Total		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)	(millions of Canadian dollars)								(millions of Canadian dollars)
Balance as at January 1, 2021		(1,326)	5	(215)	568	66	(499)	(1,401)
Balance as at January 1, 2022									Balance as at January 1, 2022	(897)	—	(166)	56	(5)	(84)	(1,096)
Other comprehensive income/(loss) retained in AOCI	Other comprehensive income/(loss) retained in AOCI	284	(3)	18	(340)	(33)	—	(74)	Other comprehensive income/(loss) retained in AOCI	854	(5)	(253)	1,136	—	—	1,732
Other comprehensive loss/(income) reclassified to earnings	Other comprehensive loss/(income) reclassified to earnings								Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	Interest rate contracts1	218	—	—	—	—	—	218	Interest rate contracts1	142	—	—	—	—	—	142
Foreign exchange contracts2		4	—	—	—	—	—	4

Foreign exchange contracts5									Foreign exchange contracts5	(4)	—	—	—	—	—	(4)
Other contracts3	Other contracts3	1	—	—	—	—	—	1	Other contracts3	2	—	—	—	—	—	2
Commodity contracts5		(4)	—	—	—	—	—	(4)
Amortization of pension and OPEB actuarial loss4		—	—	—	—	—	21	21
Other		17	—	—	(20)	3	—	—
Amortization of pension and OPEB actuarial gain4									Amortization of pension and OPEB actuarial gain4	—	—	—	—	—	(6)	(6)

		520	(3)	18	(360)	(30)	21	166		994	(5)	(253)	1,136	—	(6)	1,866
Tax impact	Tax impact								Tax impact
Income tax on amounts retained in AOCI	Income tax on amounts retained in AOCI	(72)	—	(2)	—	5	—	(69)	Income tax on amounts retained in AOCI	(202)	—	—	—	—	—	(202)
Income tax on amounts reclassified to earnings	Income tax on amounts reclassified to earnings	(51)	—	—	—	—	(5)	(56)	Income tax on amounts reclassified to earnings	(31)	—	—	—	—	1	(30)
		(123)	—	(2)	—	5	(5)	(125)		(233)	—	—	—	—	1	(232)

Balance as at September 30, 2021		(929)	2	(199)	208	41	(483)	(1,360)
Balance as at June 30, 2022									Balance as at June 30, 2022	(136)	(5)	(419)	1,192	(5)	(89)	538

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

2Reported within Transportation and other services revenues ~~and Net foreign currency gain/(loss)~~ in the Consolidated Statements of Earnings.

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

4These components are included in the computation of net periodic benefit ~~(credit)/cost~~credit and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

5Reported within Transportation and other services revenues ~~Commodity sales revenue, Commodity costs~~ and ~~Operating and administrative expense~~Other income/(expense) in the Consolidated Statements of Earnings.

9.8. 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 ~~cash flow, fair value~~ and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in ~~US dollar denominated~~United States (US) dollar-denominated investments and subsidiaries using foreign currency derivatives and US ~~dollar denominated~~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~~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 viathe execution of floating-to-fixed interest rate swaps. These hedges have an average fixed rate of ~~2.5%~~ 4.1%.

~~We are exposed to changes in the fair value of~~On March 8, 2023, we issued US$700 million three-year fixed rate ~~debt that arise as~~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 ~~result of~~similar right to cancel the ~~changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to~~swap after the ~~fair value of~~first year. This swap has a fixed rate ~~debt which mitigates the impact~~ of ~~fluctuations in the fair value of fixed rate debt via execution of fixed-to-floating interest rate swaps. As at September 30, 2022, we did not have any~~6.0%. This instrument was our only pay floating-receive fixed interest rate ~~swaps outstanding.~~swap outstanding as at June 30, 2023.

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~~forecasted term debt issuances via the execution of floating-to-fixed interest rate swaps with an average swap rate of ~~2.1%~~ 2.6%.

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 ~~the~~ outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, ~~restricted share units.~~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, 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)
Accounts receivable and other
Foreign exchange contracts — — 65 65 (37) 28
Interest rate contracts 127 — 1 128 (17) 111
Commodity contracts — — 414 414 (230) 184
Other contracts 1 — 5 6 — 6
128 — 485 613 1 (284) 329
Deferred amounts and other assets
Foreign exchange contracts — 117 203 320 (164) 156
Interest rate contracts 830 — — 830 — 830
Commodity contracts — — 66 66 (26) 40
Other contracts 1 — — 1 (1) —
831 117 269 1,217 (191) 1,026
Accounts payable and other
Foreign exchange contracts — (37) (693) (730) 37 (693)
Interest rate contracts (1) — (16) (17) 17 —
Commodity contracts (32) — (380) (412) 230 (182)
Other contracts — — — — — —
(33) (37) (1,089) (1,159) 1 284 (875)
Other long-term liabilities
Foreign exchange contracts — (6) (1,423) (1,429) 164 (1,265)
Interest rate contracts (3) — — (3) — (3)
Commodity contracts (27) — (145) (172) 26 (146)
Other contracts (1) — — (1) 1 —
(31) (6) (1,568) (1,605) 191 (1,414)
Total net derivative assets/(liabilities)
Foreign exchange contracts — 74 (1,848) (1,774) — (1,774)
Interest rate contracts 953 — (15) 938 — 938
Commodity contracts (59) — (45) (104) — (104)
Other contracts 1 — 5 6 — 6
895 74 (1,903) (934) — (934)

1As at September 30, 2022, $28 million and $36 million were reported within Accounts receivable from affiliates and Accounts payable to affiliates, respectively, in the Consolidated Statements of Financial Position.

2723


December 31, 2021		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
June 30, 2023								June 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)	(millions of Canadian dollars)							(millions of Canadian dollars)
Accounts receivable and other
Other current assets								Other current assets
Foreign exchange contracts	Foreign exchange contracts	—	—	259	259	(41)	218	Foreign exchange contracts	—	40	89	129	(16)	113
Interest rate contracts	Interest rate contracts	64	—	—	64	—	64	Interest rate contracts	205	—	58	263	(2)	261
Commodity contracts	Commodity contracts	—	—	204	204	(129)	75	Commodity contracts	—	—	239	239	(130)	109
Other contracts	Other contracts	—	—	2	2	—	2	Other contracts	—	—	1	1	—	1
		64	—	465	529	(170)	359		205	40	387	632	(148)	484
Deferred amounts and other assets	Deferred amounts and other assets							Deferred amounts and other assets
Foreign exchange contracts	Foreign exchange contracts	—	—	240	240	(61)	179	Foreign exchange contracts	—	17	161	178	(117)	61
Interest rate contracts	Interest rate contracts	88	—	—	88	(1)	87	Interest rate contracts	198	—	15	213	(5)	208
Commodity contracts	Commodity contracts	—	—	29	29	(13)	16	Commodity contracts	—	—	68	68	(41)	27
Other contracts		—	—	3	3	—	3
		88	—	272	360	(75)	285
Accounts payable and other
									198	17	244	459	(163)	296
Other current liabilities								Other current liabilities
Foreign exchange contracts	Foreign exchange contracts	(15)	(112)	(176)	(303)	41	(262)	Foreign exchange contracts	—	(47)	(39)	(86)	16	(70)
Interest rate contracts	Interest rate contracts	(150)	—	—	(150)	—	(150)	Interest rate contracts	—	—	(2)	(2)	2	—
Commodity contracts	Commodity contracts	(14)	—	(250)	(264)	129	(135)	Commodity contracts	(37)	—	(223)	(260)	130	(130)

		(179)	(112)	(426)	(717)	170	(547)		(37)	(47)	(264)	(348)	148	(200)
Other long-term liabilities	Other long-term liabilities							Other long-term liabilities
Foreign exchange contracts	Foreign exchange contracts	—	—	(423)	(423)	61	(362)	Foreign exchange contracts	—	(29)	(587)	(616)	117	(499)
Interest rate contracts	Interest rate contracts	(1)	—	(23)	(24)	1	(23)	Interest rate contracts	(4)	—	(5)	(9)	5	(4)
Commodity contracts	Commodity contracts	(17)	—	(67)	(84)	13	(71)	Commodity contracts	(12)	—	(101)	(113)	41	(72)

		(18)	—	(513)	(531)	75	(456)		(16)	(29)	(693)	(738)	163	(575)
Total net derivative assets/(liabilities)
Total net derivative asset/(liability)								Total net derivative asset/(liability)
Foreign exchange contracts	Foreign exchange contracts	(15)	(112)	(100)	(227)	—	(227)	Foreign exchange contracts	—	(19)	(376)	(395)	—	(395)
Interest rate contracts	Interest rate contracts	1	—	(23)	(22)	—	(22)	Interest rate contracts	399	—	66	465	—	465
Commodity contracts	Commodity contracts	(31)	—	(84)	(115)	—	(115)	Commodity contracts	(49)	—	(17)	(66)	—	(66)
Other contracts	Other contracts	—	—	5	5	—	5	Other contracts	—	—	1	1	—	1
		(45)	(112)	(202)	(359)	—	(359)		350	(19)	(326)	5	—	5


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.~~instruments:


September 30, 2022		2022	2023	2024	2025	2026	Thereafter	Total
June 30, 2023										June 30, 2023	2023	2024	2025	2026	2027	Thereafter	Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)	Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)	799	4	1,000	500	—	—	2,303		Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)	535	1,000	500	—	—	—	2,035
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)	Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)	3,017	7,185	6,134	4,361	3,761	1,481	25,939		Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)	3,052	4,708	4,763	4,157	3,131	2,010	21,821
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	7	29	30	30	28	32	156		Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	17	30	30	28	32	—	137

Foreign exchange contracts - Euro forwards - sell (millions of Euro)	Foreign exchange contracts - Euro forwards - sell (millions of Euro)	23	92	91	86	85	343	720		Foreign exchange contracts - Euro forwards - sell (millions of Euro)	46	91	86	85	81	262	651
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	—	—	—	84,800	—	—	84,800		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)	Interest rate contracts - short-term debt pay fixed rate (millions of Canadian dollars)	2,715	3,190	241	31	26	64	6,267		Interest rate contracts - short-term debt pay fixed rate (millions of Canadian dollars)	5,267	4,028	1,072	891	67	39	11,364
Interest rate contracts - short-term debt receive fixed rate (millions of Canadian dollars)										Interest rate contracts - short-term debt receive fixed rate (millions of Canadian dollars)	448	926	926	175	—	—	2,475
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	900	4,099	1,781	594	—	—	7,374		Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	3,304	1,478	581	—	—	—	5,363
Equity contracts (millions of Canadian dollars)	Equity contracts (millions of Canadian dollars)	—	36	31	11	—	—	78		Equity contracts (millions of Canadian dollars)	—	32	12	—	—	—	44
Commodity contracts - natural gas (billions of cubic feet)1		33	49	21	13	3	—	119
Commodity contracts - crude oil (millions of barrels)1		3	—	—	—	—	—	3
Commodity contracts - natural gas (billions of cubic feet)										Commodity contracts - natural gas (billions of cubic feet)	15	39	25	6	3	—	88
Commodity contracts - crude oil (millions of barrels)										Commodity contracts - crude oil (millions of barrels)	7	(4)	—	—	—	—	3

Commodity contracts - power (megawatt per hour) (MW/H)	Commodity contracts - power (megawatt per hour) (MW/H)	5	(25)	(33)	(43)	—	—	(31)	2	Commodity contracts - power (megawatt per hour) (MW/H)	98	2	(22)	3	(3)	—	7	1

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

2Total is an average net purchase/(sale) of power.

2825

Fair Value Derivatives

For foreign exchange derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative is included in ~~Net foreign currency gain/(loss)~~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 ~~Net foreign currency gain/(loss)~~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,			Three months ended June 30,		Six months ended June 30,
		2022	2021	2022	2021		2023	2022	2023	2022
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Unrealized gain on derivative		122	50	221	15
Unrealized loss on hedged item		(122)	(50)	(211)	(22)
Unrealized gain/(loss) on derivative						Unrealized gain/(loss) on derivative	(131)	23	(142)	99
Unrealized gain/(loss) on hedged item						Unrealized gain/(loss) on hedged item	130	(2)	141	(89)
Realized loss on derivative	Realized loss on derivative	(5)	(1)	(101)	(40)	Realized loss on derivative	(12)	(21)	(23)	(96)
Realized gain on hedged item	Realized gain on hedged item	—	—	85	45	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,			Three months ended June 30,		Six months ended June 30,
		2022	2021	2022	2021		2023	2022	2023	2022
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI	Amount of unrealized gain/(loss) recognized in OCI					Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges	Cash flow hedges					Cash flow hedges
Foreign exchange contracts	Foreign exchange contracts	1	4	3	(21)	Foreign exchange contracts	—	—	—	2
Interest rate contracts	Interest rate contracts	230	(1)	1,087	293	Interest rate contracts	215	480	110	857
Commodity contracts	Commodity contracts	(16)	(21)	(27)	(25)	Commodity contracts	2	(15)	36	(11)
Other contracts	Other contracts	(4)	(2)	(4)	2	Other contracts	—	(3)	(2)	—
Fair value hedges	Fair value hedges					Fair value hedges
Foreign exchange contracts	Foreign exchange contracts	(33)	(1)	(38)	(3)	Foreign exchange contracts	2	(4)	9	(5)

		178	(21)	1,021	246		219	458	153	843
Amount of (gain)/loss reclassified from AOCI to earnings	Amount of (gain)/loss reclassified from AOCI to earnings					Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts1	Foreign exchange contracts1	—	1	13	4	Foreign exchange contracts1	—	—	—	13
Interest rate contracts2	Interest rate contracts2	45	76	187	218	Interest rate contracts2	15	66	23	142
Commodity contracts		—	(4)	—	(4)
Other contracts3		1	—	3	1
Commodity contracts3						Commodity contracts3	(1)	—	(1)	—
Other contracts4						Other contracts4	—	—	1	2
		46	73	203	219		14	66	23	157

1Reported within Transportation and other services revenues and ~~Net foreign currency gain/(loss)~~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 ~~$57~~$16 million offrom AOCI related to ~~unrealized~~ cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 3930 months as at ~~September~~June 30, ~~2022.~~2023.

2926

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,			Three months ended June 30,		Six months ended June 30,
		2022	2021	2022	2021		2023	2022	2023	2022
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Foreign exchange contracts1	Foreign exchange contracts1	(1,379)	(436)	(1,752)	18	Foreign exchange contracts1	509	(806)	1,065	(373)
Interest rate contracts2	Interest rate contracts2	17	2	1	4	Interest rate contracts2	45	(16)	55	(16)
Commodity contracts3	Commodity contracts3	89	(102)	59	(120)	Commodity contracts3	62	38	23	(30)
Other contracts4	Other contracts4	(3)	2	1	12	Other contracts4	(1)	—	(8)	4
Total unrealized derivative fair value loss, net		(1,276)	(534)	(1,691)	(86)
Total unrealized derivative fair value gain/(loss), net						Total unrealized derivative fair value gain/(loss), net	615	(784)	1,135	(415)

1For the respective ~~nine~~six months ended periods, reported within Transportation and other services revenues ~~(2022~~(2023 - ~~$375~~$645 million ~~loss; 2021~~gain; 2022 - ~~$71~~$65 million ~~gain)~~loss) and ~~Net foreign currency gain/(loss) (2022~~Other income/(expense) (2023 - ~~$1,377~~$420 million ~~loss; 2021~~gain; 2022 - ~~$53~~$308 million loss) in the Consolidated Statements of Earnings.

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

3For the respective ~~nine~~six months ended periods, reported within Transportation and other services revenues ~~(2022~~(2023 - ~~$12~~$8 million gain; ~~2021~~2022 - ~~nil)~~$25 million gain), Commodity sales ~~(2022~~(2023 - ~~$151~~$96 million gain; ~~2021~~2022 - $5$109 million ~~loss)~~gain), Commodity costs ~~(2022~~(2023 - ~~$116~~$51 million loss; ~~2021~~2022 - ~~$124~~$167 million loss) and Operating and administrative expense ~~(2022~~(2023 - ~~$12~~$30 million ~~gain; 2021~~loss; 2022 - $8$3 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 ~~are~~were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at ~~September~~June 30, ~~2022.~~2023. As a result, all credit facilities are available to us and the banks are obligated to fund ~~and have been funding~~ us under the terms of the facilities.

CREDIT RISK

Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through 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.

3027

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


		September 30, 2022	December 31, 2021		June 30, 2023	December 31, 2022
(millions of Canadian dollars)	(millions of Canadian dollars)			(millions of Canadian dollars)
Canadian financial institutions	Canadian financial institutions	637	424	Canadian financial institutions	499	644
US financial institutions	US financial institutions	361	130	US financial institutions	136	277
European financial institutions	European financial institutions	441	181	European financial institutions	214	334
Asian financial institutions	Asian financial institutions	208	30	Asian financial institutions	109	224
Other1	Other1	165	122	Other1	89	105
		1,812	887		1,047	1,584

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

As at ~~September~~June 30, ~~2022,~~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~~June 30, ~~2022~~2023 and December 31, ~~2021.~~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, ~~Inc.,~~ credit risk is mitigated by the utility's large and diversified customer base and the ability to recover an estimate for expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

FAIR VALUE MEASUREMENTS

Our financial assets and liabilities measured at fair value on a recurring basis include ~~derivative~~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 equity funds held by our captive insurance subsidiaries, as well as restricted long-term investments in Canadian equity securities that are held in trust in accordance with the CER's regulatory requirements under the Land Matters Consultation Initiative (LMCI).

3128

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~~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 available-for-sale preferred share investment is based on the redemption value, which equals the face value plus accrued and unpaid interest periodically reset based on market interest rates. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. 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 ~~derivative’s~~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.

3229

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


September 30, 2022		Level 1	Level 2	Level 3	Total Gross Derivative Instruments
June 30, 2023						June 30, 2023	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Financial assets	Financial assets					Financial assets
Current derivative assets	Current derivative assets					Current derivative assets
Foreign exchange contracts	Foreign exchange contracts	—	65	—	65	Foreign exchange contracts	—	129	—	129
Interest rate contracts	Interest rate contracts	—	128	—	128	Interest rate contracts	—	263	—	263
Commodity contracts	Commodity contracts	120	142	152	414	Commodity contracts	43	47	149	239
Other contracts	Other contracts	—	6	—	6	Other contracts	—	1	—	1
		120	341	152	613		43	440	149	632
Long-term derivative assets	Long-term derivative assets					Long-term derivative assets
Foreign exchange contracts	Foreign exchange contracts	—	320	—	320	Foreign exchange contracts	—	178	—	178
Interest rate contracts	Interest rate contracts	—	830	—	830	Interest rate contracts	—	213	—	213
Commodity contracts	Commodity contracts	—	24	42	66	Commodity contracts	—	17	51	68
Other contracts		—	1	—	1

		—	1,175	42	1,217		—	408	51	459
Financial liabilities	Financial liabilities					Financial liabilities
Current derivative liabilities	Current derivative liabilities					Current derivative liabilities
Foreign exchange contracts	Foreign exchange contracts	—	(730)	—	(730)	Foreign exchange contracts	—	(86)	—	(86)
Interest rate contracts	Interest rate contracts	—	(17)	—	(17)	Interest rate contracts	—	(2)	—	(2)
Commodity contracts	Commodity contracts	(56)	(188)	(168)	(412)	Commodity contracts	(21)	(39)	(200)	(260)
Other contracts		—	—	—	—

		(56)	(935)	(168)	(1,159)		(21)	(127)	(200)	(348)
Long-term derivative liabilities	Long-term derivative liabilities					Long-term derivative liabilities
Foreign exchange contracts	Foreign exchange contracts	—	(1,429)	—	(1,429)	Foreign exchange contracts	—	(616)	—	(616)
Interest rate contracts	Interest rate contracts	—	(3)	—	(3)	Interest rate contracts	—	(9)	—	(9)
Commodity contracts	Commodity contracts	—	(49)	(123)	(172)	Commodity contracts	—	(26)	(87)	(113)
Other contracts		—	(1)	—	(1)
		—	(1,482)	(123)	(1,605)
Total net financial assets/(liabilities)
							—	(651)	(87)	(738)
Total net financial asset/(liability)						Total net financial asset/(liability)
Foreign exchange contracts	Foreign exchange contracts	—	(1,774)	—	(1,774)	Foreign exchange contracts	—	(395)	—	(395)
Interest rate contracts	Interest rate contracts	—	938	—	938	Interest rate contracts	—	465	—	465
Commodity contracts	Commodity contracts	64	(71)	(97)	(104)	Commodity contracts	22	(1)	(87)	(66)
Other contracts	Other contracts	—	6	—	6	Other contracts	—	1	—	1
		64	(901)	(97)	(934)		22	70	(87)	5

3330


December 31, 2021		Level 1	Level 2	Level 3	Total Gross Derivative Instruments
December 31, 2022						December 31, 2022	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Financial assets	Financial assets					Financial assets
Current derivative assets	Current derivative assets					Current derivative assets
Foreign exchange contracts	Foreign exchange contracts	—	259	—	259	Foreign exchange contracts	—	46	—	46
Interest rate contracts	Interest rate contracts	—	64	—	64	Interest rate contracts	—	660	—	660
Commodity contracts	Commodity contracts	38	71	95	204	Commodity contracts	65	90	147	302
Other contracts	Other contracts	—	2	—	2	Other contracts	—	7	—	7
		38	396	95	529		65	803	147	1,015
Long-term derivative assets	Long-term derivative assets					Long-term derivative assets
Foreign exchange contracts	Foreign exchange contracts	—	240	—	240	Foreign exchange contracts	—	309	—	309
Interest rate contracts	Interest rate contracts	—	88	—	88	Interest rate contracts	—	254	—	254
Commodity contracts	Commodity contracts	—	21	8	29	Commodity contracts	—	17	44	61
Other contracts	Other contracts	—	3	—	3	Other contracts	—	3	—	3
		—	352	8	360		—	583	44	627
Financial liabilities	Financial liabilities					Financial liabilities
Current derivative liabilities	Current derivative liabilities					Current derivative liabilities
Foreign exchange contracts	Foreign exchange contracts	—	(303)	—	(303)	Foreign exchange contracts	—	(566)	—	(566)
Interest rate contracts		—	(150)	—	(150)

Commodity contracts	Commodity contracts	(52)	(66)	(146)	(264)	Commodity contracts	(60)	(77)	(195)	(332)

		(52)	(519)	(146)	(717)		(60)	(643)	(195)	(898)
Long-term derivative liabilities	Long-term derivative liabilities					Long-term derivative liabilities
Foreign exchange contracts	Foreign exchange contracts	—	(423)	—	(423)	Foreign exchange contracts	—	(1,116)	—	(1,116)
Interest rate contracts	Interest rate contracts	—	(24)	—	(24)	Interest rate contracts	—	(4)	—	(4)
Commodity contracts	Commodity contracts	—	(19)	(65)	(84)	Commodity contracts	—	(38)	(132)	(170)

		—	(466)	(65)	(531)		—	(1,158)	(132)	(1,290)
Total net financial assets/(liabilities)
Total net financial asset/(liability)						Total net financial asset/(liability)
Foreign exchange contracts	Foreign exchange contracts	—	(227)	—	(227)	Foreign exchange contracts	—	(1,327)	—	(1,327)
Interest rate contracts	Interest rate contracts	—	(22)	—	(22)	Interest rate contracts	—	910	—	910
Commodity contracts	Commodity contracts	(14)	7	(108)	(115)	Commodity contracts	5	(8)	(136)	(139)
Other contracts	Other contracts	—	5	—	5	Other contracts	—	10	—	10
		(14)	(237)	(108)	(359)		5	(415)	(136)	(546)

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


September 30, 2022		Fair Value	Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
June 30, 2023								June 30, 2023	Fair Value	Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
(fair value in millions of Canadian dollars)	(fair value in millions of Canadian dollars)							(fair value in millions of Canadian dollars)
Commodity contracts - financial1	Commodity contracts - financial1							Commodity contracts - financial1
Natural gas	Natural gas	9	Forward gas price	5.41	12.51	7.75	$/mmbtu2	Natural gas	(16)	Forward gas price	1.59	8.82	4.48	$/mmbtu2
Crude	Crude	5	Forward crude price	64.09	108.87	77.06	$/barrel	Crude	(8)	Forward crude price	70.23	90.70	81.07	$/barrel

Power	Power	(80)	Forward power price	35.56	207.09	93.98	$/MW/H	Power	(91)	Forward power price	25.85	255.75	63.34	$/MW/H
Commodity contracts - physical1	Commodity contracts - physical1							Commodity contracts - physical1
Natural gas	Natural gas	(66)	Forward gas price	3.43	22.01	7.11	$/mmbtu2	Natural gas	(12)	Forward gas price	1.66	23.07	4.65	$/mmbtu2
Crude	Crude	24	Forward crude price	72.52	125.74	90.39	$/barrel	Crude	(3)	Forward crude price	73.18	116.60	86.60	$/barrel

Power	Power	11	Forward power price	37.08	175.52	81.95	$/MW/H	Power	43	Forward power price	24.26	96.39	55.05	$/MW/H
		(97)							(87)

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,			Six months ended June 30,
		2022	2021		2023	2022
(millions of Canadian dollars)	(millions of Canadian dollars)			(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	Level 3 net derivative liability at beginning of period	(108)	(191)	Level 3 net derivative liability at beginning of period	(136)	(108)
Total gain/(loss)	Total gain/(loss)			Total gain/(loss)
Included in earnings1	Included in earnings1	41	(181)	Included in earnings1	11	14
Included in OCI	Included in OCI	(28)	(29)	Included in OCI	35	(11)
Settlements	Settlements	(2)	167	Settlements	3	(2)
Level 3 net derivative liability at end of period	Level 3 net derivative liability at end of period	(97)	(234)	Level 3 net derivative liability at end of period	(87)	(107)

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~~June 30, ~~2022~~2023 or December 31, ~~2021.~~2022.

NET INVESTMENT HEDGES

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

During the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021,~~2022, we recognized an unrealized foreign exchange ~~loss~~gains of ~~$1,191~~$444 million and ~~gain~~losses of ~~$18~~$257 million, respectively, on the translation of US ~~dollar denominated debt. During the nine months ended September 30, 2022 and 2021, we recognized nil~~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 six months ended June 30, 2023 and ~~nil in OCI~~2022. No realized gains or losses associated with the settlement of foreign exchange forward contracts orwere recognized in OCI during the six months ended June 30, 2023 and 2022. During the six months ended June 30, 2023 and 2022, we recognized a realized loss of $44 million and nil, respectively, associated with the settlement of US ~~dollar denominated~~dollar-denominated debt that had matured during the ~~period.~~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 ~~$102~~$207 million and ~~$52~~$102 million as at ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, respectively.

~~We have~~ As at June 30, 2023, we had investments with a fair value of $664 million included in Restricted long-term investments ~~held in trust totaling $219 million and $217 million as at September 30, 2022 and December 31, 2021, respectively, which are classified as Level 1~~ in the ~~fair value hierarchy. We also have Restricted long-term investments held in trust totaling $350 million and $413 million as at September 30,~~Consolidated Statements of Financial Position (December 31, 2022 ~~and December 31, 2021, respectively, which are classified as Level 2 in the fair value hierarchy.~~- $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 June 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 $412 million (cost basis - $463 million) and $357 million (cost basis - $437 million) as at June 30, 2023 and December 31, 2022, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding gains of ~~$11~~$3 million and ~~losses of $120~~$37 million on these investments for the three and ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, respectively ~~(2021~~(2022 - losses of ~~$16~~$71 million and ~~$41~~$131 million, respectively).

3532

We have wholly-owned captive insurance subsidiaries whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures ~~in the US and Canada~~ of our operating subsidiaries and certain equity investments. As at ~~September~~June 30, ~~2022,~~2023, the fair value of ~~short- and long-term investment~~sinvestments in equity funds and debt securities held by our captive insurance subsidiaries was ~~$108~~$354 million and ~~$400~~$323 million, respectively (December 31, ~~2021~~2022 - ~~$14~~$335 million and ~~$290~~$298 million, respectively). Our investments in debt securities had a cost basis of $314 million as at June 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 ~~Accounts receivable~~Other current assets and ~~other and Long-ter~~mLong-term investments ~~respectively,~~ in the Consolidated Statements of Financial Position. There were unrealized holding ~~losses in equity funds and debt securities~~gains of ~~$13~~ $7 million and ~~$40~~$22 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, respectively ~~(2021~~(2022 - ~~gains~~losses of $1$19 million and $4$27 million, respectively).

As at ~~September~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, our long-term debt had a carrying value of ~~$80.7~~$78.7 billion and ~~$74.4~~$79.3 billion, respectively, before debt issuance costs and a fair value of ~~$74.2~~$73.8 billion and ~~$82.0~~$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~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, the non-current notes receivable had a carrying value of ~~$752~~$680 million and ~~$954~~$752 million, respectively, which also approximates their fair value.

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

~~10.~~9. INCOME TAXES

The effective income tax rates for the three months ended ~~September~~June 30, 2023 and 2022 were 20.6% and ~~2021 were 18.7% and 19.6%~~18.0%, respectively, and for the ~~nine~~six months ended ~~September~~June 30, 2023 and 2022 were 21.0% and ~~2021 were 20.5% and 18.0%~~21.4%, respectively.

The period-over-period changes in the effective income tax rates are due to the ~~effect~~effects of rate-regulated accounting for income taxes, higher investment tax credits available on certain capital projects in the US and ~~other permanent differences relative to earnings,~~ an increase in ~~US minimum tax, offset by a statutory rate decrease in Pennsylvania and an adjustment~~earnings attributable to ~~2020 regulatory~~

~~balances~~non-controlling interests, relative to higher earnings in the ~~three-month period of the prior year.~~2023 periods.

~~11. PENSION AND~~10. OTHER ~~POSTRETIREMENT BENEFITS~~INCOME

Three months ended September 30, Nine months ended September 30,
2022 2021 2022 2021
(millions of Canadian dollars)
Service cost 46 48 136 144
Interest cost1
40 32 122 96
Expected return on plan assets1
(98) (84) (294) (252)
Amortization of actuarial (gain)/loss1
(1) 14 (3) 42
Net periodic benefit (credit)/cost (13) 10 (39) 30

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


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Gain/(loss) on dispositions	8	1	11	(1)
Realized foreign currency gain	1	2	146	4
Unrealized foreign currency gain/(loss)	492	(583)	304	(216)
Net defined pension and OPEB credit	34	59	67	117
Other	40	22	149	55
	575	(499)	677	(41)

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~~12.~~11. CONTINGENCIES

LITIGATION

We and our subsidiaries are ~~involved in~~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.

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.

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, ~~2021.~~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

~~Joint Venture Merger Transaction to Advance US Gulf Coast Oil Strategy~~

~~On August 17, 2022, we completed a joint venture merger transaction with Phillips 66 (P66) resulting in a single joint venture, DCP Midstream LLC, holding both~~ MAINLINE TOLLING AGREEMENT

Enbridge Inc.'s (Enbridge) ~~and P66's indirect ownership interests in Gray Oak Pipeline, LLC (Gray Oak) and DCP Midstream, LP (DCP), as well as~~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 realign our respective economic and governance interests in the underlying business operations. Our indirect economic interest in Gray Oak has increased to 58.5% from 22.8% and we will assume operatorship of Gray Oak in the second quarter of 2023. Simultaneously, our indirect economic interest in DCP has been reduced to 13.2% from 28.3%. We received approximately~~$522 million (US$404 million)~~ ~~in cash proceeds and recorded an accounting gain of $1.1 billion (US$832 million) on the Consolidated Statements of Earnings~~operate as a ~~result of~~common carrier system available to all shippers on a monthly nomination basis. The settlement is subject to regulatory and other approvals and the ~~transaction.~~

~~Acquisition of Tri Global Energy LLC~~

~~On September 27, 2022, we acquired Tri Global Energy LLC (TGE),~~term is seven and a leading US renewable power project developer, for approximately US$270 million in cash and assumed debt. The acquisition of TGE enhances our renewable power platform and further builds on our inventory of North American growth opportunities.

~~Athabasca Indigenous Investments Partnership~~

~~On October 5, 2022, we completed a transaction with Athabasca Indigenous Investments~~ ~~Limited Partnership~~ (Aii), a newly created entity representing 23 First Nation and Métis communities, pursuant to which Aii acquired an 11.6% non-operating interest in seven Regional Oil Sands pipelines in northern Alberta for $1.1 billion.

~~CEO Transition~~

On October 3, 2022, we announced Al Monaco's retirement as President and Chief Executive Officer and from our Board of Directors effective January 1, 2023. Concurrent with this announcement, the Board of Directors appointed Greg Ebel, currently Chair of our Board of Directors, to succeed Mr. Monaco as President and Chief Executive Officer. Mr. Ebel will also continue as a member of the Board of Directors. A new independent Board Chair will be named prior to January 1, 2023. To support Mr. Ebelhalf years through the ~~transition, Mr. Monaco will serve as an advisor to March~~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 will continue to be distance and commodity adjusted, and will 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 will earn 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 will flex 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) in October 2023.

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 Commissioners. Lakehead System tolls will be updated to reflect the new Settlement pending approval by the FERC.

ACQUISITIONS

Tres Palacios Holdings LLC

On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for US$335 million of cash. Tres Palacios is a natural gas storage facility located in the US Gulf Coast and its infrastructure serves Texas gas-fired power generation and liquefied natural gas exports, as well as Mexico pipeline exports. Tres Palacios is comprised of three natural gas storage salt caverns with a total FERC-certificated working gas capacity of approximately 35 billion cubic feet (bcf) and also owns an integrated 62-mile natural gas header pipeline system, with eleven inter- and intrastate natural gas pipeline connections.

Aitken Creek Gas Storage

On May 1, 2023, we announced that Enbridge has entered into a definitive agreement to acquire a 93.8% interest in Aitken Creek Gas Storage Facility and a 100% interest in Aitken Creek North Gas Storage Facility (collectively, Aitken Creek) for $400 million of cash plus payment for derivative contracts and gas inventory, subject to other customary closing adjustments. Aitken Creek is a natural gas storage facility located in British Columbia, Canada with a working gas capacity of approximately 77 bcf. The transaction is expected to close later in 2023, subject to receipt of customary regulatory approvals and closing conditions.

GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS

Texas Eastern Transmission

The Stipulation and Agreement for Texas Eastern Transmission, LPLP’s (Texas Eastern) ~~filed two~~consolidated 2021 rate cases inwas approved by the ~~third quarter of 2021. These two rate proceedings have since been consolidated~~FERC on November 30, 2022, and ~~settlement negotiations began during the first quarter of 2022. An uncontested settlement in principle was reached~~became effective on ~~July 7, 2022.~~January 1, 2023. Texas Eastern ~~filed an uncontested Stipulation~~received FERC approval on April 3, 2023 to implement the settled rates and Agreement on September 8, 2022 to resolve all issues from the rate proceeding. The comment and reply period ended October 11, 2022 and the Stipulation and Agreement is now with the Federal Energy Regulatory Commission for approval.other settlement provisions.

Maritimes & Northeast Pipeline

~~In December 2021, the Canada Energy Regulator (CER) approved interim rates~~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 planned in the third quarter of 2023 with the objective of reaching a toll settlement which would be effective January 1, 2022, which were based on the negotiated 2022 rates in the 2022-2023 settlement agreement and unanimously supported by shippers. The 2022-2023 M&N Canada settlement agreement was approved by the CER in February 2022.

~~British Columbia Pipeline~~

The settlement agreement for our British Columbia Pipeline (BC Pipeline) System expired in December 2021. The CER has approved 2022 interim tolls for BC Pipeline effective January 1, 2022. In August 2022, an agreement in principle was reached with BC Pipeline shippers on a 2022-2026 rate settlement, and we expect2024. It is expected that a settlement agreement towill be ~~executed with shippers and~~ filed ~~with the CER~~ in the fourth quarter of ~~2022.~~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

~~2022~~Incentive Regulation Rate Application

In ~~June 2021,~~October 2022, Enbridge Gas Inc. (Enbridge Gas) filed ~~Phase 1 of the~~its application with the Ontario Energy Board (OEB) for the setting of rates for 2022 (the 2022 Application). The 2022 Application was filed in accordance with the parameters of Enbridge Gas' OEB approved Price Cap Incentive Regulation (IR) rate setting mechanism and represents the fourth year of a five-year term. In October 2021, the OEB approved a Phase 1 Settlement Proposal and Interim Rate Order effective January 1, 2022. In April 2022, the OEB issued its decision on Phase 2 of the 2022 Application filed in October 2021, addressing incremental capital module (ICM) funding requirements, under which $127 million of Enbridge Gas' requested capital funding was approved and incorporated into final rates, effective July 1, 2022.

~~2023 Rate Application~~

In June 2022, Enbridge Gas filed Phase 1 of the application with the OEB for the setting of rates for 2023 (the 2023 Application). The 2023 Application was filed in accordance with the parameters of Enbridge Gas' approved Price Cap IR rate setting mechanism and represents the final year of a five-year term. In November 2022, the OEB approved the Phase 1 Settlement Proposal and Interim Rate Order effective January 1, 2023. In addition, Enbridge Gas does ~~not anticipate 2023 capital investments to require incremental funding during the final year of~~ ~~its~~ ~~current Price Cap IR term, and as such Enbridge Gas will not be making a Phase 2~~ ~~ICM~~ ~~request as part of the 2023 Application.~~

~~Incentive Regulation Rate Application~~

~~In October 2022, Enbridge Gas filed its application~~ to establish a 2024 through 2028 IRIncentive Regulation (IR) rate setting framework. The application and framework seeks approval in two phases to establish 2024 base rates (Phase 1) on a ~~cost of service~~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). ~~An OEB decision is expected on the application in the second half of 2023~~.

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On June 28, 2023, we filed a Phase 1 Partial Settlement Proposal with the OEB for final review and approval. Items resolved in whole or in part include:

•Indigenous engagement;

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

•capital structure cost rates;

•deferral and variance accounts; and

•rate implementation approach for 2024.

A Phase 1 oral hearing began on July 13, 2023 to further examine issues in our application that were not resolved as part of the Partial Settlement Proposal.

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 and June 2022, the OEB approved Enbridge Gas' April 1, 2022 and July 1, 2022 QRAM applications, respectively. Due to the significant increase in natural gas prices, the approvals have also included rate mitigation plans intended to ease bill impacts to ratepayers. Specifically, the approved rate mitigation plans extended the PGVA recovery period from 12 months to 24 months in both applications. As an additional mitigation measure, as part of2023, the April 1, ~~2022~~2023 QRAM ~~a portion of~~application was filed and approved by the ~~PGVA balance was deferred for recovery,~~OEB, which ~~was subsequently~~included an adjustment to the prior mitigation approved ~~for recovery~~ as part of the July 1, 2022 QRAM. The ~~October~~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. The July 1, 2023 QRAM application was filed and approved by the OEB with no adjustments to the prior period rate mitigation plans and it did not include any additional rate mitigation measures.

As at ~~September~~June 30, ~~2022,~~2023, Enbridge Gas' PGVA receivable balance was ~~$693~~$337 million.

FINANCING UPDATE

~~On January 19, 2022,~~In March 2023, we closed a ~~$750 million private placement~~two-tranche US debt offering consisting of ~~non-call~~three-year senior notes, callable at par after one year at our option, and 10-year ~~fixed-to-fixed subordinated~~sustainability-linked senior notes, for an aggregate principal amount of US$3.0 billion, which mature ~~on January 19, 2082. The net proceeds~~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 ~~offering were used~~facility's maturity date was extended to ~~redeem Preference Shares, Series 17 at par on March 1, 2022.~~July 2025, which includes a one-year term out provision from July 2024.

On ~~February 17, 2022,~~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~~three-tranche debt offering ~~of aggregate US$1.5 billion senior notes~~ consisting of ~~US$600 million two-year floating rate~~five-year medium-term notes, ~~US$400 million two-year~~10-year sustainability-linked medium-term notes, and ~~US$500 million three-year notes. Each tranche is payable semi-annually in arrears and matures on February 16, 2024, February 16, 2024 and February 14, 2025, respectively.~~

~~On May 17, 2022, we entered into a three year term loan with a syndicate~~30-year medium-term notes for an aggregate principal amount of ~~Japanese banks for approximately $806 million (¥84.8 billion),~~$1.5 billion, which ~~will~~ mature in May ~~2025~~2028, May 2033 and ~~replaces the approximately $499 million (¥52.5 billion) term loan that matured in~~ May ~~2022. Additionally, on May 24, 2022, we entered into a 364-day term loan for approximately $1.9 billion, which will mature in May 2023.~~2053, respectively.

In July ~~and August 2022, we increased our~~2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit ~~facilities by approximately $641 million.~~facility to July 2025, which includes a one-year term out provision from July 2024.

~~On August 17, 2022, Enbridge Gas closed~~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 ~~$650 million dual-tranche medium-term note offering in~~one-year term out provision from July 2024. We also renewed approximately $7.6 billion of our five-year credit facilities, extending the ~~Canadian debt capital markets, split evenly across a 10-year tranche and a 30-year tranche, payable semi-annually in arrears due August 17, 2032 and August 17, 2052, respectively.~~

~~On September 20, 2022,~~maturity dates to July 2028. Further, we closed a US$1.1 billion dual-tranche hybrid note offering consisting of 60-year non-call 5-year fixed-to-fixed subordinated notes and 60-year non-call 10-year fixed-to-fixed subordinated notes, both of which mature on January 15, 2083.extended our three-year credit facilities, extending the maturity dates to July 2026.

These financing activities, in combination with the financing activities executed in ~~2021,~~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~~June 30, ~~2022,~~2023, after adjusting for the impact of floating-to-fixed interest rate swap hedges, ~~approximately 10%~~less than 5% of our total debt is exposed to floating rates. Refer to Part I. Item I.1. Financial Statements - Note 9.8 - 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,			Three months ended June 30,		Six months ended June 30,
		2022	2021	2022	2021		2023	2022	2023	2022
(millions of Canadian dollars)
(millions of Canadian dollars, except per share amounts)						(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1	Segment earnings/(loss) before interest, income taxes and depreciation and amortization1					Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
Liquids Pipelines	Liquids Pipelines	1,946	1,673	6,093	5,756	Liquids Pipelines	2,451	1,818	4,814	4,147
Gas Transmission and Midstream	Gas Transmission and Midstream	2,251	884	4,384	2,725	Gas Transmission and Midstream	1,042	1,119	2,247	2,133
Gas Distribution and Storage	Gas Distribution and Storage	286	282	1,368	1,374	Gas Distribution and Storage	367	417	1,083	1,082
Renewable Power Generation	Renewable Power Generation	105	91	389	362	Renewable Power Generation	129	122	265	284
Energy Services	Energy Services	(70)	(204)	(348)	(379)	Energy Services	22	(177)	23	(278)
Eliminations and Other	Eliminations and Other	(935)	(121)	(1,284)	191	Eliminations and Other	529	(704)	535	(349)
Earnings before interest, income taxes and depreciation and amortization1	Earnings before interest, income taxes and depreciation and amortization1	3,583	2,605	10,602	10,029	Earnings before interest, income taxes and depreciation and amortization1	4,540	2,595	8,967	7,019
Depreciation and amortization	Depreciation and amortization	(1,076)	(944)	(3,195)	(2,805)	Depreciation and amortization	(1,137)	(1,064)	(2,283)	(2,119)
Interest expense	Interest expense	(806)	(648)	(2,316)	(1,923)	Interest expense	(883)	(791)	(1,788)	(1,510)
Income tax expense	Income tax expense	(318)	(199)	(1,044)	(952)	Income tax expense	(519)	(133)	(1,029)	(726)
Earnings attributable to noncontrolling interests	Earnings attributable to noncontrolling interests	(21)	(34)	(61)	(93)	Earnings attributable to noncontrolling interests	(66)	(12)	(115)	(40)
Preference share dividends	Preference share dividends	(83)	(98)	(330)	(280)	Preference share dividends	(87)	(145)	(171)	(247)
Earnings attributable to common shareholders	Earnings attributable to common shareholders	1,279	682	3,656	3,976	Earnings attributable to common shareholders	1,848	450	3,581	2,377
Earnings per common share attributable to common shareholders	Earnings per common share attributable to common shareholders	0.63	0.34	1.80	1.97	Earnings per common share attributable to common shareholders	0.91	0.22	1.77	1.17
Diluted earnings per common share attributable to common shareholders	Diluted earnings per common share attributable to common shareholders	0.63	0.34	1.80	1.96	Diluted earnings per common share attributable to common shareholders	0.91	0.22	1.77	1.17

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

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EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended ~~September~~June 30, ~~2022,~~2023, compared with the three months ended ~~September~~June 30, ~~2021~~2022

Earnings attributable to common shareholders were positively impacted by ~~$415~~$1,368 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 ~~$1,076~~$550 million ($~~732~~422 million after-tax) ~~on the closing~~in 2023, compared to a net loss of ~~the joint venture merger transaction with P66 realigning our indirect economic interests~~$866 million ($663 million after-tax) in ~~Gray Oak and DCP;~~

•~~a deferred tax benefit of $95 million recognized~~2022, reflecting changes in the ~~quarter as a result~~mark-to-market value of ~~the reduced Pennsylvania state corporate income tax;~~derivative financial instruments used to manage foreign exchange and interest rate risks;

•the absence in 2023 of ~~the $111~~a $100 million ($8377 million after-tax) ~~impairment loss in 2021 to~~restructuring expense associated with our ~~investment in the PennEast Pipeline Company, LLC (PennEast) pipeline project after a decision by project partners to cease development;~~enterprise insurance strategy;

•a net positive adjustment to crude oil and natural gas inventories of ~~$85~~$7 million ($756 million after-tax) ~~due to the release~~in 2023, compared with a net negative adjustment of ~~reserves associated with our enterprise insurance strategy; and~~$62 million ($48 million after-tax) in 2022;

•a non-cash, net unrealized ~~gains~~gain of ~~$58~~$45 million ($4434 million after-tax) in ~~2022,~~2023, compared ~~with unrealized losses~~to a net loss of ~~$88~~$16 million ($6712 million after-tax) in ~~2021,~~2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, ~~as well as manage the~~and exposure to movements in commodity prices;

•the absence in 2023 of an asset impairment loss of $40 million ($31 million after-tax) relating to the MacKay River line within our Alberta Regional Oil Sands System; and

•a net unrealized gain of $9 million ($8 million after-tax) in 2023, compared with a net unrealized loss of $27 million ($23 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; partially offset by

•~~non-cash,~~the absence in 2023 of a net ~~unrealized derivative fair value losses~~positive adjustment of ~~$1,334~~$22 million ($~~1,021~~17 million after-tax) ~~in 2022, compared with unrealized losses~~relating to our share of ~~$436 million ($332 million after-tax) in 2021, reflecting~~ changes in the mark-to-market value of derivative financial instruments ~~used to manage foreign exchange risks.~~of our equity method investees, DCP Midstream, LP (DCP) and Aux Sable Canada LP, Aux Sable Liquid Products LP and Aux Sable Midstream LLC (collectively, Aux Sable).

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 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 ~~$182~~$30 million increase in earnings attributable to common shareholders is primarily explained by:

•higher ~~throughput within~~contributions from the Mainline System and Line 9 in our Liquids Pipelines segment driven by ~~higher~~increased volumes due to increased crude demand and ~~incremental~~the recognition of a lower provision against the interim Mainline IJT, net of a lower Line 3 Replacement (L3R) ~~capacity that came into service October 2021;~~surcharge; and

•~~increased earnings within~~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 ~~implementation of~~Flanagan South Pipeline and the ~~full L3R surcharge when compared~~Enbridge Ingleside Energy Center (EIEC) due to ~~the lower surcharge on the Canadian portion of the project in effect prior to October 2021, as well as from new export assets acquired in October 2021;~~higher demand; partially offset by

•~~increased~~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 Phillips 66 that closed in the third quarter in 2022;

•higher power costs as a result of increased volumes and power prices in our Liquids Pipelines segment;

•lower commodity prices ~~benefiting our investments in~~impacting the DCP and Aux Sable joint ventures in our Gas Transmission and Midstream ~~LLC (Aux Sable), as well as higher contributions from projects placed into service in November 2021;~~segment; and

•~~recognition of revenues attributable to the Texas Eastern rate case resulting from an uncontested Stipulation and Agreement; partially offset by~~

•higher interest expense primarily due to ~~reduced capitalized~~higher interest ~~associated with the US portion of the L3R Project placed into service in the fourth quarter of 2021, as well as~~rates and higher average ~~principal and higher interest rates; and~~

•~~higher depreciation and amortization expense as a result of several projects placed into service in the fourth quarter of 2021, as well as for new export assets acquired in October 2021.~~principal.

4239

~~Nine~~Six months ended ~~September~~June 30, ~~2022,~~2023, compared with the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022

Earnings attributable to common shareholders were ~~negatively~~positively impacted by ~~$566~~$1,153 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized derivative fair value ~~losses~~gain of ~~$1,751~~$1,091 million ($~~1,340~~828 million after-tax) in ~~2022,~~2023, compared with a net unrealized ~~gains~~loss of ~~$85~~$433 million ($65332 million after-tax) in ~~2021,~~2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange ~~risks;~~

•~~a net negative adjustment to crude oil~~ and ~~natural gas inventories in our Energy Services business segment of $67 million ($50 million after-tax);~~interest rate risks;

•the absence in ~~2022~~2023 of ~~a $57~~restructuring expense of $100 million ($4377 million after-tax) ~~property tax settlement received in 2021 related to the resolution of Minnesota property tax appeals for 2012-2018;~~

•~~an impairment of $44 million ($34 million after-tax) for lease assets due to office relocation plans; and~~

•~~an asset impairment loss of $40 million ($30 million after-tax) relating to MacKay River line within~~associated with our ~~Alberta Regional Oil Sands System; partially offset by~~enterprise insurance strategy;

•a non-cash, net unrealized gain of ~~$1,076~~$53 million ($~~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 deferred tax benefit of $95 million recognized in the quarter as a result of the reduced Pennsylvania state corporate income tax;~~

•~~non-cash, unrealized gains of $22 million ($17~~40 million after-tax) in ~~2022,~~2023, compared ~~with unrealized losses~~to a net loss of ~~$102~~$36 million ($7827 million after-tax) in ~~2021,~~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;

•a net positive adjustment to crude oil and natural gas inventories in our Energy Services business segment of $6 million ($5 million after-tax) in 2023, compared with a net negative adjustment of $72 million ($55 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 $22 million ($19 million after-tax) in 2023, compared with a net loss of $27 million ($23 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;

•a non-cash, net ~~negative~~positive equity earnings adjustment of ~~$30~~$8 million ($226 million after-tax) in ~~2022,~~2023, compared to a net negative adjustment of ~~$104~~$34 million ($7926 million after-tax) in ~~2021~~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.~~Sable; and

•the absence in 2023 of an asset impairment loss of $40 million ($31 million after-tax) relating to the MacKay River line within our Alberta Regional Oil Sands System; partially offset by

•a realized loss of $638 million ($479 million after-tax) due to termination of foreign exchange hedges, reflecting changes in the key settlement terms under the Competitive Toll Settlement (CTS).

After taking into consideration the factors above, the remaining ~~$246~~$51 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:

•higher ~~throughput within~~contributions from the Mainline System and Line 9 in our Liquids Pipelines segment driven by ~~higher~~increased volumes due to increased crude demand, ~~and incremental~~net of a lower L3R ~~capacity that came into service October 2021;~~surcharge;

•recognition of revenues in our Gas Transmission and Midstream segment attributable to the ~~full L3R surcharge when~~Texas Eastern rate case settlement;

•higher contributions from our Energy Services segment primarily due to the expiration of transportation commitments and favorable margins realized on facilities; and

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the ~~lower surcharge on the Canadian portion of the project~~same period in ~~effect prior to October 2021, as well as from new export assets acquired in October 2021;~~2022; partially offset by

•higher power costs as a result of increased volumes and power prices in our Liquids Pipeline segment;

•lower commodity prices ~~benefiting our investments in~~impacting the DCP and Aux Sable ~~as well as higher contributions from projects placed into service~~joint ventures in ~~November 2021;~~our Gas Transmission and Midstream segment;

•~~recognition of revenues attributable to the Texas Eastern rate case resulting from an uncontested Stipulation and Agreement; partially offset by~~

•~~the recognition of a provision against the interim Mainline International Joint Tariff (IJT) for barrels shipped in 2022;~~

•higher interest expense primarily due to higher ~~average principal~~interest rates and higher ~~interest rates, as well as reduced capitalized interest associated with the US portion of the L3R Project placed into service in the fourth quarter of 2021;~~average principal; and

•higher depreciation and amortization ~~expense as a result of several projects~~due to assets placed into service in the ~~fourth quarter~~second half of ~~2021, as well as for new export assets acquired in October 2021.~~2022.

BUSINESS SEGMENTS

LIQUIDS PIPELINES

Three months ended
September 30, Nine months ended
September 30,
2022 2021 2022 2021
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization1
1,946 1,673 6,093 5,756

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


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	2,451	1,818	4,814	4,147

Three months ended ~~September~~June 30, ~~2022,~~2023, compared with the three months ended ~~September~~June 30, ~~2021~~2022

EBITDA was ~~negatively~~positively impacted by ~~$98~~$257 million due to certain infrequent or other non-operating factors, primarily explained byby:

•a non-cash, net unrealized ~~losses~~gain of ~~$290~~$17 million in 2023, compared with a net unrealized loss of $196 million in 2022, ~~compared with unrealized losses of $222 million in 2021,~~ reflecting ~~net fair value gains and losses arising from~~ changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange ~~risks.~~risks; and

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

After taking into consideration the factors above, the remaining ~~$371~~$376 million increase is primarily explained by the following significant business factors:

•higher Mainline System ex-Gretna average throughput of 3.0 million barrels per day (mmbpd) in ~~2022~~2023 as compared to ~~2.7~~2.8 mmbpd in ~~2021~~2022, higher Line 9 deliveries to eastern Canada driven by ~~higher~~increased crude demand and ~~incremental~~the recognition of a lower provision against the interim Mainline IJT, net of a lower L3R ~~capacity that came into service October 2021;~~

•~~implementation of the full L3R surcharge when compared to the lower surcharge on the Canadian portion of the project in effect prior to October 2021;~~surcharge;

•higher contributions from the Gulf Coast and Mid-Continent System due primarily to ~~the acquisition~~increased ownership of the ~~Enbridge Ingleside Energy Center (EIEC)~~Gray Oak Pipeline and ~~related assets~~Cactus II Pipeline acquired in the ~~fourth quarter~~second half of ~~2021, as well as~~2022 and higher volumes from ~~our~~the Flanagan South Pipeline ~~(FSP),~~ and ~~increased indirect economic interest in~~ the ~~Gray Oak pipeline during the third quarter of 2022;~~

•~~higher contributions from the Bakken System~~EIEC due to higher ~~volumes;~~demand; and

•the favorable effect of translating US dollar ~~EBITDA~~earnings at a higher average exchange rate in ~~2022~~2023, compared to the same period in ~~2021;~~2022; partially offset by

•~~the recognition of a provision against the interim Mainline IJT for barrels shipped in 2022;~~

•~~lower contributions from the Seaway Crude Pipeline System, as well as from the Cushing and Hardisty storage assets as a result of lower demand; and~~

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

~~Nine~~Six months ended ~~September~~June 30, ~~2022,~~2023, compared with the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022

EBITDA was ~~negatively~~positively impacted by ~~$621~~$154 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized ~~losses~~gain of ~~$364~~$630 million in ~~2022,~~2023, compared with a net unrealized ~~gains~~loss of ~~$84~~$74 million in ~~2021,~~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 risks;

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

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

•a realized loss of $638 million due to termination of foreign exchange hedges, reflecting changes in

the ~~absence in 2022 of a $57 million property tax~~key settlement ~~received in 2021 related to~~terms under the ~~resolution of Minnesota property tax appeals for 2012-2018.~~CTS.

4441

After taking into consideration the factors above, the remaining ~~$958~~$513 million increase is primarily explained by the following significant business factors:

•higher Mainline System ex-Gretna average throughput of 3.1 mmbpd in 2023 as compared to 2.9 mmbpd in 2022, ~~as compared~~and higher Line 9 deliveries to ~~2.7 mmbpd in 2021~~eastern Canada driven by ~~higher~~increased crude demand, ~~and incremental~~net of a lower L3R ~~capacity that came into service October 2021;~~

•~~implementation of the full L3R surcharge when compared to the lower surcharge on the Canadian portion of the project in effect prior to October 2021;~~surcharge;

•higher contributions from the Gulf Coast and Mid-Continent System due primarily to ~~the acquisition~~increased ownership of the ~~EIEC~~Gray Oak Pipeline and ~~related assets~~Cactus II Pipeline acquired in the ~~fourth quarter~~second half of ~~2021, as well as~~2022 and higher volumes from ~~FSP,~~the Flanagan South Pipeline and ~~increased indirect economic interest in~~ the ~~Gray Oak pipeline during the third quarter of 2022;~~

•~~higher contributions from the Bakken System~~EIEC due to higher ~~volumes;~~demand; and

•the favorable effect of translating US dollar ~~EBITDA~~earnings at a higher average exchange rate in ~~2022~~2023, compared to the same period in ~~2021;~~2022; partially offset by

•~~the recognition of a provision against the interim Mainline IJT for barrels shipped in 2022;~~

•~~lower contributions from the Seaway Crude Pipeline System, as well as from the Cushing and Hardisty storage assets as a result of lower demand; 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,			Three months ended June 30,		Six months ended June 30,
		2022	2021	2022	2021		2023	2022	2023	2022
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization1		2,251	884	4,384	2,725
Earnings before interest, income taxes and depreciation and amortization						Earnings before interest, income taxes and depreciation and amortization	1,042	1,119	2,247	2,133

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

Three months ended ~~September~~June 30, ~~2022,~~2023, compared with the three months ended ~~September~~June 30, ~~2021~~2022

EBITDA was ~~positively~~negatively impacted by ~~$1,195~~$26 million due to certain infrequent or other non-operating factors, primarily explained by the ~~following:~~absence in 2023 of a net positive adjustment of $22 million 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 $51 million decrease is primarily explained by the following significant business factors:

•a ~~gain~~reduction in earnings from our investment in DCP as a result of ~~$1,076 million on the closing of~~our decreased interest due to the joint venture merger transaction with ~~P66 realigning~~Phillips 66 that closed during the third quarter in 2022;

•lower commodity prices impacting our ~~indirect economic interests in Gray Oak~~DCP and ~~DCP;~~Aux Sable joint ventures; and

•higher operating and administrative costs; partially offset by

•the ~~absence~~favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the ~~$111~~same period in 2022;

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

•contributions from the Tres Palacios acquisition in the second quarter of 2023.

Six months ended June 30, 2023, compared with the six months ended June 30, 2022

EBITDA was positively impacted by $34 million ~~impairment loss~~due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net positive equity earnings adjustment of $8 million in ~~2021~~2023, compared to a net negative adjustment of $34 million in 2022 relating to our ~~investment~~share of changes in the ~~PennEast pipeline project after a decision by project partners to cease development.~~mark-to-market value of derivative financial instruments of our equity method investees, DCP and Aux Sable.

The remaining ~~$172~~$80 million increase is primarily explained by the following significant business factors:

•~~contributions from the T-South and Spruce Ridge expansion projects after service commenced in November 2021;~~

•~~higher AECO-Chicago basis differential and lower costs benefiting earnings from our investment in Alliance Pipeline (Alliance);~~

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

•the recognition of revenues attributable to the Texas Eastern rate case ~~resulting from an uncontested Stipulation and Agreement;~~

•~~contributions from the Cameron Extension, Middlesex Extension, and the Appalachia to Market projects placed into service in the fourth quarter of 2021; and~~settlement;

•the favorable effect of translating US dollar ~~EBITDA~~earnings at a higher average exchange rate in ~~2022~~2023, compared to the same period in ~~2021;~~2022;

•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~~Phillips 66 that closed during the ~~quarter.~~third quarter in 2022;

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

45•higher operating and administrative costs.

~~Nine~~GAS DISTRIBUTION AND STORAGE


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	367	417	1,083	1,082

Three months ended ~~September~~June 30, ~~2022,~~2023, compared with the ~~nine~~three months ended ~~September~~June 30, ~~2021~~2022

EBITDA was ~~positively~~negatively impacted by ~~$1,287~~$50 million ~~due to certain infrequent or other non-operating factors, primarily explained by the following:~~

•~~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;~~

•~~the absence of the $111 million impairment loss in 2021 to our investment in the PennEast pipeline project after a decision by project partners to cease development; and~~

•a non-cash, net negative equity earnings adjustment of $30 million in 2022, compared to a net negative adjustment of $104 million in 2021 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 $372 million increase is~~ primarily explained by the following significant business factors:

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

•~~higher AECO-Chicago basis differential and lower~~transportation costs ~~benefiting earnings from our investment in Alliance;~~

•~~contributions from the T-South and Spruce Ridge expansion projects after service commenced in November 2021;~~

•of $33 million which represents a partial reversal of previously favorable timing of recognition of ~~revenues attributable to the Texas Eastern rate case resulting from an uncontested Stipulation and Agreement;~~

•~~contributions from the Cameron Extension, Middlesex Extension, and the Appalachia to Market projects placed into service in the fourth quarter of 2021; and~~

•~~the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2022 compared to the same period in 2021; partially offset by~~

•~~higher operating~~these costs; ~~and~~

•~~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 quarter.~~

~~GAS DISTRIBUTION AND STORAGE~~

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

~~Three months ended September 30, 2022, compared with the three months ended September 30, 2021~~

EBITDA remained consistent year over year for the same three-month period due to higher distribution charges at Enbridge Gas, resulting from increases in rates and customer base, that were offset by higher operating and administrative costs related to higher maintenance and integrity spend, as well as timing of expenditures.

~~Nine months ended September 30, 2022, compared with the nine months ended September 30, 2021~~

~~EBITDA was negatively impacted by $6 million primarily explained by:~~

•~~the absence of earnings from Noverco Inc. due to the sale of our minority investment in December 2021;~~ and

•higher operating and administrative costs ~~at Enbridge Gas largely driven by~~primarily due to higher ~~maintenance~~costs for line locates and higher integrity ~~spend, as well as the timing of expenditures;~~spend; partially offset by

•higher distribution charges ~~at Enbridge Gas~~ resulting from increases in rates and customer ~~base, as well as~~ base.

Six months ended June 30, 2023, compared with the six months ended June 30, 2022

EBITDA was positively impacted by $1 million primarily explained by the following significant business factors:

•higher ~~demand~~distribution charges resulting from increases in ~~the contract market;~~rates and customer base; and

•favorable timing of recognition of storage demand and transportation costs of $30 million, which will be reversed over the remainder of 2023; offset by

•weather, when compared with the normal weather forecast embedded in rates, was warmer in 2023 and colder ~~than normal weather~~ in 2022, ~~positively impacted Enbridge Gas 2022~~resulting in a negative EBITDA byimpact of approximately ~~$28~~$67 million ~~while warmer than normal weather in 2021 negatively impacted 2021 EBITDA by approximately $24 million.~~year-over- year; and

•higher operating and administrative costs primarily due to higher costs for line locates and higher integrity spend.

RENEWABLE POWER GENERATION

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


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	129	122	265	284

Three months ended ~~September~~June 30, ~~2022,~~2023, compared with the three months ended ~~September~~June 30, ~~2021~~2022

EBITDA was positively impacted by ~~$14 million primarily due to higher energy pricing at European offshore wind facilities.~~

~~Nine months ended September 30, 2022, compared with the nine months ended September 30, 2021~~

~~EBITDA was positively impacted by $27~~$7 million primarily due to the following significant business factors:

•~~stronger~~contributions from the Saint-Nazaire Offshore Wind Project, which reached full operating capacity in December 2022; partially offset by

•weaker wind resources at ~~Canadian and US onshore~~North American wind facilities; and

•~~higher~~lower energy pricing at European offshore wind facilities.

Six months ended June 30, 2023, compared with the six months ended June 30, 2022

EBITDA was negatively impacted by $19 million primarily due to the following significant business factors:

•weaker wind resources at North American wind facilities; and

•lower energy pricing at European offshore wind facilities; ~~and~~

•~~the absence in 2022 of the adverse effects from the major winter storm in Texas during February 2021;~~ partially offset by

•contributions from the ~~absence~~Saint-Nazaire Offshore Wind Project, which reached full operating capacity in 2022 of a promote fee received in the first quarter of 2021 associated with the closing of the sale of 49% of our interest in three European offshore wind projects to Canada Pension Plan Investment Board.December 2022.

ENERGY SERVICES

Three months ended
September 30, Nine months ended
September 30,
2022 2021 2022 2021
(millions of Canadian dollars)
Loss before interest, income taxes and depreciation and amortization1
(70) (204) (348) (379)

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


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	22	(177)	23	(278)

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~~June 30, ~~2022,~~2023, compared with the three months ended ~~September~~June 30, ~~2021~~2022

EBITDA was positively impacted by ~~$150~~$130 million due to certain non-operating factors, primarily explained byby:

•a non-cash, net unrealized ~~gains~~gain of ~~$58~~$45 million in ~~2022,~~2023, compared with ~~unrealized losses~~a net loss of ~~$88~~$16 million in ~~2021,~~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.~~prices; and

•a net positive adjustment to crude oil and natural gas inventories of $7 million in 2023, compared with a net negative adjustment of $62 million in 2022.

After taking into consideration the ~~factor~~factors above, the remaining ~~$16~~$69 million ~~decrease~~increase is primarily explained ~~by more~~by:

•less pronounced market structure backwardation ~~and significant compression of location differentials in certain markets~~ as compared to the same period of ~~2021.~~2022;

•expiration of transportation commitments; and

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

~~Nine~~Six months ended ~~September~~June 30, ~~2022,~~2023, compared with the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022

EBITDA was positively impacted by ~~$56~~$167 million due to certain non-operating factors, primarily explained by:

•a non-cash, unrealized ~~gains~~gain of ~~$22~~$53 million in 2023, compared with an unrealized loss of $36 million in 2022, ~~compared with unrealized losses of $102 million in 2021,~~ 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; ~~partially offset by~~and

•a net ~~negative~~positive adjustment to crude oil and natural gas inventories of ~~$67 million.~~$6 million in 2023, compared with a net negative adjustment of $72 million in 2022.

After taking into consideration the factors above, the remaining ~~$25~~$134 million ~~decrease~~increase is primarily explained by the ~~following~~same significant business ~~factors:~~factors as discussed in the three months ended June 30, 2023 results.

•~~more pronounced market structure backwardation and significant compression of location differentials in certain markets as compared to the same period of 2021; partially offset by~~

•~~the absence in 2022 of adverse impacts from the major winter storm experienced across the US Midwest during February 2021.~~

ELIMINATIONS AND OTHER

Three months ended
September 30, Nine months ended
September 30,
2022 2021 2022 2021
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization1
(935) (121) (1,284) 191

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


	Three months ended June 30,		Six months ended June 30,
	2023	2022	2023	2022
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	529	(704)	535	(349)

Eliminations and Other includes operating and administrative costs that are not allocated to business segments, and the impact of foreign exchange hedge settlements ~~which are not allocated to business segments.~~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~~June 30, ~~2022,~~2023, compared with the three months ended ~~September~~June 30, ~~2021~~2022

EBITDA was ~~negatively~~positively impacted by ~~$755~~$1,284 million due to certain infrequent or non-operating factors, primarily explained by:

•a non-cash, net unrealized ~~losses~~gain of ~~$1,046~~$485 million in 2023, compared with a net loss of $656 million in 2022, ~~compared with unrealized losses of $214 million in 2021,~~ reflecting ~~the change~~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 $100 million restructuring expense associated with our enterprise insurance strategy; and

•a net ~~positive adjustment~~unrealized gain of ~~$85~~$9 million ~~due to~~in 2023, compared with a net unrealized loss of $27 million in 2022 reflecting changes in the ~~release~~mark-to-market value of ~~reserves associated with~~equity fund investments held by our ~~enterprise~~wholly-owned captive insurance ~~strategy.~~subsidiaries.

After taking into consideration the non-operating factors above, the remaining ~~$59~~$51 million decrease is primarily explained by lower realized foreign exchange gains on hedge settlements in ~~2022, as well as the timing of certain operating and administrative cost recoveries from the business units.~~2023.

~~Nine~~Six months ended ~~September~~June 30, ~~2022,~~2023, compared with the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022

EBITDA was ~~negatively~~positively impacted by ~~$1,446~~$968 million due to certain infrequent or non-operating factors, primarily explained by:

•a non-cash, ~~net~~ unrealized ~~losses~~gain of ~~$1,393~~$403 million in ~~2022,~~2023, compared with an unrealized ~~losses~~loss of ~~$17~~$347 million in ~~2021,~~2022, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;

•the absence in 2023 of $100 million restructuring expense associated with our enterprise insurance strategy;

•a net unrealized gain of $22 million in 2023, compared with a net loss of $27 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 in Houston; and~~

•~~a net negative expense of $15 million associated with our enterprise insurance strategy.~~plans.

After taking into consideration the non-operating factors above, the remaining ~~$29~~$84 million decrease is primarily explained by ~~the timing of certain operating and administrative cost recoveries from the business units, partially offset by higher~~lower realized foreign exchange gains on hedge settlements in ~~2022.~~2023.

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. Gulfstream Phase VI 50 % US$0.1 billion US$0.1 billion Complete In-service
2. Vito Gas & Oil 100 % US$0.3 billion US$0.2 billion Under construction 4Q - 2022
3.
Texas Eastern Venice Extension Project3
100 % US$0.4 billion No significant expenditures to date Pre-construction 2023 - 2024
4. Texas Eastern Modernization 100 % US$0.4 billion No significant expenditures to date Pre-construction 2024 - 2025
5. Appalachia to Market II 100 % US$0.1 billion No significant expenditures to date Pre-construction 2025
6. T-North Expansion 100 % $1.2 billion No significant expenditures to date Pre-construction 2026
7.
Woodfibre LNG4
30 % US$1.5 billion No significant expenditures to date Pre-construction 2027
8. T-South Expansion 100 % $3.6 billion No significant expenditures to date Pre-construction 2028
GAS DISTRIBUTION AND STORAGE
9.
Storage Enhancements5
100 % $0.1 billion $0.1 billion Under construction 4Q - 2022
10. System Enhancement Project 100 % $0.1 billion $0.1 billion Under construction 4Q - 2022
11.
Natural Gas Expansion Program6
100 % $0.1 billion No significant expenditures to date Pre-construction 2022 - 2027
12. Panhandle Regional Expansion 100 % $0.3 billion No significant expenditures to date Pre-construction 2023 - 2024
RENEWABLE POWER GENERATION
13. East-West Tie Line 25 % $0.2 billion $0.2 billion Complete In-service
14.
Saint-Nazaire France Offshore Wind Project7
25.5 % $0.9 billion $0.7 billion Under construction 4Q - 2022
(€0.6 billion) (€0.5 billion)
15.
Fécamp Offshore Wind Project8
17.9 % $0.7 billion $0.3 billion Under construction 2023
(€0.5 billion) (€0.2 billion)
16.
Provence Grand Large Floating Offshore Wind Project8
25 % $0.1 billion $0.1 billion Under construction 2023
(€0.1 billion) (€0.1 billion)
17. Solar Self-Power Projects 100 % US$0.2 billion US$0.1 billion Under construction 2023 - 2024
18
Calvados Offshore Wind Project7
21.7 % $0.9 billion $0.3 billion Under construction 2025
(€0.6 billion) (€0.2 billion)


		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 Extension	100	%	US$391 million	US$93 million	Pre-construction	2023 - 2024
2.	Texas Eastern Modernization	100	%	US$394 million	US$21 million	Pre-construction	2024 - 2025
3.	T-North Expansion3	100	%	$1.2 billion	$14 million	Pre-construction	2026
4.	Rio Bravo Pipeline	100	%	US$1.2 billion4	US$37 million	Pre-construction	2026
5.	Woodfibre LNG5	30	%	US$1.5 billion	US$210 million	Pre-construction	2027
6.	T-South Expansion3	100	%	$3.6 billion	$17 million	Pre-construction	2028


RENEWABLE POWER GENERATION
7.	Fécamp Offshore Wind6	17.9	%	$692 million	$445 million	Under construction	1Q - 2024
				(€471 million)	(€306 million)
8.	Calvados Offshore Wind7	21.7	%	$954 million	$286 million	Under construction	2025
				(€645 million)	(€197 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~~June 30, ~~2022.~~2023.

3~~This includes~~Capital cost estimates will be updated prior to filing the ~~Gator Express Project with an~~regulatory applications.

4Rio 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 by the fourth quarter of ~~$31 million.~~2023.

45Our equity contribution is ~~US $0.9 billion,~~US$893 million, with the remainder offinanced through non-recourse project level debt. Capital cost estimates will be updated prior to 60% engineering milestone, at which point Enbridge's preferred return will be set.

6Our equity contribution is $103 million, with the ~~project~~remainder financed through non-recourse project level debt.

5~~The Storage Enhancements project commenced service on October 4, 2022.~~

6Represents Phase 2 of the Natural Gas Expansion Program and the estimated capital cost is presented net of the maximum funding assistance we expect to receive from the Government of Ontario. The expected in-service dates represent the expected completion dates of the leave to construct requirements.

7Our equity contribution is ~~$0.2 billion for each project,~~$181 million, with the remainder ~~of each project financed through non-recourse project level debt.~~

8~~Our equity contribution is $0.1 billion for each project, with the remainder of each project~~ financed through non-recourse project level debt.

A full description of each of our projects is provided in our annual report on Form 10-K for the year ended December 31, ~~2021.~~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

•~~Texas Eastern Venice Extension Project~~ –~~A reversal and expansion of Texas Eastern’s Line 40 from its existing New Roads compressor station to a new delivery point with~~In July 2023, the proposed Gator Express pipeline just south of Texas Eastern’s Larose compressor station. The project is expected to deliver 1.5 billion cubic feet per day (bcf/d) of natural gas to Venture Global Plaquemines LNG, LLC’sRio Grande LNG export facility, ~~located in Plaquemines Parish, Louisiana and is underpinned~~owned by ~~long-term take or pay contracts.~~

•~~T-North Expansion~~ – An expansion of Westcoast Energy Inc.'s (WEI) BC Pipeline in northern BC that includes pipeline looping, additional compressor units and other ancillary station modifications to support 535 million cubic feet per day (MMcf/d) of additional capacity. The project will be underpinned byNextDecade Corporation (NextDecade), reached a ~~cost-of-service commercial model with a target in-service date of 2026.~~

•~~Woodfibre LNG~~ –~~Construction of liquefaction and floating storage facilities in Squamish, BC, as well as an expansion of the BC Pipeline System. The project is expected to be placed into service in 2027.~~

•~~T-South Expansion~~ – An expansion of WEI's BC Pipeline's T-South section that includes pipeline looping, additional compressor units and other ancillary station modifications to support 300 MMcf/d of additional capacity. The project is expected to be placed in service in 2028 and will be underpinned by a cost-of-service commercial model.

~~GAS DISTRIBUTION AND STORAGE~~

•~~Panhandle Regional Expansion Project~~ – Expansion of the Panhandle Transmission System, which supplies natural gas from the Dawn Hub to customers in Southern Ontario west of Dawn. The project consists of construction on Panhandle Loop and Leamington interconnect, and is expected to receive a full cost-of-service regulated return upon OEB approval with target in-service dates of November 2023 and November 2024.

•~~System Enhancement Project~~ – On May 3, 2022, the OEB issued a Decision and Order denying the leave to construct application for the St. Laurent project. Subsequent to this decision, Enbridge Gas has continued to assess the condition of the line through integrity work, ensuring the ongoing safety and reliability of the line.final investment decision. As a result, the construction on our previously announced Rio Bravo Pipeline project ~~has been excluded from~~will proceed after obtaining necessary regulatory approvals. The first phase of the ~~Growth Projects~~ ~~table.~~

~~RENEWABLE POWER GENERATION~~

•~~Calvados Offshore Wind Project~~ –~~The Calvados Offshore Wind Project has experienced modest schedule pressures. The revised expected in-service date is 2025.~~

•~~Solar Self-Power Projects~~ ~~– The Solar Self-Power Projects have experienced modest schedule pressures. The revised expected in-service date is 2023-2024.~~

~~OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT~~

~~The following projects have been announced by us during the quarter, but have not yet met our criteria~~Rio Bravo Pipeline will transport 2.6 bcf per day of natural gas feedstock to ~~be classified as commercially secured:~~

~~GAS TRANSMISSION AND MIDSTREAM~~

•~~Valley Crossing Expansion Project~~ –~~On January 10, 2022, we executed a precedent agreement with Texas~~NextDecade's Rio Grande LNG ~~Brownsville LLC (Texas LNG) under which, via an expansion of our Valley Crossing Pipeline, we will provide 0.72 bcf/d firm transportation capacity to Texas LNG’s proposed LNG liquefaction and~~ export facility in the Port of Brownsville, ~~Texas for a term of at least 20 years. Expansion of the pipeline will be subject~~Texas. The project is expected to ~~Texas LNG’s export facility reaching a final investment decision.~~

~~We also have a portfolio of additional projects under development that have not yet progressed to the point of securement.~~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 issuance and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures, fund debt retirements, share redemptions, execute share repurchases under our normal course issuer bid (NCIB) and pay common and preference share dividends. We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.

We have signed capital obligation contracts for the purchase of services, pipe and other materials totaling approximately ~~$1.1~~$1.2 billion, which are expected to be paid over the next five years.

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

CAPITAL MARKET ACCESS

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

5247

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~~June 30, ~~2022:~~2023:


		Maturity1	Total Facilities	Draws2	Available		Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Enbridge Inc.	Enbridge Inc.	2023-2027	10,949	9,451	1,498	Enbridge Inc.	2024-2027	8,860	4,341	4,519
Enbridge (U.S.) Inc.	Enbridge (U.S.) Inc.	2024-2027	8,245	3,909	4,336	Enbridge (U.S.) Inc.	2024-2027	8,403	4,260	4,143
Enbridge Pipelines Inc.	Enbridge Pipelines Inc.	2024	2,000	858	1,142	Enbridge Pipelines Inc.	2024	2,000	930	1,070
Enbridge Gas Inc.	Enbridge Gas Inc.	2024	2,000	1,885	115	Enbridge Gas Inc.	2024	2,500	850	1,650
Total committed credit facilities	Total committed credit facilities		23,194	16,103	7,091	Total committed credit facilities		21,763	10,381	11,382

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

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

~~On February 10, 2022, we renewed our three year $1.0 billion sustainability-linked credit facility, extending the maturity date out to July 2025.~~

~~On June 23, 2022, we renewed approximately $5.5 billion of our~~In March 2023, Enbridge Gas increased its 364-day extendible credit ~~facilities~~facility from $2.0 billion to $2.5 billion and in July 2023, the facility's maturity date was extended to July ~~2024,~~2025, which includes a one-year term out provision from July ~~2023.~~2024.

As at ~~September~~June 30, ~~2022,~~2023, our net available liquidity totaled ~~$8.1~~$12.4 billion (December 31, ~~2021~~2022 - ~~$6.5~~$10.0 billion), consisting of available credit facilities of ~~$7.1~~$11.4 billion (December 31, ~~2021~~2022 - ~~$6.2~~$9.1 billion) and ~~was inclusive of~~ unrestricted cash and cash equivalents of $1.0 billion (December 31, ~~2021~~2022 - ~~$286~~$861 million) as reported in the Consolidated Statements of Financial Position.

5348

LONG-TERM DEBT ISSUANCES

During the ~~nine~~six months ended ~~September~~June 30, ~~2022,~~2023, we completed the following long-term debt issuances totaling ~~$1.4~~US$3.0 billion and ~~US$2.6~~$1.5 billion:

Company

Issue Date

Principal Amount

Company

Issue Date

Principal Amount

(millions of Canadian dollars unless otherwise stated)

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

January 2022

5.00%

fixed-to-fixed subordinated notes due January 20821

$750

March 2023

5.70%

sustainability-linked senior notes due March 20331

US$2,300

February 2022

Floating rate senior notes due February 20242

US$600

March 2023

5.97%

senior notes due March 20262

US$700

February 2022

2.15%

senior notes due February 2024

US$400

May 2023

4.90%

medium-term notes due May 2028

$600

February 2022

2.50%

senior notes due February 2025

US$500

May 2023

5.36%

sustainability-linked medium-term notes due May 20333

$400

September 2022

7.38%

fixed-to-fixed subordinated notes due January 20833

US$500

May 2023

5.76%

medium-term notes due May 2053

$500

September 2022

7.63%

fixed-to-fixed subordinated notes due January 20834

US$600

Enbridge Gas Inc.

August 2022

4.15

medium-term notes due August 2032

$325

August 2022

4.55

medium-term notes due August 2052

$325

2We have the option to call the notes at par after one year ~~10, every five years,~~from issuance. Refer to Part 1. Item 1. Financial Statements - Note 8 - Risk Management and Financial Instruments.

LONG-TERM DEBT REPAYMENTS

During the six months ended June 30, 2023, we completed the following long-term debt repayments totaling US$1.2 billion and $0.7 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 Pipelines (Southern Lights) L.L.C.

June 2023

3.98%

senior notes

US$38

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

1~~Notes carry~~The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 6340 basis points.

32~~For the initial five years, the~~The five-year callable notes, ~~carry a fixed interest rate. At year five the interest rate will be set to equal to the Five-Year US Treasury rate plus a margin~~with an original maturity date of 3.71%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.96%. 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 4.71%.

~~LONG-TERM DEBT REPAYMENTS~~

~~During the nine months ended September 30, 2022, we completed the following long-term debt repayments totaling US$1.5 billion and $0.3 billion:~~

1~~Notes carried an interest rate set to equal the three-month London Interbank Offered Rate plus a margin of 50 basis points.~~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 ~~$36~~$60 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~~June 30, ~~2022~~2023 and December 31, ~~2021,~~2022, we had positive and negative working capital ~~position~~positions of ~~$0.7~~$1.0 billion and ~~$3.1 billion. In both periods,~~$2.1 billion, respectively. During the six months ended June 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 ~~the ongoing funding of~~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,				Six months ended June 30,
			2022	2021			2023	2022
(millions of Canadian dollars)	(millions of Canadian dollars)				(millions of Canadian dollars)
Operating activities	Operating activities		7,617	7,366	Operating activities		7,305	5,473
Investing activities	Investing activities		(3,158)	(5,907)	Investing activities		(2,333)	(2,120)
Financing activities	Financing activities		(3,785)	(1,422)	Financing activities		(4,770)	(2,605)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	Effect of translation of foreign denominated cash and cash equivalents and restricted cash		63	(12)	Effect of translation of foreign denominated cash and cash equivalents and restricted cash		(19)	20
Net change in cash and cash equivalents and restricted cash	Net change in cash and cash equivalents and restricted cash		737	25	Net change in cash and cash equivalents and restricted cash		183	768

Significant sources and uses of cash for the ~~nine~~six months ended ~~September~~June 30, ~~2022~~2023 and ~~2021~~2022 are summarized below:

Operating Activities

Typically, the primary factors impacting cash ~~flow from~~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 ~~as well as timing of~~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 ~~under~~in Results of ~~Operations.~~Operations, as well as Distributions from equity investments. Changes in operating and assets and liabilities increased period-over-period primarily due to a larger decline in gas inventory balances in 2023 when compared to the same period in 2022, as well as 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~~Projects. . The timing of project ~~approval,~~approval, construction and in-service dates impacts the timing of cash requirements. ~~Factors impacting the decrease~~Cash used in investing activities is also impacted by acquisitions and changes in contributions to, and distributions from, our equity investments. The increase in cash used in investing activities period-over-period was primarily ~~include:~~

•~~lower capital expenditures~~ due to the ~~US L3R Program that was placed into service in the fourth quarter~~ acquisition of ~~2021; and~~

•~~proceeds from the completion of a joint venture merger transaction for DCP Midstream LLC in August 2022.~~

~~The factors above were~~Tres Palacios on April 3, 2023, partially offset ~~by:~~

•by higher equity distributions in ~~increased contributions made~~2023 mainly related to our ~~equity~~ investment in ~~Bakken Pipeline System due to debt servicing requirements;~~

•~~our acquisition of TGE in September 2022; and~~

•~~increased investments held by our wholly-owned captive insurance subsidiaries.~~NEXUS Gas Transmission, LLC.

5550

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 NCIB. Cash ~~flow from~~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 our 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

•an increase in common share dividend payments due to the increase in our 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 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;~~

•~~lower long-term debt issuances and higher long-term debt repayments in 2022, when compared to the same period in 2021;~~

•~~the repurchase and cancellation of 2,737,965 common shares under our NCIB for approximately $151 million during the period; and~~

•~~common share dividend payments increased period-over-period primarily due to the 3% increase in our common share dividend rate.~~

~~The factors above were partially offset by:~~

•~~net commercial paper and credit facility draws in 2022 when compared to net repayments in the same period in 2021;~~

•~~higher short-term borrowings in 2022 when compared to the same period in 2021; and~~

•~~the absence of the redemption of WEI's preferred shares in the first quarter of 2021.~~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~~June 30, ~~2022,~~2023, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.

2As at ~~September~~June 30, ~~2022,~~2023, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

5651

Enbridge Notes under Guarantees


USD Denominated1			CAD Denominated2
Floating Rate Senior Notes due ~~2023~~2024			~~3.190%~~3.950% Senior Notes due ~~2022~~
~~Floating Rate Senior Notes due~~ 2024			~~3.940% Senior Notes due 2023~~
4.000% Senior Notes due 2023			~~3.940%~~2.440% Senior Notes due ~~2023~~2025
0.550% Senior Notes due 2023			~~3.950%~~3.200% Senior Notes due ~~2024~~2027
3.500% Senior Notes due 2024			~~2.440%~~5.700% Senior Notes due ~~2025~~2027
2.150% Senior Notes due 2024			~~3.200%~~6.100% Senior Notes due ~~2027~~2028
2.500% Senior Notes due 2025			~~6.100%~~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
~~2.500%~~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~~June 30, ~~2022,~~2023, the aggregate outstanding principal amount of the Enbridge US ~~dollar denominated~~dollar-denominated notes was approximately US$~~11.0~~13.5 billion.

2As at ~~September~~June 30, ~~2022,~~2023, the aggregate outstanding principal amount of the Enbridge Canadian ~~dollar denominated~~dollar-denominated notes was approximately ~~$9.0~~$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~~Six months ended ~~September~~June 30,			~~2022~~2023
(millions of Canadian dollars)

Operating loss			~~(124)~~(6)
Earnings			~~333~~2,402
Earnings attributable to common shareholders			32,231

5752

Summarized Combined Statements of Financial Position


		September 30, 2022	December 31, 2021		June 30, 2023	December 31, 2022
(millions of Canadian dollars)	(millions of Canadian dollars)			(millions of Canadian dollars)
Cash and cash equivalents				Cash and cash equivalents	1,076	425
Accounts receivable from affiliates	Accounts receivable from affiliates	2,482	3,442	Accounts receivable from affiliates	3,705	2,486
Short-term loans receivable from affiliates	Short-term loans receivable from affiliates	8,613	4,947	Short-term loans receivable from affiliates	3,500	5,232
Other current assets	Other current assets	433	605	Other current assets	682	969
Long-term loans receivable from affiliates	Long-term loans receivable from affiliates	45,857	51,983	Long-term loans receivable from affiliates	42,378	43,873
Other long-term assets	Other long-term assets	4,609	3,732	Other long-term assets	3,486	4,111
Accounts payable to affiliates	Accounts payable to affiliates	1,339	1,982	Accounts payable to affiliates	2,665	1,375
Short-term loans payable to affiliates	Short-term loans payable to affiliates	3,368	2,891	Short-term loans payable to affiliates	1,524	1,745
Other current liabilities	Other current liabilities	6,097	8,110	Other current liabilities	6,100	8,752
Long-term loans payable to affiliates	Long-term loans payable to affiliates	39,208	41,370	Long-term loans payable to affiliates	36,364	37,626
Other long-term liabilities	Other long-term liabilities	48,842	41,353	Other long-term liabilities	46,178	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

~~LIQUIDS PIPELINES~~

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 United States 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~~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~~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~~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 ~~certain tracts~~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 ~~between~~ October 24 ~~and~~through November 1, 2022. ~~While~~

On May 9, 2023, the Band filed an Emergency Motion for Injunctive Relief asking the Court ~~reserved judgment~~to require Enbridge to purge and shutdown Line 5 on the Bad River Reservation due to significant erosion at the ~~conclusion~~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 ~~trial, the summary judgment decision and subsequent pre-trial decisions provide that~~Band had proven imminence but his final ruling on all issues would be provided soon.

On June 26, 2023, the Court ~~will assess~~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 ~~damages calculated~~on the 12 allotted parcels; (3) Enbridge must continue to pay money on a quarterly basis using ~~a pro-rata share of Enbridge’s profits from~~ 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 ~~pipeline attributable~~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 ~~12 disputed parcels compared~~Relocation to ~~the pipeline as a whole rather than the profits associated with the entire length~~be completed prior to having to cease operations. The Final Judgment was entered on June 29, 2023. Enbridge filed its Notice of ~~the pipeline, as~~Appeal on June 30, 2023 and the Band ~~sought.~~filed its Notice of Cross Appeal on July 27, 2023. The 7th Circuit Court ~~has also stated~~of Appeals 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 ~~any injunction will not result in the immediate closure of the pipeline but also will not allow the pipeline to operate indefinitely.~~schedule, briefing should be complete on or before December 8, 2023.

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, weEnbridge 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 ~~follows~~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 ~~remand motion and on December 28, 2021, we responded to her request to file that motion. On January 5, 2022, the court issued an Order allowing the AG to file a~~ motion to

remand the 2019 ~~case. The AG’s motion and brief were filed~~case, which the US District Court allowed on January ~~14, 2022, and our response was filed~~5, 2022. However, after full briefing, on ~~February 11, 2022. The motion was fully briefed in March 2022. On~~ August 18, 2022, Judge Neff denied the AG’s motion to ~~remand which now remains in the US District Court.~~remand. On August 30, 2022, the AG filed a motion to certify the ~~US District Court’s~~ August 18 Order to pursue an appeal on the jurisdictional issue, which Enbridge opposed. ~~We anticipate~~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). Enbridge responded and on July 21, 2023, the 6th Circuit granted the AG’s Petition. In the meantime, this case will remain on hold in US District Court. It will likely take approximately 12 to 18 months for additional briefing and a ~~decision on the jurisdictional issue in 2022.~~decision.

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

~~CHANGES IN ACCOUNTING POLICIES~~

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk is described in Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our annual report on Form 10-K for the year ended December 31, ~~2021.~~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~~June 30, ~~2022,~~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~~June 30, ~~2022~~2023 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in various legal and regulatory actions and proceedings which arise in the ordinary course of business. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations. Refer to Part I. Item 2. 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.

~~On October 17, 2022, four separate comprehensive enforcement resolutions were announced with~~As part of its ongoing post-construction monitoring activities for L3R, Enbridge reported groundwater flow near Moose Lake in Aitkin County to the ~~Minnesota Pollution Control Agency,~~ Minnesota Department of Natural Resources (DNR)~~, Fond du Lac Band of Lake Superior Chippewa,~~. Enbridge has been working cooperatively with DNR and Minnesota Attorney General’s Office related to alleged violations that occurred during construction of L3R. As part of these agreements, together with the DNR’s previous Administrative Penalty Order, Enbridgeother agencies and will provide ~~the various entities~~ a ~~total of approximately US$11 million, approximately US$7.5 million of which is to provide financial assurances~~corrective action plan for this location as requested and fund multiple environmental and resource enhancement projects. The Minnesota Attorney General has filed a misdemeanor criminal charge for the taking of water without a permit at the Clearbrook aquifer, with this charge against us to be dismissed following one year of compliance with the state water appropriation rules.implement it upon approval. For additional information, please see our ~~2021 Annual Report~~annual report on Form 10-K ~~and our Quarterly Report on Form 10-Q~~ for the ~~quarter~~year ended ~~March~~December 31, 2022.

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, ~~2021,~~2022, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors.

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

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 programs~~1

~~July 2022~~

~~(July 1 - July 31)~~

—

~~N/A~~

—

~~28,324,366~~

~~August 2022~~

~~(August 1 - August 31)~~

—

~~N/A~~

—

~~28,324,366~~

~~September 2022~~

~~(September 1 - September 30)~~

—

~~N/A~~

—

~~28,324,366~~


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
April 2023 (April 1 - April 30)	478,500	CAD$52.24 (TSX)/CAD$52.25 (Other)	478,500	27,459,663
May 2023 (May 1 - May 31)	1,521,300	CAD$49.25 (TSX)/CAD$49.24 (Other)	1,521,300	25,938,363
June 2023 (June 1 - June 30)	504,556	CAD $49.55 (TSX)/ CAD $49.55 (Other)	504,556	25,433,807

1On ~~December 31, 2021,~~January 4, 2023, the Toronto Stock Exchange (TSX) approved our NCIB to purchase, for cancellation, up to ~~31,062,331~~27,938,163 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 ~~billion, subject to certain restrictions on the number of common shares that may be purchased on a single day.~~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 ~~5, 2022,~~6, 2023 and continues until January ~~4, 2023,~~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

~~None.~~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
~~3.1~~						~~Certificate and Articles of Amendment, dated September 15, 2022 (incorporated by reference to Exhibit 3.1 to Enbridge’s Current Report on Form 8-K filed September 20, 2022)~~
~~3.2~~						~~Certificate and Articles of Amendment, dated September 15, 2022 (incorporated by reference to Exhibit 3.2 to Enbridge’s Current Report on Form 8-K filed September 20, 2022)~~
4.1						~~Ninth Supplemental Indenture~~Shareholder Rights Plan Agreement between ~~the Corporation~~Enbridge Inc. and ~~Deutsche Bank~~Computershare Trust Company ~~Americas,~~of Canada dated ~~September 20, 2022~~as of November 9, 1995 and Amended and Restated as of May 3, 2023 (incorporated by reference to Exhibit 4.1 to Enbridge’s Current Report on Form 8-K filed ~~September 20, 2022)~~May 4, 2023).
~~4.2~~						Tenth Supplemental Indenture between the Corporation and Deutsche Bank Trust Company Americas, dated September 20, 2022 (incorporated by reference to Exhibit 4.2 to Enbridge’s Current Report on Form 8-K filed September 20, 2022
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)

6458

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~~August 4, ~~2022~~2023	By:	/s/ ~~Al Monaco~~Gregory L. Ebel
			~~Al Monaco~~Gregory L. Ebel President, ~~and~~ Chief Executive Officer and Director (Principal Executive Officer)

Date:	~~November~~August 4, ~~2022~~2023	By:	/s/ ~~Vern D. Yu~~Patrick R. Murray
			~~Vern D. Yu~~Patrick R. Murray Executive Vice President ~~Corporate Development~~ and Chief Financial Officer (Principal Financial Officer)

6559


	Three months ended September 30,		Nine months ended September 30,
	2022	2021	2022	2021
(millions of Canadian dollars)
Service cost	46	48	136	144
Interest cost1	40	32	122	96
Expected return on plan assets1	(98)	(84)	(294)	(252)
Amortization of actuarial (gain)/loss1	(1)	14	(3)	42
Net periodic benefit (credit)/cost	(13)	10	(39)	30