0000895728us-gaap:EstimateOfFairValueFairValueDisclosureMemberenb:FinancialForwardCommodityContractMemberus-gaap:MarketApproachValuationTechniqueMemberenb:PowerMemberus-gaap:FairValueInputsLevel3Member2022-06-30

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 ~~June 30, 2022~~March 31, 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 ~~2,024,789,365~~2,024,676,423 common shares outstanding as at ~~July 22, 2022.~~April 28, 2023.


	PART I	~~Page~~PAGE
	~~PART I~~
Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3533
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5548
Item 4.	Controls and Procedures	5548

	PART II

Item 1.	Legal Proceedings	5749
Item 1A.	Risk Factors	5749
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5749
Item 3.	Defaults Upon Senior Securities	5749
Item 4.	Mine Safety Disclosures	5849
Item 5.	Other Information	5850
Item 6.	Exhibits	5850
	Signatures	5951

GLOSSARY


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


~~ASU~~			~~Accounting Standards Update~~
~~Aux Sable~~			~~Aux Sable Canada LP, Aux Sable Liquid Products L.P. and Aux Sable Midstream LLC~~


~~CPP Investments~~DAPL			~~Canada Pension Plan Investment Board~~Dakota Access Pipeline

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

EEP			Enbridge Energy Partners, L.P.


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


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

~~Guaranteed Enbridge Notes~~			~~Guaranteed notes of Enbridge~~
~~L3R~~			~~Line 3 Replacement~~
~~LNG~~			~~Liquified natural gas~~











NCIB			Normal course issuer bid
NGL			Natural gas liquids
~~Noverco~~			~~Noverco Inc.~~
OCI			Other comprehensive income/(loss)

~~OEB~~			~~Ontario Energy Board~~
OPEB			Other postretirement benefits








SEP			Spectra Energy Partners, LP









Texas Eastern			Texas Eastern Transmission, LP



~~the Partnerships~~Tres Palacios			~~Spectra Energy Partners, LP (SEP) and Enbridge Energy Partners, L.P. (EEP)~~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”, “$”~~"dollars" or ~~“C$”~~"$" are to Canadian dollars and all references to ~~“US$”~~"US$" are to United States (US) dollars. All amounts are provided on a ~~before tax~~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; 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 ~~COVID-19 pandemic and the duration and impact thereof; 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; 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, operating ~~performance,~~performance; legislative and regulatory parameters; litigation; acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom; ~~our~~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 ~~United States~~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 June 30,		Six months ended June 30,			Three months ended March 31,
		2022	2021	2022	2021			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	8,108	6,334	16,433	12,763	Commodity sales		4,783	8,325
Gas distribution sales	Gas distribution sales	905	737	3,003	2,277	Gas distribution sales		2,279	2,098
Transportation and other services	Transportation and other services	4,202	3,877	8,876	8,045	Transportation and other services		5,013	4,674
Total operating revenues (Note 3)		13,215	10,948	28,312	23,085
Total operating revenues (Note 2)						Total operating revenues (Note 2)		12,075	15,097
Operating expenses	Operating expenses					Operating expenses
Commodity costs	Commodity costs	8,181	6,430	16,472	12,628	Commodity costs		4,636	8,291
Gas distribution costs	Gas distribution costs	456	289	1,912	1,239	Gas distribution costs		1,594	1,456
Operating and administrative	Operating and administrative	1,994	1,484	3,869	3,043	Operating and administrative		2,037	1,875
Depreciation and amortization	Depreciation and amortization	1,064	929	2,119	1,861	Depreciation and amortization		1,146	1,055

Total operating expenses	Total operating expenses	11,695	9,132	24,372	18,771	Total operating expenses		9,413	12,677
Operating income	Operating income	1,520	1,816	3,940	4,314	Operating income		2,662	2,420
Income from equity investments	Income from equity investments	510	352	1,001	747	Income from equity investments		517	491

Other income/(expense)
Net foreign currency gain/(loss)		(581)	159	(212)	311
Other		82	82	171	191
Other income (Note 9)						Other income (Note 9)		102	458
Interest expense	Interest expense	(791)	(618)	(1,510)	(1,275)	Interest expense		(905)	(719)
Earnings before income taxes	Earnings before income taxes	740	1,791	3,390	4,288	Earnings before income taxes		2,376	2,650
Income tax expense (Note 9)		(133)	(270)	(726)	(753)
Income tax expense						Income tax expense		(510)	(593)
Earnings	Earnings	607	1,521	2,664	3,535	Earnings		1,866	2,057
Earnings attributable to noncontrolling interests	Earnings attributable to noncontrolling interests	(12)	(37)	(40)	(59)	Earnings attributable to noncontrolling interests		(49)	(28)
Earnings attributable to controlling interests	Earnings attributable to controlling interests	595	1,484	2,624	3,476	Earnings attributable to controlling interests		1,817	2,029
Preference share dividends	Preference share dividends	(145)	(90)	(247)	(182)	Preference share dividends		(84)	(102)
Earnings attributable to common shareholders	Earnings attributable to common shareholders	450	1,394	2,377	3,294	Earnings attributable to common shareholders		1,733	1,927
Earnings per common share attributable to common shareholders (Note 5)		0.22	0.69	1.17	1.63
Diluted earnings per common share attributable to common shareholders (Note 5)		0.22	0.69	1.17	1.63
Earnings per common share attributable to common shareholders (Note 4)						Earnings per common share attributable to common shareholders (Note 4)		0.86	0.95
Diluted earnings per common share attributable to common shareholders (Note 4)						Diluted earnings per common share attributable to common shareholders (Note 4)		0.85	0.95

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

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


		Three months ended June 30,		Six months ended June 30,			Three months ended March 31,
		2022	2021	2022	2021			2023	2022
(unaudited; millions of Canadian dollars)	(unaudited; millions of Canadian dollars)					(unaudited; millions of Canadian dollars)
Earnings	Earnings	607	1,521	2,664	3,535	Earnings		1,866	2,057
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	Change in unrealized gain/(loss) on cash flow hedges	352	(157)	646	213	Change in unrealized gain/(loss) on cash flow hedges		(45)	294
Change in unrealized gain/(loss) on net investment hedges		(386)	129	(253)	222
Other comprehensive income from equity investees		—	24	—	2
Change in unrealized gain on net investment hedges						Change in unrealized gain on net investment hedges		15	133

Excluded components of fair value hedges	Excluded components of fair value hedges	(4)	(1)	(5)	(2)	Excluded components of fair value hedges		7	(1)
Reclassification to earnings of loss on cash flow hedges	Reclassification to earnings of loss on cash flow hedges	52	61	109	113	Reclassification to earnings of loss on cash flow hedges		7	57
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(3)	6	(5)	11	Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts		(4)	(2)

Foreign currency translation adjustments	Foreign currency translation adjustments	1,881	(835)	1,173	(1,631)	Foreign currency translation adjustments		(59)	(708)
Other comprehensive income/(loss), net of tax		1,892	(773)	1,665	(1,072)
Other comprehensive loss, net of tax						Other comprehensive loss, net of tax		(79)	(227)
Comprehensive income	Comprehensive income	2,499	748	4,329	2,463	Comprehensive income		1,787	1,830
Comprehensive income attributable to noncontrolling interests	Comprehensive income attributable to noncontrolling interests	(58)	(9)	(71)	(6)	Comprehensive income attributable to noncontrolling interests		(64)	(13)
Comprehensive income attributable to controlling interests	Comprehensive income attributable to controlling interests	2,441	739	4,258	2,457	Comprehensive income attributable to controlling interests		1,723	1,817
Preference share dividends	Preference share dividends	(145)	(90)	(247)	(182)	Preference share dividends		(84)	(102)
Comprehensive income attributable to common shareholders	Comprehensive income attributable to common shareholders	2,296	649	4,011	2,275	Comprehensive income attributable to common shareholders		1,639	1,715

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

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY


		Three months ended June 30,		Six months ended June 30,			Three months ended March 31,
		2022	2021	2022	2021			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	7,010	7,747	7,747	7,747	Balance at beginning of period		6,818	7,747
Redemption of preference shares	Redemption of preference shares	(192)	—	(929)	—	Redemption of preference shares		—	(737)
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	7,010
Common shares	Common shares					Common shares
Balance at beginning of period	Balance at beginning of period	64,801	64,772	64,799	64,768	Balance at beginning of period		64,760	64,799
Shares issued on exercise of stock options	Shares issued on exercise of stock options	12	8	48	12	Shares issued on exercise of stock options		2	36
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	(58)	—	(88)	—	Share purchases at stated value		—	(30)
Other	Other	—	—	(4)	—	Other		—	(4)
Balance at end of period	Balance at end of period	64,755	64,780	64,755	64,780	Balance at end of period		64,774	64,801
Additional paid-in capital	Additional paid-in capital					Additional paid-in capital
Balance at beginning of period	Balance at beginning of period	316	324	365	277	Balance at beginning of period		275	365
Stock-based compensation	Stock-based compensation	5	5	18	16	Stock-based compensation		—	13
Options exercised	Options exercised	(11)	(5)	(45)	(8)	Options exercised		(1)	(34)
Change in reciprocal interest		—	—	—	39

Other	Other	(5)	—	(33)	—	Other		—	(28)
Balance at end of period	Balance at end of period	305	324	305	324	Balance at end of period		274	316
Deficit	Deficit					Deficit
Balance at beginning of period	Balance at beginning of period	(9,082)	(8,093)	(10,989)	(9,995)	Balance at beginning of period		(15,486)	(10,989)
Earnings attributable to controlling interests	Earnings attributable to controlling interests	595	1,484	2,624	3,476	Earnings attributable to controlling interests		1,817	2,029
Preference share dividends	Preference share dividends	(145)	(90)	(247)	(182)	Preference share dividends		(84)	(102)
Common share dividends declared		(1,743)	(1,692)	(1,743)	(1,692)
Dividends paid to reciprocal shareholder		—	2	—	5

Share purchases in excess of stated value	Share purchases in excess of stated value	(43)	—	(63)	—	Share purchases in excess of stated value		—	(20)
Other		—	1	—	—

Balance at end of period	Balance at end of period	(10,418)	(8,388)	(10,418)	(8,388)	Balance at end of period		(13,753)	(9,082)
Accumulated other comprehensive income/(loss) (Note 7)
Accumulated other comprehensive income/(loss) (Note 6)						Accumulated other comprehensive income/(loss) (Note 6)
Balance at beginning of period	Balance at beginning of period	(1,308)	(1,675)	(1,096)	(1,401)	Balance at beginning of period		3,520	(1,096)
Other comprehensive income/(loss) attributable to common shareholders, net of tax		1,846	(745)	1,634	(1,019)
Other comprehensive loss attributable to common shareholders, net of tax						Other comprehensive loss attributable to common shareholders, net of tax		(94)	(212)
Balance at end of period	Balance at end of period	538	(2,420)	538	(2,420)	Balance at end of period		3,426	(1,308)
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	61,998	62,026	61,998	62,026	Total Enbridge Inc. shareholders’ equity		61,539	61,737
Noncontrolling interests	Noncontrolling interests					Noncontrolling interests
Balance at beginning of period	Balance at beginning of period	2,536	2,930	2,542	2,996	Balance at beginning of period		3,511	2,542
Earnings attributable to noncontrolling interests	Earnings attributable to noncontrolling interests	12	37	40	59	Earnings attributable to noncontrolling interests		49	28
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)	(3)	(6)	(6)
Change in unrealized gain on cash flow hedges						Change in unrealized gain on cash flow hedges		17	2
Foreign currency translation adjustments	Foreign currency translation adjustments	54	(25)	37	(47)	Foreign currency translation adjustments		(2)	(17)
		46	(28)	31	(53)			15	(15)
Comprehensive income attributable to noncontrolling interests	Comprehensive income attributable to noncontrolling interests	58	9	71	6	Comprehensive income attributable to noncontrolling interests		64	13
Distributions	Distributions	(67)	(77)	(127)	(143)	Distributions		(92)	(60)
Contributions	Contributions	2	6	8	9	Contributions		4	6

Other	Other	10	2	45	2	Other		(1)	35
Balance at end of period	Balance at end of period	2,539	2,870	2,539	2,870	Balance at end of period		3,486	2,536
Total equity	Total equity	64,537	64,896	64,537	64,896	Total equity		65,025	64,273
Dividends paid per common share	Dividends paid per common share	0.860	0.835	1.720	1.670	Dividends paid per common share		0.888	0.860

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

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


		Six months ended June 30,			Three months ended March 31,
		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	2,664	3,535	Earnings	1,866	2,057
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	2,119	1,861	Depreciation and amortization	1,146	1,055
Deferred income tax expense	Deferred income tax expense	469	647	Deferred income tax expense	484	423
Unrealized derivative fair value (gain)/loss, net (Note 8)		415	(448)
Unrealized derivative fair value gain, net (Note 7)				Unrealized derivative fair value gain, net (Note 7)	(520)	(369)
Income from equity investments	Income from equity investments	(1,001)	(747)	Income from equity investments	(517)	(491)
Distributions from equity investments	Distributions from equity investments	878	737	Distributions from equity investments	453	394

Gain on disposition		—	(41)

Other	Other	67	(128)	Other	40	47
Changes in operating assets and liabilities	Changes in operating assets and liabilities	(138)	(363)	Changes in operating assets and liabilities	914	(177)
Net cash provided by operating activities	Net cash provided by operating activities	5,473	5,053	Net cash provided by operating activities	3,866	2,939
Investing activities	Investing activities			Investing activities
Capital expenditures	Capital expenditures	(2,002)	(3,725)	Capital expenditures	(1,129)	(1,048)
Long-term investments and restricted long-term investments	Long-term investments and restricted long-term investments	(388)	(155)	Long-term investments and restricted long-term investments	(413)	(314)
Distributions from equity investments in excess of cumulative earnings	Distributions from equity investments in excess of cumulative earnings	296	246	Distributions from equity investments in excess of cumulative earnings	100	97
Additions to intangible assets	Additions to intangible assets	(91)	(118)	Additions to intangible assets	(66)	(53)
Proceeds from disposition		—	122

Affiliate loans, net	Affiliate loans, net	65	29	Affiliate loans, net	71	—

Net cash used in investing activities	Net cash used in investing activities	(2,120)	(3,601)	Net cash used in investing activities	(1,437)	(1,318)
Financing activities	Financing activities			Financing activities
Net change in short-term borrowings	Net change in short-term borrowings	105	289	Net change in short-term borrowings	(559)	89
Net change in commercial paper and credit facility draws	Net change in commercial paper and credit facility draws	1,031	739	Net change in commercial paper and credit facility draws	(2,921)	(283)
Debenture and term note issues, net of issue costs	Debenture and term note issues, net of issue costs	2,642	3,247	Debenture and term note issues, net of issue costs	4,111	2,643
Debenture and term note repayments	Debenture and term note repayments	(1,333)	(1,888)	Debenture and term note repayments	(968)	(1,155)
Contributions from noncontrolling interests	Contributions from noncontrolling interests	8	9	Contributions from noncontrolling interests	4	6
Distributions to noncontrolling interests	Distributions to noncontrolling interests	(127)	(143)	Distributions to noncontrolling interests	(92)	(60)
Common shares issued	Common shares issued	3	3	Common shares issued	—	2
Common shares repurchased	Common shares repurchased	(151)	—	Common shares repurchased	—	(50)
Preference share dividends	Preference share dividends	(173)	(182)	Preference share dividends	(84)	(91)
Common share dividends	Common share dividends	(3,485)	(3,382)	Common share dividends	(1,798)	(1,742)
Redemption of preferred shares held by subsidiary		—	(115)
Redemption of preference shares	Redemption of preference shares	(1,003)	—	Redemption of preference shares	—	(750)
Affiliate loans, net				Affiliate loans, net	51	—
Other	Other	(122)	(40)	Other	(33)	(92)
Net cash used in financing activities	Net cash used in financing activities	(2,605)	(1,463)	Net cash used in financing activities	(2,289)	(1,483)
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	20	(20)	Effect of translation of foreign denominated cash and cash equivalents and restricted cash	4	(4)
Net change in cash and cash equivalents and restricted cash	Net change in cash and cash equivalents and restricted cash	768	(31)	Net change in cash and cash equivalents and restricted cash	144	134
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	1,088	459	Cash and cash equivalents and restricted cash at end of period	1,051	454

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

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


		June 30, 2022	December 31, 2021		March 31, 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	1,045	286	Cash and cash equivalents	976	861
Restricted cash	Restricted cash	43	34	Restricted cash	75	46
Accounts receivable and other		7,545	6,862
Trade receivables and unbilled revenues				Trade receivables and unbilled revenues	4,755	5,616
Other current assets				Other current assets	2,701	3,255
Accounts receivable from affiliates	Accounts receivable from affiliates	248	107	Accounts receivable from affiliates	100	114
Inventory	Inventory	1,546	1,670	Inventory	1,311	2,255
		10,427	8,959		9,918	12,147
Property, plant and equipment, net	Property, plant and equipment, net	101,290	100,067	Property, plant and equipment, net	104,251	104,460
Long-term investments	Long-term investments	13,687	13,324	Long-term investments	16,320	15,936
Restricted long-term investments	Restricted long-term investments	543	630	Restricted long-term investments	646	593
Deferred amounts and other assets	Deferred amounts and other assets	9,360	8,613	Deferred amounts and other assets	9,148	9,542
Intangible assets, net	Intangible assets, net	3,916	4,008	Intangible assets, net	3,913	4,018
Goodwill	Goodwill	33,277	32,775	Goodwill	32,411	32,440
Deferred income taxes	Deferred income taxes	316	488	Deferred income taxes	463	472
Total assets	Total assets	172,816	168,864	Total assets	177,070	179,608

Liabilities and equity	Liabilities and equity			Liabilities and equity
Current liabilities	Current liabilities			Current liabilities
Short-term borrowings	Short-term borrowings	1,620	1,515	Short-term borrowings	1,437	1,996
Accounts payable and other		8,206	9,767
Trade payables and accrued liabilities				Trade payables and accrued liabilities	4,098	6,172
Other current liabilities				Other current liabilities	3,051	5,220
Accounts payable to affiliates	Accounts payable to affiliates	257	90	Accounts payable to affiliates	47	105
Interest payable	Interest payable	704	693	Interest payable	709	763
Current portion of long-term debt	Current portion of long-term debt	7,188	6,164	Current portion of long-term debt	7,436	6,045
		17,975	18,229		16,778	20,301
Long-term debt	Long-term debt	70,005	67,961	Long-term debt	71,740	72,939
Other long-term liabilities	Other long-term liabilities	7,799	7,617	Other long-term liabilities	9,235	9,189
Deferred income taxes	Deferred income taxes	12,500	11,689	Deferred income taxes	14,292	13,781
		108,279	105,496		112,045	116,210
Contingencies (Note 11)		0	0
Contingencies (Note 10)				Contingencies (Note 10)
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 June 30, 2022 and December 31, 2021)		64,755	64,799
Common shares (2,025 outstanding at March 31, 2023 and December 31, 2022)				Common shares (2,025 outstanding at March 31, 2023 and December 31, 2022)	64,774	64,760
Additional paid-in capital	Additional paid-in capital	305	365	Additional paid-in capital	274	275
Deficit	Deficit	(10,418)	(10,989)	Deficit	(13,753)	(15,486)
Accumulated other comprehensive income/(loss) (Note 7)		538	(1,096)
Accumulated other comprehensive income (Note 6)				Accumulated other comprehensive income (Note 6)	3,426	3,520

Total Enbridge Inc. shareholders' equity		61,998	60,826
Total Enbridge Inc. shareholders’ equity				Total Enbridge Inc. shareholders’ equity	61,539	59,887
Noncontrolling interests	Noncontrolling interests	2,539	2,542	Noncontrolling interests	3,486	3,511
		64,537	63,368		65,025	63,398
Total liabilities and equity	Total liabilities and equity	172,816	168,864	Total liabilities and equity	177,070	179,608

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

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by US GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, ~~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~~

~~ADOPTION OF NEW ACCOUNTING STANDARDS~~

~~Disclosures About Government Assistance~~

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 items and significant terms and conditions. The adoption of this ASU did not have a material impact on our consolidated financial statements.

~~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.

~~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.

~~3. REVENUE~~2. REVENUES

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services


		Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated		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
Three months ended March 31, 2023									Three months ended March 31, 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	2,565	1,200	157	—	—	—	3,922	Transportation revenue	2,942	1,384	276	—	—	—	4,602
Storage and other revenue	Storage and other revenue	64	83	99	—	—	—	246	Storage and other revenue	64	95	99	—	—	—	258
Gas gathering and processing revenue		—	6	—	—	—	—	6

Gas distribution revenue	Gas distribution revenue	—	—	919	—	—	—	919	Gas distribution revenue	—	—	2,287	—	—	—	2,287
Electricity and transmission revenue		—	—	—	81	—	—	81
Electricity revenue									Electricity revenue	—	—	—	66	—	—	66

Total revenue from contracts with customers	Total revenue from contracts with customers	2,629	1,289	1,175	81	—	—	5,174	Total revenue from contracts with customers	3,006	1,479	2,662	66	—	—	7,213
Commodity sales	Commodity sales	—	—	—	—	8,108	—	8,108	Commodity sales	—	—	—	—	4,783	—	4,783
Other revenue1,2	Other revenue1,2	(145)	11	(37)	74	30	—	(67)	Other revenue1,2	30	11	(40)	78	—	—	79
Intersegment revenue	Intersegment revenue	154	1	—	—	—	(155)	—	Intersegment revenue	129	1	3	—	18	(151)	—
Total revenue	Total revenue	2,638	1,301	1,138	155	8,138	(155)	13,215	Total revenue	3,165	1,491	2,625	144	4,801	(151)	12,075

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated
Three months ended
June 30, 2021
(millions of Canadian dollars)
Transportation revenue 2,157 1,046 150 — — — 3,353
Storage and other revenue 37 63 51 — — — 151
Gas gathering and processing revenue — 10 — — — — 10
Gas distribution revenue — — 725 — — — 725
Electricity and transmission revenue — — — 55 — — 55
Total revenue from contracts with customers 2,194 1,119 926 55 — — 4,294
Commodity sales — — — — 6,334 — 6,334
Other revenue1,2
215 9 12 77 1 6 320
Intersegment revenue 138 — 15 — 10 (163) —
Total revenue 2,547 1,128 953 132 6,345 (157) 10,948

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
(millions of Canadian dollars)
Transportation revenue 5,250 2,394 408 — — — 8,052
Storage and other revenue 115 167 146 — — — 428
Gas gathering and processing revenue — 21 — — — — 21
Gas distribution revenue — — 3,017 — — — 3,017
Electricity and transmission revenue — — — 143 — — 143
Total revenue from contracts with customers 5,365 2,582 3,571 143 — — 11,661
Commodity sales — — — — 16,433 — 16,433
Other revenue1,2
33 18 (33) 168 32 — 218
Intersegment revenue 295 1 11 — 10 (317) —
Total revenue 5,693 2,601 3,549 311 16,475 (317) 28,312


		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
Six months ended June 30, 2021
Three months ended March 31, 2022									Three months ended March 31, 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)
Transportation revenue	Transportation revenue	4,486	2,167	366	—	—	—	7,019	Transportation revenue	2,685	1,194	251	—	—	—	4,130
Storage and other revenue	Storage and other revenue	63	137	109	—	—	—	309	Storage and other revenue	51	84	47	—	—	—	182
Gas gathering and processing revenue	Gas gathering and processing revenue	—	17	—	—	—	—	17	Gas gathering and processing revenue	—	15	—	—	—	—	15
Gas distribution revenue	Gas distribution revenue	—	—	2,259	—	—	—	2,259	Gas distribution revenue	—	—	2,098	—	—	—	2,098
Electricity and transmission revenue		—	—	—	81	—	—	81
Electricity revenue									Electricity revenue	—	—	—	62	—	—	62

Total revenue from contracts with customers	Total revenue from contracts with customers	4,549	2,321	2,734	81	—	—	9,685	Total revenue from contracts with customers	2,736	1,293	2,396	62	—	—	6,487
Commodity sales	Commodity sales	—	—	—	—	12,763	—	12,763	Commodity sales	—	—	—	—	8,325	—	8,325
Other revenue1,2	Other revenue1,2	427	21	18	168	1	2	637	Other revenue1,2	178	7	4	94	2	—	285
Intersegment revenue	Intersegment revenue	270	—	24	—	14	(308)	—	Intersegment revenue	141	—	11	—	10	(162)	—
Total revenue	Total revenue	5,246	2,342	2,776	249	12,778	(306)	23,085	Total revenue	3,055	1,300	2,411	156	8,337	(162)	15,097

1Includes ~~mark-to-market gains/(losses) from~~realized and unrealized gains and losses from our hedging program which for the three months ended ~~June 30, 2022 and 2021 of $198~~March 31, 2023 were a net $55 million loss ~~and $131~~(2022 - $94 million ~~gain, respectively. For the six months ended June 30, 2022 and 2021, Other revenue includes a $104 million mark-to-market loss and a $261 million mark-to-market gain, respectively.~~gain).

2 Includes revenues from lease contracts for the three months ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~ of ~~$143~~$144 million and ~~$143 million, respectively, and for the six months ended June 30, 2022 and 2021 of $307 million and $302~~$164 million, respectively.

We disaggregate ~~revenues~~revenue 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.

1312

Contract Balances

Contract Receivables Contract Assets Contract Liabilities
(millions of Canadian dollars)
Balance as at June 30, 2022 2,256 223 2,043
Balance as at December 31, 2021 2,369 213 1,898


	Contract Receivables	Contract Assets	Contract Liabilities
(millions of Canadian dollars)
Balance as at March 31, 2023	3,186	232	2,328
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~~revenue 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 the 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. Revenue recognized during the three ~~and six~~ months ended ~~June 30, 2022~~March 31, 2023 included in contract liabilities at the beginning of the period ~~is $21 million and $82 million, respectively.~~was $36 million. Increases in contract liabilities from cash received, net of amounts recognized as ~~revenues,~~revenue during the three ~~and six~~ months ended ~~June 30, 2022~~March 31, 2023 were ~~$131 million and $228 million, respectively.~~$124 million.

Performance Obligations

There ~~were~~was no material ~~revenues~~revenue recognized in the three ~~and six~~ months ended ~~June 30, 2022~~March 31, 2023 from performance obligations satisfied in previous periods.

~~Revenues~~Revenue to be Recognized from Unfulfilled Performance Obligations

Total ~~revenues~~revenue from performance obligations expected to be fulfilled in future periods ~~are $58.3~~is $60.0 billion, of which ~~$3.7~~$6.0 billion and ~~$6.3~~$6.7 billion are expected to be recognized during the remaining ~~six~~nine 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~~revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.

Variable Consideration

During the three ~~and six~~ months ended ~~June 30, 2022,~~March 31, 2023, revenue for the Canadian Mainline has been recognized in accordance with the terms of the Competitive Tolling Settlement, which expired on June 30, 2021. The tolls in place on June 30, 2021 continue on an interim basis until a new commercial arrangement is implemented and are subject to finalization and adjustment applicable to the interim period, 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 six~~ months ended ~~June 30, 2022~~March 31, 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
June 30, 2022
(millions of Canadian dollars)
Revenues from products transferred at a point in time — — 20 — 20
Revenues from products and services transferred over time1
2,629 1,289 1,155 81 5,154
Total revenue from contracts with customers 2,629 1,289 1,175 81 5,174


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
Three months ended March 31, 2023
(millions of Canadian dollars)
Revenue from products transferred at a point in time	—	—	30	—	30
Revenue from products and services transferred over time1	3,006	1,479	2,632	66	7,183
Total revenue from contracts with customers	3,006	1,479	2,662	66	7,213

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated
Three months ended
June 30, 2021
(millions of Canadian dollars)
Revenues from products transferred at a point in time — — 17 — 17
Revenues from products and services transferred over time1
2,194 1,119 909 55 4,277
Total revenue from contracts with customers 2,194 1,119 926 55 4,294

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

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated
Six months ended
June 30, 2021
(millions of Canadian dollars)
Revenues from products transferred at a point in time — — 34 — 34
Revenues from products and services transferred over time1
4,549 2,321 2,700 81 9,651
Total revenue from contracts with customers 4,549 2,321 2,734 81 9,685


	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Consolidated
Three months ended March 31, 2022
(millions of Canadian dollars)
Revenue from products transferred at a point in time	—	—	16	—	16
Revenue from products and services transferred over time1	2,736	1,293	2,380	62	6,471
Total revenue from contracts with customers	2,736	1,293	2,396	62	6,487

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

3. SEGMENTED INFORMATION


Three months ended March 31, 2023	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Operating revenues	3,165	1,491	2,625	144	4,801	(151)	12,075
Commodity and gas distribution costs	—	—	(1,612)	(4)	(4,782)	168	(6,230)
Operating and administrative	(1,123)	(549)	(309)	(53)	(18)	15	(2,037)


Income/(loss) from equity investments	248	238	—	35	—	(4)	517


Other income/(expense)	73	25	12	14	—	(22)	102
Earnings before interest, income taxes and depreciation and amortization	2,363	1,205	716	136	1	6	4,427
Depreciation and amortization							(1,146)
Interest expense							(905)
Income tax expense							(510)
Earnings							1,866
Capital expenditures1	280	527	264	45	—	25	1,141


Three months ended March 31, 2022	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Operating revenues	3,055	1,300	2,411	156	8,337	(162)	15,097
Commodity and gas distribution costs	(11)	—	(1,468)	(4)	(8,427)	163	(9,747)
Operating and administrative	(947)	(530)	(299)	(48)	(14)	(37)	(1,875)


Income from equity investments	215	221	—	55	—	—	491

Other income	17	23	21	3	3	391	458
Earnings/(loss) before interest, income taxes and depreciation and amortization	2,329	1,014	665	162	(101)	355	4,424
Depreciation and amortization							(1,055)
Interest expense							(719)
Income tax expense							(593)
Earnings							2,057
Capital expenditures1	545	229	266	6	—	12	1,058

1Includes allowance for equity funds used during construction.

4. ~~SEGMENTED INFORMATION~~

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated
Three months ended
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

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated
Three months ended
June 30, 2021
(millions of Canadian dollars)
Operating revenues 2,547 1,128 953 132 6,345 (157) 10,948
Commodity and gas distribution costs (7) — (299) — (6,567) 154 (6,719)
Operating and administrative (673) (424) (242) (37) (9) (99) (1,484)
Income from equity investments 180 132 27 13 — — 352
Other income/(expense) (3) 32 19 7 (8) 194 241
Earnings/(loss) before interest, income taxes, and depreciation and amortization 2,044 868 458 115 (239) 92 3,338
Depreciation and amortization (929)
Interest expense (618)
Income tax expense (270)
Earnings 1,521
Capital expenditures1
567 547 300 2 — 9 1,425

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
(millions of Canadian dollars)
Operating revenues 5,693 2,601 3,549 311 16,475 (317) 28,312
Commodity and gas distribution costs (27) — (1,931) (8) (16,732) 314 (18,384)
Operating and administrative (1,923) (1,075) (580) (101) (25) (165) (3,869)
Income/(loss) from equity investments 368 556 1 78 — (2) 1,001
Other income/(expense) 36 51 43 4 4 (179) (41)
Earnings/(loss) before interest, income taxes, and depreciation and amortization 4,147 2,133 1,082 284 (278) (349) 7,019
Depreciation and amortization (2,119)
Interest expense (1,510)
Income tax expense (726)
Earnings 2,664
Capital expenditures1
818 562 600 17 — 24 2,021

Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated
Six months ended
June 30, 2021
(millions of Canadian dollars)
Operating revenues 5,246 2,342 2,776 249 12,778 (306) 23,085
Commodity and gas distribution costs (10) — (1,257) — (12,920) 320 (13,867)
Operating and administrative (1,492) (858) (514) (80) (23) (76) (3,043)
Income from equity investments 334 314 49 50 — — 747
Other income/(expense) 5 43 38 52 (10) 374 502
Earnings/(loss) before interest, income taxes, and depreciation and amortization 4,083 1,841 1,092 271 (175) 312 7,424
Depreciation and amortization (1,861)
Interest expense (1,275)
Income tax expense (753)
Earnings 3,535
Capital expenditures1
1,923 1,029 519 7 — 21 3,499

~~1 Includes allowance for equity funds used during construction.~~

5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

BASIC

Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. On December 30, 2021, we closed the sale of our minority ownership in Noverco Inc. (Noverco). For the three and six months ended June 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 and 3 million, respectively, 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 June 30,		Six months ended June 30,			Three months ended March 31,
		2022	2021	2022	2021			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	2,026	2,024	2,026	2,023	Weighted average shares outstanding		2,025	2,026
Effect of dilutive options and RSUs	Effect of dilutive options and RSUs	4	2	4	1	Effect of dilutive options and RSUs		3	3
Diluted weighted average shares outstanding	Diluted weighted average shares outstanding	2,030	2,026	2,030	2,024	Diluted weighted average shares outstanding		2,028	2,029

For the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021, 3.2~~16.7 million and ~~20.5~~12.9 million, respectively, of anti-dilutive stock options with a weighted average exercise price of ~~$59.29~~$55.62 and ~~$50.66,~~$56.09, respectively, were excluded from the diluted earnings per common share calculation.

For the six months ended June 30, 2022 and 2021, 8.0 million and 24.0 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $56.72 and $51.10, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE

On ~~July 26, 2022,~~May 2, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on ~~September~~June 1, ~~2022~~2023 to shareholders of record on ~~August~~May 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 D2			$~~0.27875~~0.33825
Preference Shares, Series F			$0.29306
Preference Shares, Series H			$0.27350
Preference Shares, Series L			US$~~0.30993~~0.36612
Preference Shares, Series N			$0.31788
Preference Shares, Series P			$0.27369
Preference Shares, Series R			$0.25456
Preference Shares, Series 1			US$0.37182
Preference Shares, Series 3			$0.23356
Preference Shares, Series 5			US$0.33596
Preference Shares, Series 7			$0.27806
Preference Shares, Series 9			$0.25606
Preference Shares, Series 11			$0.24613
Preference Shares, Series 13			$0.19019
Preference Shares, Series 15			$0.18644

Preference Shares, Series 193			$~~0.30625~~0.38825

1The quarterly dividend per common share was increased 3%3.2% to ~~$0.86~~$0.8875 from ~~$0.835,~~$0.86, effective March 1, ~~2022.~~2023.

2The quarterly dividend per share paid on Preference Shares, Series BD was increased to ~~$0.32513~~$0.33825 from ~~$0.21340~~$0.27875 on ~~June~~March 1, ~~2022~~2023 due to reset of the annual dividend on ~~June~~March 1, ~~2022. On June 1, 2022, all outstanding~~2023.

3The quarterly dividend per share paid on Preference Shares, Series ~~C were converted~~19 was increased to ~~Preference Shares, Series B.~~$0.38825 from $0.30625 on March 1, 2023 due to reset of the annual dividend on March 1, 2023.

~~PREFERENCE SHARE REDEMPTIONS~~

On March 1, 2022, we redeemed our $750 million outstanding Cumulative Redeemable Minimum Rate Reset Preference Shares, Series 17. On June 1, 2022, we also redeemed our US$200 million outstanding Cumulative Redeemable Preference Shares, Series J. Dividends are cumulative, payable quarterly and are included in Preference share dividends in the Consolidated Statements of Earnings.

6.5. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at ~~June 30, 2022:~~March 31, 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.	2023-2026	10,818	9,153	1,665	Enbridge Inc.	2023-2027	9,623	7,053	2,570
Enbridge (U.S.) Inc.	Enbridge (U.S.) Inc.	2023-2026	7,095	4,493	2,602	Enbridge (U.S.) Inc.	2024-2027	8,594	1,702	6,892
Enbridge Pipelines Inc.	Enbridge Pipelines Inc.	2024	2,000	797	1,203	Enbridge Pipelines Inc.	2024	2,000	876	1,124
Enbridge Gas Inc.	Enbridge Gas Inc.	2023	2,000	1,620	380	Enbridge Gas Inc.	2024	2,500	1,440	1,060
Total committed credit facilities	Total committed credit facilities		21,913	16,063	5,850	Total committed credit facilities		22,717	11,071	11,646

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 ~~July 2024, which includes a one-year term out provision from July 2023.~~

On July 15 and 22, 2022, we renewed $3.0 billion of our five year credit facilities, extending the maturity date out to July 2027. We also extended approximately $4.8 billion of our 364-day extendible credit facilities to July 2024, which includes a one-year term out provision, from July 2023. As part of the renewal, we also increased our credit facilities by approximately $481 million.$2.5 billion.

In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which ~~$791~~$720 million was unutilized as at ~~June 30, 2022.~~March 31, 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 2023 to 2027.

As at ~~June 30, 2022~~March 31, 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 ~~$12.3~~$9.0 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 ~~six~~three months ended ~~June 30, 2022,~~March 31, 2023, we completed the following long-term debt issuances totaling ~~$750 million and~~ US$~~1.5~~3.0 billion:

Company Issue Date Principal Amount
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
January 2022 5.00% hybrid fixed-to-fixed subordinated notes due January 2082 $750
February 2022
Floating rate senior notes due February 20241
US$600
February 2022 2.15% senior notes due February 2024 US$400
February 2022 2.50% senior notes due February 2025 US$500

Company

Issue Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

March 2023

5.70%

sustainability-linked senior notes due March 20331

US$2,300

March 2023

5.97%

senior notes due March 20262

US$700

1~~Notes carry~~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 target is not met, on September 8, 2031, the interest rate will be set to equal 5.70% plus a margin of 50 basis points.

2We have the option to call the notes at par after one year from issuance. Refer to Note 7 - Risk Management and Financial Instruments.

LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2023, we completed the following long-term debt repayments totaling US$513 million and $275 million:

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

Tri Global Energy, LLC

January 2023

10.00

senior notes

US$4

January 2023

14.00

senior notes

US$9

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

~~LONG-TERM DEBT REPAYMENTS~~

~~During~~On April 15, 2023 call date, we redeemed at par all of the ~~six months ended June 30, 2022, we completed the following long-term debt repayments totaling~~outstanding US$~~784~~600 million ~~and $334 million:~~

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
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~~five-year callable, 6.38% fixed-to-floating rate subordinated notes that carried an ~~interest rate set to equal the three-month London Interbank Offered Rate plus a margin~~original maturity date of ~~50 basis points.~~April 2078.

SUBORDINATED TERM NOTES

As at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of ~~$8.6 billion and $7.7 billion, respectively.~~$10.3 billion.

FAIR VALUE ADJUSTMENT

As at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, the net fair value adjustments to total debt assumed in a historical acquisition were ~~$635~~$588 million and ~~$667~~$608 million, respectively.

During the three ~~and six~~ months ended ~~June 30,~~March 31, 2023 and 2022, amortization of the fair value adjustment recorded as a reduction to Interest expense in the Consolidated Statements of Earnings was $11 ~~million (June 30, 2021 - $13 million) and $22 million (June 30, 2021 - $25 million), respectively.~~million.

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we are to default on payment or violate certain covenants. As at ~~June 30, 2022,~~March 31, 2023, we ~~are~~were in compliance with all covenant provisions.

2118

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

Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to our common shareholders for the ~~six~~three months ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~ 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		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, 2022		(897)	—	(166)	56	(5)	(84)	(1,096)
Balance as at January 1, 2023									Balance as at January 1, 2023	121	(35)	(1,137)	4,348	5	218	3,520
Other comprehensive income/(loss) retained in AOCI	Other comprehensive income/(loss) retained in AOCI	854	(5)	(253)	1,136	—	—	1,732	Other comprehensive income/(loss) retained in AOCI	(90)	7	15	(57)	—	—	(125)
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	142	—	—	—	—	—	142	Interest rate contracts1	8	—	—	—	—	—	8

Foreign exchange contracts2		(4)	—	—	—	—	—	(4)
Other contracts3		2	—	—	—	—	—	2
Amortization of pension and OPEB actuarial gain4		—	—	—	—	—	(6)	(6)

Other contracts2									Other contracts2	1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial gain3									Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(5)	(5)

		994	(5)	(253)	1,136	—	(6)	1,866		(81)	7	15	(57)	—	(5)	(121)
Tax impact	Tax impact								Tax impact
Income tax on amounts retained in AOCI	Income tax on amounts retained in AOCI	(202)	—	—	—	—	—	(202)	Income tax on amounts retained in AOCI	28	—	—	—	—	—	28
Income tax on amounts reclassified to earnings	Income tax on amounts reclassified to earnings	(31)	—	—	—	—	1	(30)	Income tax on amounts reclassified to earnings	(2)	—	—	—	—	1	(1)
		(233)	—	—	—	—	1	(232)		26	—	—	—	—	1	27

Balance as at June 30, 2022		(136)	(5)	(419)	1,192	(5)	(89)	538
Balance as at March 31, 2023									Balance as at March 31, 2023	66	(28)	(1,122)	4,291	5	214	3,426


		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	294	(2)	251	(1,584)	1	—	(1,040)	Other comprehensive income/(loss) retained in AOCI	384	(1)	133	(691)	—	—	(175)
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	142	—	—	—	—	—	142	Interest rate contracts1	76	—	—	—	—	—	76
Foreign exchange contracts4									Foreign exchange contracts4	(4)	—	—	—	—	—	(4)
Other contracts2									Other contracts2	2	—	—	—	—	—	2

Foreign exchange contracts2		3	—	—	—	—	—	3
Other contracts3		1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial loss4		—	—	—	—	—	14	14
Other		17	—	—	(20)	3	—	—
Amortization of pension and OPEB actuarial gain3									Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(3)	(3)

		457	(2)	251	(1,604)	4	14	(880)		458	(1)	133	(691)	—	(3)	(104)
Tax impact	Tax impact								Tax impact
Income tax on amounts retained in AOCI	Income tax on amounts retained in AOCI	(75)	—	(29)	—	1	—	(103)	Income tax on amounts retained in AOCI	(92)	—	—	—	—	—	(92)
Income tax on amounts reclassified to earnings	Income tax on amounts reclassified to earnings	(33)	—	—	—	—	(3)	(36)	Income tax on amounts reclassified to earnings	(17)	—	—	—	—	1	(16)
		(108)	—	(29)	—	1	(3)	(139)		(109)	—	—	—	—	1	(108)

Balance as at June 30, 2021		(977)	3	7	(1,036)	71	(488)	(2,420)
Balance as at March 31, 2022									Balance as at March 31, 2022	(548)	(1)	(33)	(635)	(5)	(86)	(1,308)

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

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

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

4 3These components are included in the computation of net periodic benefit ~~costs~~credit and are reported within Other ~~income/(expense)~~income in the Consolidated Statements of Earnings.

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

2219

8.7. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

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

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

Foreign Exchange Risk

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

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

The foreign exchange risks inherent within the Competitive Toll Settlement framework are not expected to be 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 with~~swaps. These hedges have an average ~~swap~~fixed rate of ~~1.9%~~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 includes 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 June 30, 2022, we do not have any~~6.0%. This instrument is our only pay floating-receive fixed interest rate ~~swaps outstanding.~~swap outstanding as at March 31, 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 ~~select forecast~~forecasted term debt issuances via the execution of floating-to-fixed interest rate swaps with an average swap rate of ~~2.2%~~2.5%.

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 1one 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.

June 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 — — 140 140 (41) 99
Interest rate contracts 341 — 1 342 (21) 321
Commodity contracts — — 358 358 (254) 104
Other contracts 2 — 6 8 — 8
343 — 505 848
1
(316) 532
Deferred amounts and other assets
Foreign exchange contracts — 20 183 203 (123) 80
Interest rate contracts 566 — — 566 — 566
Commodity contracts — — 60 60 (22) 38
Other contracts 2 — 2 4 — 4
568 20 245 833 (145) 688
Accounts payable and other
Foreign exchange contracts — (31) (221) (252) 41 (211)
Interest rate contracts (10) — (41) (51) 21 (30)
Commodity contracts (23) — (415) (438) 254 (184)
(33) (31) (677) (741)
1
316 (425)
Other long-term liabilities
Foreign exchange contracts — (8) (574) (582) 123 (459)
Interest rate contracts (3) — — (3) — (3)
Commodity contracts (19) — (119) (138) 22 (116)
(22) (8) (693) (723) 145 (578)
Total net derivative assets/(liabilities)
Foreign exchange contracts — (19) (472) (491) — (491)
Interest rate contracts 894 — (40) 854 — 854
Commodity contracts (42) — (116) (158) — (158)
Other contracts 4 — 8 12 — 12
856 (19) (620) 217 — 217

1 As at June 30, 2022, $84 million and $128 million were reported within Accounts receivable from affiliates and Accounts payable to affiliates, respectively, in the Consolidated Statements of Financial Position.

2421


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
March 31, 2023								March 31, 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	—	68	54	122	(13)	109
Interest rate contracts	Interest rate contracts	64	—	—	64	—	64	Interest rate contracts	194	—	21	215	(11)	204
Commodity contracts	Commodity contracts	—	—	204	204	(129)	75	Commodity contracts	—	—	193	193	(118)	75
Other contracts	Other contracts	—	—	2	2	—	2	Other contracts	—	—	2	2	—	2
		64	—	465	529	(170)	359		194	68	270	532	(142)	390
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	—	83	131	214	(108)	106
Interest rate contracts	Interest rate contracts	88	—	—	88	(1)	87	Interest rate contracts	154	—	44	198	(43)	155
Commodity contracts	Commodity contracts	—	—	29	29	(13)	16	Commodity contracts	—	—	67	67	(30)	37
Other contracts		—	—	3	3	—	3
		88	—	272	360	(75)	285
Accounts payable and other
									154	83	242	479	(181)	298
Other current liabilities								Other current liabilities
Foreign exchange contracts	Foreign exchange contracts	(15)	(112)	(176)	(303)	41	(262)	Foreign exchange contracts	—	(42)	(89)	(131)	13	(118)
Interest rate contracts	Interest rate contracts	(150)	—	—	(150)	—	(150)	Interest rate contracts	(19)	—	(1)	(20)	11	(9)
Commodity contracts	Commodity contracts	(14)	—	(250)	(264)	129	(135)	Commodity contracts	(30)	—	(218)	(248)	118	(130)

		(179)	(112)	(426)	(717)	170	(547)		(49)	(42)	(308)	(399)	142	(257)
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	—	—	(980)	(980)	108	(872)
Interest rate contracts	Interest rate contracts	(1)	—	(23)	(24)	1	(23)	Interest rate contracts	(4)	—	(45)	(49)	43	(6)
Commodity contracts	Commodity contracts	(17)	—	(67)	(84)	13	(71)	Commodity contracts	(21)	—	(123)	(144)	30	(114)

		(18)	—	(513)	(531)	75	(456)		(25)	—	(1,148)	(1,173)	181	(992)
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	—	109	(884)	(775)	—	(775)
Interest rate contracts	Interest rate contracts	1	—	(23)	(22)	—	(22)	Interest rate contracts	325	—	19	344	—	344
Commodity contracts	Commodity contracts	(31)	—	(84)	(115)	—	(115)	Commodity contracts	(51)	—	(81)	(132)	—	(132)
Other contracts	Other contracts	—	—	5	5	—	5	Other contracts	—	—	2	2	—	2
		(45)	(112)	(202)	(359)	—	(359)		274	109	(944)	(561)	—	(561)


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:


March 31, 2023	2023	2024	2025	2026	2027	Thereafter	Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)	832	1,000	500	—	—	—	2,332
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)	4,566	4,708	4,763	4,157	2,969	1,728	22,891
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	21	30	30	28	32	—	141

Foreign exchange contracts - Euro forwards - sell (millions of Euro)	69	91	86	85	81	262	674
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)	7,821	1,929	80	26	25	39	9,920
Interest rate contracts - short-term debt receive fixed rate (millions of Canadian dollars)	711	947	947	179	—	—	2,784
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	4,153	1,494	588	—	—	—	6,235
Equity contracts (millions of Canadian dollars)	—	32	12	—	—	—	44
Commodity contracts - natural gas (billions of cubic feet)	34	25	23	8	3	—	93
Commodity contracts - crude oil (millions of barrels)	11	—	—	—	—	—	11

Commodity contracts - power (megawatt per hour) (MW/H)	19	(31)	(46)	—	—	—	(17)	1

June 30, 2022 2022 2023 2024 2025 2026 Thereafter Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)
762 — 1,000 500 — — 2,262
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)
4,900 6,384 5,134 3,962 3,362 1,082 24,824
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)
14 29 30 30 28 32 163
Foreign exchange contracts - Euro forwards - sell (millions of Euro)
68 92 91 86 85 343 765
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)
5,242 1,346 132 30 26 64 6,840
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)
3,052 2,626 1,718 573 — — 7,969
Equity contracts (millions of Canadian dollars)
— 36 30 11 — — 77
Commodity contracts - natural gas (billions of cubic feet)1
120 47 17 11 — — 195
Commodity contracts - crude oil (millions of barrels)1
10 — — — — — 10
Commodity contracts - power (megawatt per hour) (MW/H)
(24) (43) (43) (43) — — (40) 2

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

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

2523

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 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 in the Consolidated Statements of Earnings. Any excluded components are included in the Consolidated Statements of Comprehensive Income.


		Three months ended June 30,		Six months ended June 30,			Three months ended March 31,
		2022	2021	2022	2021			2023	2022
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	Unrealized gain/(loss) on derivative	23	(32)	99	(35)	Unrealized gain/(loss) on derivative		(11)	76
Unrealized gain/(loss) on hedged item	Unrealized gain/(loss) on hedged item	(2)	32	(89)	28	Unrealized gain/(loss) on hedged item		11	(87)
Realized loss on derivative	Realized loss on derivative	(21)	—	(96)	(39)	Realized loss on derivative		(11)	(75)
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 March 31,
		2023	2022
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts		—	2
Interest rate contracts		(105)	377
Commodity contracts		34	4
Other contracts		(2)	3
Fair value hedges
Foreign exchange contracts		7	(1)


		(66)	385
Amount of loss reclassified from AOCI to earnings
Foreign exchange contracts1		—	13
Interest rate contracts2		8	76

Other contracts3		1	2
		9	91

Three months ended
June 30, Six months ended
June 30,
2022 2021 2022 2021
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts — (5) 2 (25)
Interest rate contracts 480 (203) 857 294
Commodity contracts (15) 4 (11) (4)
Other contracts (3) 1 — 4
Fair value hedges
Foreign exchange contracts (4) (1) (5) (2)
458 (204) 843 267
Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts1
— 2 13 3
Interest rate contracts2
66 79 142 142
Commodity contracts — (1) — —
Other contracts3
— 1 2 1
66 81 157 146

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

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

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

We estimate that a gain of ~~$68~~$20 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 4233 months as at ~~June 30, 2022.~~March 31, 2023.

2624

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 June 30,		Six months ended June 30,			Three months ended March 31,
		2022	2021	2022	2021			2023	2022
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Foreign exchange contracts1	Foreign exchange contracts1	(806)	218	(373)	454	Foreign exchange contracts1		556	433
Interest rate contracts2	Interest rate contracts2	(16)	—	(16)	2	Interest rate contracts2		10	—
Commodity contracts3	Commodity contracts3	38	(90)	(30)	(18)	Commodity contracts3		(39)	(68)
Other contracts4	Other contracts4	—	5	4	10	Other contracts4		(7)	4
Total unrealized derivative fair value gain/(loss), net	Total unrealized derivative fair value gain/(loss), net	(784)	133	(415)	448	Total unrealized derivative fair value gain/(loss), net		520	369

1For the respective ~~six~~three months ended periods, reported within Transportation and other services revenues ~~(2022~~(2023 - ~~$65~~$645 million ~~loss; 2021~~gain; 2022 - ~~$292~~$134 million gain) and ~~Net foreign currency gain/(loss) (2022~~Other income (2023 - ~~$308~~$89 million loss; ~~2021~~2022 - ~~$162~~$299 million gain) in the Consolidated Statements of Earnings.

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

3For the respective ~~six~~three months ended periods, reported within Transportation and other services revenues ~~(2022~~(2023 - ~~$25~~$6 million gain; ~~2021~~2022 - $3$16 million loss), Commodity sales ~~(2022~~(2023 - ~~$109~~$69 million gain; ~~2021~~2022 - ~~$144~~$16 million ~~gain)~~loss), Commodity costs ~~(2022~~(2023 - ~~$167~~$75 million loss; ~~2021~~2022 - ~~$166~~$37 million loss) and Operating and administrative expense ~~(2022~~(2023 - $3$39 million ~~gain; 2021~~loss; 2022 - $7$1 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 ~~June 30, 2022.~~March 31, 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.

2725

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


		June 30, 2022	December 31, 2021		March 31, 2023	December 31, 2022
(millions of Canadian dollars)	(millions of Canadian dollars)			(millions of Canadian dollars)
Canadian financial institutions	Canadian financial institutions	638	424	Canadian financial institutions	471	644
US financial institutions	US financial institutions	254	130	US financial institutions	115	277
European financial institutions	European financial institutions	350	181	European financial institutions	178	334
Asian financial institutions	Asian financial institutions	118	30	Asian financial institutions	97	224
Other1	Other1	233	122	Other1	88	105
		1,593	887		949	1,584

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

As at ~~June 30, 2022,~~March 31, 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 ~~June 30, 2022~~March 31, 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).

2826

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.

2927

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


June 30, 2022		Level 1	Level 2	Level 3	Total Gross Derivative Instruments
March 31, 2023						March 31, 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	—	140	—	140	Foreign exchange contracts	—	122	—	122
Interest rate contracts	Interest rate contracts	—	342	—	342	Interest rate contracts	—	215	—	215
Commodity contracts	Commodity contracts	50	180	128	358	Commodity contracts	46	63	84	193
Other contracts	Other contracts	—	8	—��	8	Other contracts	—	2	—	2
		50	670	128	848		46	402	84	532
Long-term derivative assets	Long-term derivative assets					Long-term derivative assets
Foreign exchange contracts	Foreign exchange contracts	—	203	—	203	Foreign exchange contracts	—	214	—	214
Interest rate contracts	Interest rate contracts	—	566	—	566	Interest rate contracts	—	198	—	198
Commodity contracts	Commodity contracts	—	23	37	60	Commodity contracts	—	17	50	67
Other contracts		—	4	—	4

		—	796	37	833		—	429	50	479
Financial liabilities	Financial liabilities					Financial liabilities
Current derivative liabilities	Current derivative liabilities					Current derivative liabilities
Foreign exchange contracts	Foreign exchange contracts	—	(252)	—	(252)	Foreign exchange contracts	—	(131)	—	(131)
Interest rate contracts	Interest rate contracts	—	(51)	—	(51)	Interest rate contracts	—	(20)	—	(20)
Commodity contracts	Commodity contracts	(9)	(256)	(173)	(438)	Commodity contracts	(36)	(48)	(164)	(248)

		(9)	(559)	(173)	(741)		(36)	(199)	(164)	(399)
Long-term derivative liabilities	Long-term derivative liabilities					Long-term derivative liabilities
Foreign exchange contracts	Foreign exchange contracts	—	(582)	—	(582)	Foreign exchange contracts	—	(980)	—	(980)
Interest rate contracts	Interest rate contracts	—	(3)	—	(3)	Interest rate contracts	—	(49)	—	(49)
Commodity contracts	Commodity contracts	—	(39)	(99)	(138)	Commodity contracts	—	(26)	(118)	(144)

		—	(624)	(99)	(723)		—	(1,055)	(118)	(1,173)
Total net financial assets/(liabilities)
Total net financial asset/(liability)						Total net financial asset/(liability)
Foreign exchange contracts	Foreign exchange contracts	—	(491)	—	(491)	Foreign exchange contracts	—	(775)	—	(775)
Interest rate contracts	Interest rate contracts	—	854	—	854	Interest rate contracts	—	344	—	344
Commodity contracts	Commodity contracts	41	(92)	(107)	(158)	Commodity contracts	10	6	(148)	(132)
Other contracts	Other contracts	—	12	—	12	Other contracts	—	2	—	2
		41	283	(107)	217		10	(423)	(148)	(561)

3028


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:


June 30, 2022		Fair Value	Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
March 31, 2023								March 31, 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	(11)	Forward gas price	5.10	8.55	6.65	$/mmbtu2	Natural gas	(34)	Forward gas price	2.30	10.29	4.60	$/mmbtu2
Crude	Crude	(8)	Forward crude price	84.71	135.22	105.63	$/barrel	Crude	(12)	Forward crude price	72.61	104.87	92.25	$/barrel

Power	Power	(65)	Forward power price	41.77	244.81	91.29	$/MW/H	Power	(92)	Forward power price	25.07	214.37	70.68	$/MW/H
Commodity contracts - physical1	Commodity contracts - physical1							Commodity contracts - physical1
Natural gas	Natural gas	(39)	Forward gas price	3.58	20.21	6.36	$/mmbtu2	Natural gas	(34)	Forward gas price	0.60	8.14	3.51	$/mmbtu2
Crude	Crude	16	Forward crude price	100.75	144.94	122.72	$/barrel	Crude	(9)	Forward crude price	74.97	116.60	91.05	$/barrel

Power								Power	33	Forward power price	13.30	107.36	55.46	$/MW/H
		(107)							(148)

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

2One million British thermal units (mmbtu).

3129

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:


		Six months ended June 30,			Three months ended March 31,
		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	14	(143)	Included in earnings1	(44)	(52)
Included in OCI	Included in OCI	(11)	(12)	Included in OCI	33	4
Settlements	Settlements	(2)	168	Settlements	(1)	(24)
Level 3 net derivative liability at end of period	Level 3 net derivative liability at end of period	(107)	(178)	Level 3 net derivative liability at end of period	(148)	(180)

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

NET INVESTMENT HEDGES

We currently have designated a portion of our US ~~dollar denominated~~dollar-denominated debt ~~as well as a portfolio of foreign exchange forward contracts in prior periods,~~ as a hedge of our net investment in US ~~dollar denominated~~dollar-denominated investments and subsidiaries.

During the ~~six~~three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ we recognized an unrealized foreign exchange ~~loss~~gains of ~~$257~~$59 million and ~~gain of $251~~$133 million, respectively, on the translation of US ~~dollar denominated debt. During the six months ended June 30, 2022 and 2021, we recognized NaN~~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 three months ended March 31, 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 three months ended March 31, 2023 and 2022. During the three months ended March 31, 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 ~~$52~~$209 million and $102 million as at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021.~~2022, respectively.

~~We have~~

As at March 31, 2023, we had investments with a fair value of $646 million included in Restricted long-term investments ~~held in trust totaling $194 million and $217 million as at June 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 $349 million and $413 million as at June 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. Level 1 and Level 2 Restricted long-term investments are recognized at fair value.~~- $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 $249 million as at March 31, 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 $397 million (cost basis - $451 million) and $357 million (cost basis - $437 million) as at March 31, 2023 and December 31, 2022, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding ~~losses~~gains of ~~$71~~$34 million ~~and $131 million~~on these investments for the three ~~and six~~ months ended ~~June 30, 2022, respectively (2021~~March 31, 2023 (2022 - ~~gains of $20 million and~~ losses of ~~$25 million, respectively)~~$60 million).

3230

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 ~~June 30, 2022,~~March 31, 2023, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiaries was ~~$322~~$351 million and $309 million, respectively (December 31, ~~2021~~2022 - ~~$304~~$335 million and $298 million, respectively). Our investments in debt securities had a cost basis of $303 million as at March 31, 2023 (December 31, 2022 - $295 million). These investments in equity funds and debt securities are recognized at fair value, classified as Level 1 and Level 2 in the fair value hierarchy, respectively, and are recorded in Other current assets and Long-term investments in the Consolidated Statements of Financial Position. There were unrealized holding gains of $15 million and losses of ~~$19 million and $27~~$8 million for the three ~~and six~~ months ended ~~June 30,~~March 31, 2023 and 2022, ~~respectively (2021 - gains of $4 million and $3 million, respectively).~~respectively.

As at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, our long-term debt had a carrying value of ~~$77.5~~$79.5 billion and ~~$74.4~~$79.3 billion, respectively, before debt issuance costs and a fair value of ~~$73.1~~$74.9 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 ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, the non-current notes receivable had a carrying value of ~~$840~~$691 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.

9.8. INCOME TAXES

The effective income tax rates for the three months ended ~~June 30,~~March 31, 2023 and 2022 were 21.5% and ~~2021 were 18.0% and 15.1%, respectively, and for the six months ended June 30, 2022 and 2021 were 21.4% and 17.6%~~22.4%, respectively.

The period-over-period ~~increases~~decrease in the effective income tax ~~rates were~~rate is due to higher investment tax credits available on certain capital projects in the ~~effect~~US, and the effects of rate-regulated accounting for income taxes relative to ~~earnings, an increase in US minimum tax, and the release of previously recognized uncertain tax positions in 2021.~~earnings.

~~10. PENSION AND~~9. OTHER ~~POSTRETIREMENT BENEFITS~~INCOME

Three months ended June 30, Six months ended June 30,
2022 2021 2022 2021
(millions of Canadian dollars)
Service cost 45 48 90 96
Interest cost1
41 32 82 64
Expected return on plan assets1
(98) (84) (196) (168)
Amortization of actuarial (gain)/loss1
(1) 14 (2) 28
Net periodic benefit (credit)/cost (13) 10 (26) 20

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


	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Gain/(loss) on dispositions	3	(2)
Realized foreign currency gain	145	2
Unrealized foreign currency gain/(loss)	(188)	367
Net defined pension and OPEB credit	33	58
Other	109	33
	102	458

3331

~~11.~~10. 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 a comprehensive insurance program for us, our operating subsidiaries and certain equity investments. This program includes insurance coverage in types and amounts and is subject to certain deductibles, terms, exclusions and conditions that are generally consistent with coverage considered customary for our industry, however insurance does not cover all events in all circumstances. We self-insure a significant portion of expected losses relating to certain insurance property and casualty risk exposures in the US and Canada through our wholly-owned captive insurance subsidiaries.

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.

11. SUBSEQUENT EVENT

TRES PALACIOS HOLDINGS LLC

On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for US$335 million of cash, subject to customary closing adjustments. 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.

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

~~Woodfibre LNG Facility Investment~~

MAINLINE TOLLING AGREEMENT

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

The settlement will include:

•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.

As part of the settlement, Enbridge will be settling its previously filed Lakehead cost of service application, currently before the US' Federal Energy Regulatory Commission (FERC).

ACQUISITIONS

Tres Palacios Holdings LLC

On ~~July 29, 2022,~~April 3, 2023, we ~~announced our investment in the 2.1~~acquired Tres Palacios Holdings LLC (Tres Palacios) for US$335 million ~~tonnes per annum (mtpa) Woodfibre LNG~~of cash, subject to customary closing adjustments. Tres Palacios is a natural gas storage facility located in ~~Squamish, British Columbia (BC) developed by Pacific Energy Corporation Limited. Our 30% ownership~~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 ~~the facility~~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 ~~extension~~gas storage facility located in British Columbia, Canada with a working gas capacity of ~~our BC Pipeline System, which will supply gas~~approximately 77 Bcf. The transaction is expected to ~~the facility under a 40-year transportation agreement~~close later in 2023, subject to receipt of customary regulatory approvals and ~~supports expansion of the BC Pipeline System.~~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. On July 11, 2022,~~became effective on January 1, 2023. Texas Eastern ~~requested~~received FERC approval on April 3, 2023 to implement the ~~chief Administrative Law Judge (ALJ) to suspend the procedural schedule as an unopposed~~settled rates and other settlement ~~in principle was reached between the participants. The parties are working to finalize the Stipulation and Agreement and file it with the Federal Energy Regulatory Commission.~~provisions.

Maritimes & Northeast Pipeline

The current toll settlement agreement for the Canadian portion of Maritimes & Northeast (M&N) Pipeline

In expires in December ~~2021,~~2023. Settlement negotiations with M&N Pipeline shippers are planned throughout 2023 with the objective of reaching a toll settlement which would be effective January 1, 2024. It is expected that a settlement agreement will be filed in the fourth quarter of 2023 with the Canada Energy Regulator (CER) ~~approved interim rates~~ for ~~the Canadian portion of M&N Pipeline effective January 1, 2022, which were based on the negotiated 2022 rates~~review and approval. A CER decision is expected 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.~~first quarter of 2024.

~~BC Pipeline~~

The settlement agreement for our BC Pipeline System expired in December 2021. The CER has approved 2022 interim tolls for BC Pipeline effective January 1, 2022 and settlement agreement negotiations are ongoing.

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~~to establish a 2024 through 2028 Incentive 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 basis and to establish a price cap rate setting mechanism ~~and represents~~(Phase 2) to be used for 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~~remainder 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~~IR term (2025 – 2028). An OEB decision is expected on 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. An OEB decision on Phase 1 of the 2023 Application is expected in the second half of ~~2022.~~ 2023.

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 ~~addition, Enbridge Gas does~~ ~~not anticipate~~March 2023, ~~capital investments~~the April 1, 2023 QRAM application was filed and approved by the OEB, which included an adjustment 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~~prior mitigation approved as part of the ~~2023 Application.~~July 1, 2022 QRAM. The recovery of the outstanding PGVA balance from the extended recovery period approved as part of the July 1, 2022 QRAM will now be completed by March 31, 2024.

As at March 31, 2023, Enbridge Gas' PGVA receivable balance was $287 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 10-year fixed-to-fixed subordinated~~three-year senior notes, ~~which mature on January 19, 2082. The net proceeds from the offering were used to redeem Preference Shares, Series 17~~callable at par ~~on March 1, 2022.~~

~~On February 17, 2022, we closed a three tranche offering of aggregate US$1.5 billion~~after one year at our option, and 10-year sustainability-linked senior notes, ~~consisting~~for an aggregate principal amount of US$~~600 million two-year floating rate notes, US$400 million two-year notes and US$500 million three-year notes.~~3.0 billion. Each tranche is payable semi-annually in arrears and matures ~~on February 16, 2024, February 16, 2024~~in March 2026 and ~~February 14, 2025,~~March 2033, respectively.

In March 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to $2.5 billion.

On ~~May 17, 2022,~~April 15, 2023 call date, we ~~entered into a three year term loan with a syndicate~~redeemed at par all of ~~Japanese banks for approximately $806~~the outstanding US$600 million ~~(¥84.8 billion), which will mature in May 2025 and replaces the approximately $499 million (¥52.5 billion) term loan~~five-year callable, 6.38% fixed-to-floating rate subordinated notes 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 July 22, 2022, we increased our credit facilities by approximately $481 million.~~carried an original maturity date of April 2078.

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.

36As at March 31, 2023, after adjusting for the impact of floating-to-fixed interest rate swap hedges, less than 5% of our total debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements - Note 7 - Risk Management and Financial Instruments for more information on our interest rate hedging program.

RESULTS OF OPERATIONS


		Three months ended June 30,		Six months ended June 30,			Three months ended March 31,
		2022	2021	2022	2021			2023	2022
(millions of Canadian dollars, except per share amounts)	(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	1,818	2,044	4,147	4,083	Liquids Pipelines		2,363	2,329
Gas Transmission and Midstream	Gas Transmission and Midstream	1,119	868	2,133	1,841	Gas Transmission and Midstream		1,205	1,014
Gas Distribution and Storage	Gas Distribution and Storage	417	458	1,082	1,092	Gas Distribution and Storage		716	665
Renewable Power Generation	Renewable Power Generation	122	115	284	271	Renewable Power Generation		136	162
Energy Services	Energy Services	(177)	(239)	(278)	(175)	Energy Services		1	(101)
Eliminations and Other	Eliminations and Other	(704)	92	(349)	312	Eliminations and Other		6	355
Earnings before interest, income taxes and depreciation and amortization1	Earnings before interest, income taxes and depreciation and amortization1	2,595	3,338	7,019	7,424	Earnings before interest, income taxes and depreciation and amortization1		4,427	4,424
Depreciation and amortization	Depreciation and amortization	(1,064)	(929)	(2,119)	(1,861)	Depreciation and amortization		(1,146)	(1,055)
Interest expense	Interest expense	(791)	(618)	(1,510)	(1,275)	Interest expense		(905)	(719)
Income tax expense	Income tax expense	(133)	(270)	(726)	(753)	Income tax expense		(510)	(593)
Earnings attributable to noncontrolling interests	Earnings attributable to noncontrolling interests	(12)	(37)	(40)	(59)	Earnings attributable to noncontrolling interests		(49)	(28)
Preference share dividends	Preference share dividends	(145)	(90)	(247)	(182)	Preference share dividends		(84)	(102)
Earnings attributable to common shareholders	Earnings attributable to common shareholders	450	1,394	2,377	3,294	Earnings attributable to common shareholders		1,733	1,927
Earnings per common share attributable to common shareholders	Earnings per common share attributable to common shareholders	0.22	0.69	1.17	1.63	Earnings per common share attributable to common shareholders		0.86	0.95
Diluted earnings per common share attributable to common shareholders	Diluted earnings per common share attributable to common shareholders	0.22	0.69	1.17	1.63	Diluted earnings per common share attributable to common shareholders		0.85	0.95

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

3735

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended ~~June 30, 2022,~~March 31, 2023, compared with the three months ended ~~June 30, 2021~~March 31, 2022

Earnings attributable to common shareholders were negatively impacted by ~~$937~~$215 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•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); partially offset by

•a non-cash, net unrealized derivative fair value ~~losses~~gain of ~~$850~~$532 million ($~~651~~399 million after-tax) in ~~2022,~~2023, compared ~~with unrealized gains~~to a net gain of ~~$242~~$433 million ($~~185~~331 million after-tax) in ~~2021,~~2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;

•~~restructuring expense~~a non-cash, net positive equity earnings adjustment of ~~$100~~$8 million ($776 million after-tax) ~~associated with our enterprise insurance strategy;~~

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

•a net negative adjustment ~~to crude oil and natural gas inventories in our Energy Services business segment~~ of ~~$62~~$63 million ($4847 million after-tax) in 2022 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investee, DCP Midstream, LP (DCP); ~~and~~

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

•the absence ~~in 2022~~ of a ~~$57~~$44 million ($4333 million after-tax) ~~property tax settlement received~~impairment of lease assets in ~~2021 related to the resolution of Minnesota property tax appeals for 2012-2018.~~2022;

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

•a non-cash, net unrealized ~~losses~~gain of ~~$16~~$8 million ($126 million after-tax) in 2023, compared to a net loss of $21 million ($16 million after-tax) in 2022, ~~compared with unrealized losses of $153 million ($117 million after-tax) 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; and

•a ~~non-cash,~~ net ~~positive equity earnings adjustment~~unrealized gain of ~~$22~~$13 million ($1711 million after-tax) in ~~2022, compared to a net negative adjustment of $47 million ($36 million after-tax) in 2021 relating to our share of~~2023, reflecting changes in the mark-to-market value of ~~derivative financial instruments of~~equity fund investments held by our ~~equity method investees, DCP Midstream, LLC (DCP Midstream) and Aux Sable Canada LP, Aux Sable Liquid Products L.P. and Aux Sable Midstream LLC (Aux Sable).~~wholly-owned captive insurance subsidiaries.

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 $7$21 million ~~decrease~~increase in earnings attributable to common shareholders is primarily explained by:

•higher ~~depreciation~~contributions from our Liquids Pipelines segment due to increased ownership of the Gray Oak Pipeline and ~~amortization expense as a result of several projects placed into service~~Cactus II Pipeline acquired in the ~~fourth quarter~~second half of ~~2021, as well as for new export assets acquired~~2022 and higher volumes from the Flanagan South Pipeline;

•higher contributions from Mainline System and Line 9 in ~~October 2021;~~our Liquids Pipelines segment driven by increased crude demand, net of a lower Line 3 Replacement (L3R) surcharge and the recognition of a higher provision against the interim Mainline IJT;

•recognition of revenues in our Gas Transmission and Midstream segment attributable to the Texas Eastern rate case settlement, which we did not begin recognizing until the second half of 2022; and

•~~higher interest expense primarily due to reduced capitalized interest associated with~~ the favorable effect of translating US ~~portion of the Line 3 Replacement (L3R) Project placed into service in the fourth quarter of 2021, as well as~~dollar earnings at a higher average ~~principal and higher interest rates;~~exchange rate in 2023 compared to the same period in 2022; partially offset by

•~~increased earnings within our Liquids Pipelines segment from the implementation of the full L3R surcharge beginning~~a reduction in ~~October 2021 and from new export assets acquired in October 2021;~~

•~~higher throughput within our Liquids Pipelines segment driven by incremental L3R capacity; and~~

•~~increased~~ earnings from our Gas Transmission and Midstream segment primarily due to our decreased interest in DCP as a result of ~~higher~~a joint venture merger transaction with Phillips 66 that closed in the third quarter in 2022;

•lower commodity prices ~~benefiting our investments in~~impacting the DCP ~~Midstream~~ and Aux Sable ~~as well as~~ Canada LP, Aux Sable Liquid Products LP and Aux Sable Midstream LLC (collectively, Aux Sable) joint ventures in our Gas Transmission and Midstream segment; and

•higher ~~contributions from projects placed into service in November 2021.~~Interest expense primarily due to higher interest rates and higher average principal.

3836

~~Six~~BUSINESS SEGMENTS

LIQUIDS PIPELINES


	Three months ended March 31,
		2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization		2,363	2,329

Three months ended ~~June 30, 2022,~~March 31, 2023, compared with the ~~six~~three months ended ~~June 30, 2021~~March 31, 2022

~~Earnings attributable to common shareholders were~~EBITDA was negatively impacted by ~~$981~~$103 million due to certain infrequent or other non-operating factors, primarily explained ~~by the following:~~by:

•a realized loss of $638 million due to termination of foreign exchange hedges, reflecting changes in the key settlement terms under the CTS; partially offset by

•a non-cash, net unrealized ~~derivative fair value losses~~gain of ~~$417~~$613 million ~~($320 million after-tax)~~ in ~~2022,~~2023, compared with ~~unrealized gains~~a net gain of ~~$521~~$122 million ~~($396 million after-tax)~~ in ~~2021,~~2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;

•~~restructuring expense of $100 million ($77 million after-tax) associated with our enterprise insurance strategy;~~

•~~a net negative adjustment to crude oil and natural gas inventories in our Energy Services business segment of $72 million ($55 million after-tax);~~

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

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

•the ~~absence in 2022~~receipt of a ~~$57~~litigation claim settlement of $68 million ~~($43 million after-tax) property tax settlement received~~ in ~~2021 related to the resolution of Minnesota property tax appeals for 2012-2018; partially offset by~~

•a non-cash, net negative equity earnings adjustment of $34 million ($26 million after-tax) in 2022, compared to a net negative adjustment of $66 million ($50 million after-tax) in 2021 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP Midstream and Aux Sable.2023.

After taking into consideration the factors above, the remaining ~~$64 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:~~

•~~increased earnings within our Liquids Pipelines segment from the implementation of the full L3R surcharge beginning in October 2021 and from the new export assets acquired in October 2021;~~

•~~higher throughput within our Liquids Pipelines segment as a result of incremental L3R capacity placed into service in October 2021; and~~

•increased earnings from our Gas Transmission and Midstream segment primarily as a result of higher commodity prices benefiting our investments in DCP Midstream and Aux Sable, as well as higher contributions from projects placed into service in November 2021; partially offset by

•~~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; and~~

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

~~BUSINESS SEGMENTS~~

~~LIQUIDS PIPELINES~~

Three months ended
June 30, Six months ended
June 30,
2022 2021 2022 2021
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization1
1,818 2,044 4,147 4,083

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

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

~~EBITDA was negatively impacted by $477 million due to certain infrequent or other non-operating factors, primarily explained by the following:~~

•non-cash, unrealized losses of $196 million in 2022, compared with unrealized gains of $145 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;

•~~an asset impairment loss of $40 million relating to MacKay River line within our Alberta Regional Oil Sands System; and~~

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

~~After taking into consideration the factors above, the remaining $251~~$137 million increase is primarily explained by the following significant business factors:

•higher Mainline System ex-Gretna average throughput of 2.8 million barrels per day (mmbpd) in 2022 as compared to 2.6 mmbpd in 2021 driven by higher demand and incremental L3R capacity that came into service October 2021;

•~~implementation of full L3R surcharge of US$0.935 per barrel beginning October 2021 compared to the Canadian L3R Program surcharge of US$0.20 per barrel;~~

•higher contributions from the Gulf Coast and Mid-Continent ~~System~~Systems 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; ~~and~~

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

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

•~~lower contributions from Seaway Crude Pipeline System, Spearhead Pipeline and Cushing storage assets as a result of lower demand.~~

~~Six months ended June 30, 2022, compared with the six months ended June 30, 2021~~

~~EBITDA was negatively impacted by $523 million due to certain infrequent or other non-operating factors, primarily explained by the following:~~

•non-cash, unrealized losses of $74 million in 2022, compared with unrealized gains of $306 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;

•~~an asset impairment loss of $40 million relating to MacKay River line within our Alberta Regional Oil Sands System; and~~

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

~~After taking into consideration the factors above, the remaining $587 million increase is primarily explained by the following significant business factors:~~

•higher Mainline System ex-Gretna average throughput of ~~2.9~~3.1 million barrels per day (mmbpd) in 2023 as compared to 3.0 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 L3R capacity that came into service October 2021;~~

•~~implementation~~net of ~~full~~a lower L3R surcharge and the recognition of ~~US$0.935 per barrel beginning October 2021 compared to~~a higher provision against the ~~Canadian L3R Program surcharge of US$0.20 per barrel;~~interim Mainline IJT;

•higher contributions from ~~the Gulf Coast and Mid-Continent System~~certain Bakken pipelines due ~~primarily~~ to ~~the acquisition of the EIEC and related assets in the fourth quarter of 2021, as well as~~ higher ~~volumes from our Flanagan South Pipeline;~~volumes; and

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

•lower contribution from Seaway Crude Pipeline System due to lower volumes in 2023 and higher expiration of customer make-up rights in the ~~recognition~~same period of ~~a provision against the interim Mainline IJT for barrels shipped in~~ 2022; and

•~~lower contributions from Seaway Crude Pipeline System, Spearhead Pipeline and Cushing storage assets~~higher power costs as a result of ~~lower demand.~~increased volumes and power prices.

GAS TRANSMISSION AND MIDSTREAM

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


	Three months ended March 31,
		2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization		1,205	1,014

Three months ended ~~June 30, 2022,~~March 31, 2023, compared with the three months ended ~~June 30, 2021~~March 31, 2022

EBITDA was positively impacted by ~~$102~~$60 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net positive equity earnings adjustment of ~~$22~~$8 million in ~~2022,~~2023, compared to a net negative adjustment of ~~$47~~$63 million 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 Midstream and Aux Sable.~~investee, DCP.

The remaining ~~$149~~$131 million increase is primarily explained by the following significant business factors:

•~~higher commodity prices benefiting earnings from our investments in DCP Midstream and Aux Sable joint ventures;~~

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

•~~contributions from~~Texas Eastern rate case settlement, which we did not begin recognizing until the ~~Cameron Extension, Middlesex Extension and the Appalachia to Market projects placed into service in the fourth quarter~~second half of ~~2021;~~

•~~higher AECO-Chicago basis differential and lower costs benefiting earnings from our investment in Alliance Pipeline (Alliance);~~2022; and

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

•~~higher operating costs.~~

~~Six months ended June 30, 2022, compared with the six months ended June 30, 2021~~

~~EBITDA was positively impacted by $92 million due to certain infrequent or other non-operating factors, primarily explained by~~ a ~~non-cash, net negative equity earnings adjustment of $34 million~~reduction in 2022, compared to a net negative adjustment of $66 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 Midstream and Aux Sable.

~~The remaining $200 million increase is primarily explained by the following significant business factors:~~

•~~higher commodity prices benefiting earnings from our investments in DCP Midstream and Aux Sable joint ventures;~~

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

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

•~~higher AECO-Chicago basis differential and lower costs benefiting~~ earnings from our investment in ~~Alliance;~~DCP as a result of our decreased interest due to the joint venture merger transaction with Phillips 66 that closed during the third quarter in 2022; and

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

•~~higher operating costs.~~lower commodity prices impacting our DCP and Aux Sable joint ventures.

GAS DISTRIBUTION AND STORAGE


		Three months ended June 30,		Six months ended June 30,			Three months ended March 31,
		2022	2021	2022	2021			2023	2022
(millions of Canadian dollars)	(millions of Canadian dollars)					(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization1		417	458	1,082	1,092
Earnings before interest, income taxes and depreciation and amortization						Earnings before interest, income taxes and depreciation and amortization		716	665

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

Three months ended ~~June 30, 2022,~~March 31, 2023, compared with the three months ended ~~June 30, 2021~~March 31, 2022

EBITDA was ~~negatively~~positively impacted by ~~$41~~$51 million primarily explained by the following significant business factors:

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

•~~higher operating costs at Enbridge Gas due to timing of expenditures; partially offset by~~

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

~~Six months ended June 30, 2022, compared with the six months ended June 30, 2021~~

EBITDA was negatively impacted by $10 million primarily explained by the absence of earnings from Noverco due to the sale of our minority investment in December 2021, as well as higher operating costs at Enbridge Gas due to timing of expenditures, partially offset by the following:

•~~higher distribution charges at Enbridge Gas~~ resulting from increases in rates and customer base; and

•favorable timing of recognition of storage demand and transportation costs of $63 million, which will be reversed over the remainder of 2023; partially 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~~$63 million ~~while warmer than normal weather in 2021 negatively impacted 2021 EBITDA by approximately $23 million.~~year-over- year.

4238

RENEWABLE POWER GENERATION

Three months ended
June 30, Six months ended
June 30,
2022 2021 2022 2021
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization1
122 115 284 271

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


	Three months ended March 31,
		2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization		136	162

Three months ended ~~June 30, 2022,~~March 31, 2023, compared with the three months ended ~~June 30, 2021~~March 31, 2022

EBITDA was ~~positively~~negatively impacted by $7$26 million primarily due to ~~the following significant business factors:~~

•~~stronger~~weaker wind resources at Canadian and USEuropean wind ~~facilities;~~facilities and

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

~~Six months ended June 30, 2022, compared with the six months ended June 30, 2021~~

~~EBITDA was positively impacted by $13 million primarily due to the following significant business factors:~~

•~~stronger wind resources at Canadian and US wind facilities;~~

•~~higher energy pricing at the Rampion offshore wind facilities; and~~

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

•the absence 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 (CPP Investments).

ENERGY SERVICES

Three months ended
June 30, Six months ended
June 30,
2022 2021 2022 2021
(millions of Canadian dollars)
Loss before interest, income taxes and depreciation and amortization1
(177) (239) (278) (175)

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


	Three months ended March 31,
		2023	2022
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization		1	(101)

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 ~~June 30, 2022,~~March 31, 2023, compared with the three months ended ~~June 30, 2021~~March 31, 2022

EBITDA was positively impacted by ~~$75~~$37 million due to certain non-operating factors, primarily explained ~~by:~~

•by a non-cash, net unrealized ~~losses~~gain of ~~$16~~$8 million in ~~2022,~~2023, compared with ~~unrealized losses~~a net loss of ~~$153~~$21 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; partially offset by~~

•~~a net negative adjustment to crude oil and natural gas inventories of $62 million.~~

After taking into consideration the factors above, the remaining $13 million decrease is primarily explained by more pronounced market structure backwardation and significant compression of location differentials in certain markets as compared to the same period of 2021.

~~Six months ended June 30, 2022, compared with the six months ended June 30, 2021~~

~~EBITDA was negatively impacted by $94 million due to certain non-operating factors, primarily explained by:~~

•non-cash, unrealized losses of $36 million in 2022, compared with unrealized losses of $14 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; and

•~~a net negative adjustment to crude oil and natural gas inventories of $72 million.~~prices.

After taking into consideration the factor above, the remaining $9$65 million ~~decrease~~increase is primarily explained ~~by the following significant business factors:~~by:

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

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

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

ELIMINATIONS AND OTHER

Three months ended
June 30, Six months ended
June 30,
2022 2021 2022 2021
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization1
(704) 92 (349) 312

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


	Three months ended March 31,
		2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization		6	355

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 ~~June 30, 2022,~~March 31, 2023, compared with the three months ended ~~June 30, 2021~~March 31, 2022

EBITDA was negatively impacted by ~~$847~~$316 million due to certain infrequent or non-operating factors, primarily explained by:

•a non-cash, net unrealized ~~losses of $656 million in 2022, compared with unrealized gains~~loss of $83 million in ~~2021,~~2023, compared with a net gain of $309 million in 2022, reflecting ~~the change~~changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange ~~risk,~~risk; partially offset by

•the absence of a $44 million impairment of lease assets in 2022; and

•~~restructuring expense~~a net unrealized gain of ~~$100~~$13 million ~~associated with~~in 2023, reflecting changes in the mark-to-market value of equity fund investments held by our ~~enterprise~~wholly-owned captive insurance ~~strategy.~~subsidiaries.

After taking into consideration the non-operating factors above, the remaining ~~$51~~$33 million ~~increase~~decrease is primarily explained by ~~the timing of certain operating and administrative cost recoveries from the business units, as well as higher~~lower realized foreign exchange gains on hedge settlements in ~~2022.~~2023.

~~Six months ended June 30, 2022, compared with the six months ended June 30, 2021~~

~~EBITDA was negatively impacted by $691 million due to certain infrequent or non-operating factors, primarily explained by:~~

•non-cash, unrealized losses of $347 million in 2022, compared with unrealized gains of $197 million in 2021, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;

•~~restructuring expense of $100 million associated with our enterprise insurance strategy; and~~

•~~an impairment of $44 million for lease assets due to office relocation plans.~~

After taking into consideration the non-operating factors above, the remaining $30 million increase is primarily explained by the timing of certain operating and administrative cost recoveries from the business units, as well as higher realized foreign exchange gains on hedge settlements in 2022.

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 Under construction 3Q - 2022
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
GAS DISTRIBUTION AND STORAGE
8. Storage Enhancements 100 % $0.1 billion No significant expenditures to date Under construction 2H - 2022
9. System Enhancement Project 100 % $0.1 billion No significant expenditures to date Under construction 4Q - 2022
10.
Natural Gas Expansion Program5
100 % $0.1 billion No significant expenditures to date Pre-construction 2022 - 2027
11. Panhandle Regional Expansion 100 % $0.3 billion No significant expenditures to date Pre-construction 2023 - 2024
RENEWABLE POWER GENERATION
12. East-West Tie Line 25 % $0.2 billion $0.2 billion Complete In-service
13. Solar Self-Power Projects 100 % US$0.2 billion No significant expenditures to date Under construction 2022 - 2023
14.
Saint-Nazaire France Offshore Wind Project6
25.5 % $0.9 billion $0.6 billion Under construction 4Q - 2022
(€0.6 billion) (€0.4 billion)
15.
Provence Grand Large Floating Offshore Wind Project7
25 % $0.1 billion $0.1 billion Under construction 2023
(€0.1 billion) (€0.1 billion)
16.
Fécamp Offshore Wind Project8
17.9 % $0.7 billion $0.3 billion Under construction 2023
(€0.5 billion) (€0.2 billion)
17.
Calvados Offshore Wind Project9
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$69 million	Pre-construction	2023 - 2024
2.	Texas Eastern Modernization	100	%	US$394 million	US$13 million	Pre-construction	2024 - 2025
3.	T-North Expansion	100	%	$1.2 billion	$7 million	Pre-construction	2026
4.	Woodfibre LNG3	30	%	US$1.5 billion	US$153 million	Pre-construction	2027
5.	T-South Expansion	100	%	$3.6 billion	$5 million	Pre-construction	2028


RENEWABLE POWER GENERATION
6.	Fécamp Offshore Wind4	17.9	%	$692 million	$393 million	Under construction	2023
				(€471 million)	(€269 million)
7.	Calvados Offshore Wind5	21.7	%	$954 million	$260 million	Under construction	2025
				(€645 million)	(€180 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 ~~June 30, 2022.~~

~~3 This includes the Gator Express Project with an estimated capital cost of $31 million.~~

~~4 Our equity contribution is $0.9 billion, with the remainder of the project financed through project level non-recourse debt.~~

5 Represents 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.

~~6 Our equity contribution is $0.15 billion, with the remainder of the project financed through non-recourse project level debt.~~

March 31, 2023.

~~7 Our equity contribution is $0.05 billion, with the remainder of the project financed through non-recourse project level debt.~~

8 3Our equity contribution is ~~$0.1 billion,~~US$893 million, with the remainder ~~of the project~~ financed through non-recourse project level debt.

9 4Our equity contribution is ~~$0.15 billion,~~$103 million, with the remainder ~~of the project~~ financed through non-recourse project level debt.

5Our equity contribution is $181 million, with the remainder financed through non-recourse project level debt.

A full description of each of our projects is provided in our annual report on Form 10-K for the year ended December 31, ~~2021. Significant~~2022. No significant updates ~~that~~ have occurred since the date of filing of our Form ~~10-K are discussed below.~~

~~GAS TRANSMISSION AND MIDSTREAM~~

•~~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 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’s LNG export facility located in Plaquemines Parish, Louisiana and is underpinned 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 by 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 Fortis BC's Eagle Gas Pipeline to transport feedstock from BC Pipeline to the facility. The project is expected to be placed into service in 2027.

~~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 Projects~~ – 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 continues to assess the condition of the line through continued integrity work, ensuring the ongoing safety and reliability of the line. As a result, the project has been excluded from the table above.

~~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.~~

10-K.

4740

~~OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT~~

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

~~GAS TRANSMISSION AND MIDSTREAM~~

•~~Valley Crossing Expansion Project~~ –On January 10, 2022, we executed a precedent agreement with Texas LNG Brownsville LLC (Texas LNG) under which, via an expansion of our Valley Crossing Pipeline, 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 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.~~

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 ~~$1.0 billion,~~$881 million, which are expected to be paid over the next ~~five~~four years.

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

CAPITAL MARKET ACCESS

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

Credit Facilities and Liquidity

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities as at ~~June 30, 2022:~~March 31, 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.	2023-2026	10,818	9,153	1,665	Enbridge Inc.	2023-2027	9,623	7,053	2,570
Enbridge (U.S.) Inc.	Enbridge (U.S.) Inc.	2023-2026	7,095	4,493	2,602	Enbridge (U.S.) Inc.	2024-2027	8,594	1,702	6,892
Enbridge Pipelines Inc.	Enbridge Pipelines Inc.	2024	2,000	797	1,203	Enbridge Pipelines Inc.	2024	2,000	876	1,124
Enbridge Gas Inc.	Enbridge Gas Inc.	2023	2,000	1,620	380	Enbridge Gas Inc.	2024	2,500	1,440	1,060
Total committed credit facilities	Total committed credit facilities		21,913	16,063	5,850	Total committed credit facilities		22,717	11,071	11,646

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 ~~July 2024, which includes a one-year term out provision from July 2023.~~

As at ~~June 30, 2022,~~March 31, 2023, our net available liquidity totaled ~~$6.9~~$12.6 billion (December 31, ~~2021~~2022 - ~~$6.5~~$10.0 billion), consisting of available credit facilities of ~~$5.9~~$11.6 billion (December 31, ~~2021~~2022 - ~~$6.2~~$9.1 billion) and was inclusive of unrestricted cash and cash equivalents of ~~$1.0 billion~~$976 million (December 31, ~~2021~~2022 - ~~$286~~$861 million) as reported in the Consolidated Statements of Financial Position.

LONG-TERM DEBT ISSUANCES

During the ~~six~~three months ended ~~June 30, 2022,~~March 31, 2023, we completed the following long-term debt issuances totaling ~~$750 million and~~ US$~~1.5~~3.0 billion:

Company

Issue Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

March 2023

5.70%

sustainability-linked senior notes due March 20331

US$2,300

March 2023

5.97%

senior notes due March 20262

US$700

2We have the option to call the notes at par after one year from issuance. Refer to Part I. Item 1. Financial Statements - Note 7 - Risk Management and Financial Instruments.

LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2023, we completed the following long-term debt repayments totaling US$513 million and $275 million:

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

Tri Global Energy, LLC

January 2023

10.00

senior notes

US$4

January 2023

14.00

senior notes

US$9

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

~~LONG-TERM DEBT REPAYMENTS~~

~~During~~On the ~~six months ended June 30, 2022,~~April 15, 2023 call date, we ~~completed~~redeemed at par all of the ~~following long-term debt repayments totaling~~outstanding US$~~784~~600 million ~~and $334 million:~~

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 ~~$43~~$75 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 ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, we had positive and negative working capital ~~position~~positions of ~~$0.4~~$576 million and $2.1 billion, ~~and $3.1 billion. In both periods,~~respectively. During the three months ended March 31, 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


		Six months ended June 30,				Three months ended March 31,
			2022	2021			2023	2022
(millions of Canadian dollars)	(millions of Canadian dollars)				(millions of Canadian dollars)
Operating activities	Operating activities		5,473	5,053	Operating activities		3,866	2,939
Investing activities	Investing activities		(2,120)	(3,601)	Investing activities		(1,437)	(1,318)
Financing activities	Financing activities		(2,605)	(1,463)	Financing activities		(2,289)	(1,483)
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		20	(20)	Effect of translation of foreign denominated cash and cash equivalents and restricted cash		4	(4)
Net change in cash and cash equivalents and restricted cash	Net change in cash and cash equivalents and restricted cash		768	(31)	Net change in cash and cash equivalents and restricted cash		144	134

Significant sources and uses of cash for the ~~six~~three months ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~ are summarized below:

Operating Activities

Typically, the primary factors impacting cash flow from 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 cash receipts and payments generally. Cash provided by operating activities is also impacted by changes in earnings and certain ~~unusual,~~ infrequent ~~and~~or other non-operating factors, as discussed ~~under~~in Results of Operations.

Investing Activities

Cash used in investing activities primarily relates to capital expenditures to execute our capital program, which is further described in Growth Projects - Commercially Secured Projects. The timing of project ~~approval,~~approval, construction and in-service dates impacts the timing of cash requirements. ~~Factors impacting the decrease~~The increase in cash used in investing activities period-over-period ~~primarily include:~~

•~~lower capital expenditures~~was also due to the ~~US L3R Program that was placed into service~~ acquisition of an additional 10.0% ownership in the ~~fourth quarter of 2021;~~Gray Oak Pipeline, partially offset by

•~~increased contributions made to our equity investment in Bakken Pipeline System due to~~ ~~debt servicing requirements; and~~

•~~the absence~~ net receipts of ~~proceeds received~~long-term notes receivable from ~~the sale of 49% of an entity that holds our 50% interest in Éolien Maritime France SAS to CPP Investments~~affiliates, in the first quarter of ~~2021.~~2023.

Financing Activities

C~~ash~~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 financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting ~~the~~the increase in cash used in fi~~nancing~~financing activities period-over-period primarily include:

•~~the redemption of Preference Shares, Series 17~~higher net commercial paper and ~~Series J~~credit facility repayments in ~~the first and second quarters of 2022, respectively;~~

•~~lower long-term debt issuances and net short-term borrowings in 2022~~2023 when compared to the same period in ~~2021;~~2022;

•~~the repurchase and cancellation~~net repayments of ~~2,737,965 common shares under our NCIB for approximately $150 million~~short-term borrowings in 2023 when compared to net issuances during the ~~period;~~same period in 2022; and

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

5143

The factors above were partially offset by:

•~~lower~~higher long-term ~~term~~ debt ~~repayments and higher net commercial paper draws~~issuances in ~~2022~~2023 when compared to the same period in ~~2021;~~2022, as well as lower repayments of long-term debt made during the first quarter of 2023; and

•the absence in 2023 of the redemption of ~~WEI's preferred~~Preference Shares, Series 17 and the repurchase and cancellation of 950,024 common shares under our NCIB for approximately $50 million in the first quarter of ~~2021.~~2022.

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 ~~June 30, 2022,~~March 31, 2023, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.

2As at ~~June 30, 2022,~~March 31, 2023, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

5244

Enbridge Notes under Guarantees


USD Denominated1			CAD Denominated2
Floating Rate Senior Notes due ~~2023~~			~~3.190% Senior Notes due 2022~~
~~Floating Rate Senior Notes due~~ 2024			~~3.940% Senior Notes due 2023~~
~~2.900% Senior Notes due 2022~~			3.940% Senior Notes due 2023
4.000% Senior Notes due 2023			3.950% Senior Notes due 2024
0.550% Senior Notes due 2023			2.440% Senior Notes due 2025
3.500% Senior Notes due 2024			3.200% Senior Notes due 2027
2.150% Senior Notes due 2024			5.700% Senior Notes due 2027
2.500% Senior Notes due 2025			6.100% Senior Notes due 2028
2.500% Senior Notes due 2025			2.990% Senior Notes due 2029
~~2.500%~~4.250% Senior Notes due ~~2025~~2026			7.220% Senior Notes due 2030
~~4.250%~~1.600% Senior Notes due 2026			7.200% Senior Notes due 2032
~~1.600%~~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
~~3.700%~~3.125% Senior Notes due ~~2027~~2029			5.570% Senior Notes due 2035
~~3.125%~~2.500% Sustainability-Linked Senior Notes due ~~2029~~2033			5.750% Senior Notes due 2039
~~2.500%~~5.700% Sustainability-Linked Senior Notes due 2033			5.120% Senior Notes due 2040
4.500% Senior Notes due 2044			4.240% Senior Notes due 2042
5.500% Senior Notes due 2046			4.570% Senior Notes due 2044
4.000% Senior Notes due 2049			4.870% Senior Notes due 2044
3.400% Senior Notes due 2051			4.100% Senior Notes due 2051
			6.510% Senior Notes due 2052
			4.560% Senior Notes due 2064

1As at ~~June 30, 2022,~~March 31, 2023, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$~~11.7~~13.5 billion.

2As at ~~June 30, 2022,~~March 31, 2023, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately ~~$9.0~~$9.9 billion.

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

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

Summarized Combined Statement of Earnings


	~~Six~~Three months ended ~~June 30, 2022~~March 31,	2023
(millions of Canadian dollars)

Operating ~~loss~~income	~~(107)~~1
Earnings	~~1,481~~499
Earnings attributable to common shareholders	~~1,234~~414

5345

Summarized Combined Statements of Financial Position


		June 30, 2022	December 31, 2021		March 31, 2023	December 31, 2022
(millions of Canadian dollars)	(millions of Canadian dollars)			(millions of Canadian dollars)
Cash and cash equivalents				Cash and cash equivalents	532	425
Accounts receivable from affiliates	Accounts receivable from affiliates	3,142	3,442	Accounts receivable from affiliates	2,053	2,486
Short-term loans receivable from affiliates	Short-term loans receivable from affiliates	6,893	4,947	Short-term loans receivable from affiliates	4,232	5,232
Other current assets	Other current assets	696	605	Other current assets	706	969
Long-term loans receivable from affiliates	Long-term loans receivable from affiliates	47,103	51,983	Long-term loans receivable from affiliates	45,885	43,873
Other long-term assets	Other long-term assets	4,074	3,732	Other long-term assets	3,657	4,111
Accounts payable to affiliates	Accounts payable to affiliates	1,749	1,982	Accounts payable to affiliates	1,943	1,375
Short-term loans payable to affiliates	Short-term loans payable to affiliates	3,252	2,891	Short-term loans payable to affiliates	1,261	1,745
Other current liabilities	Other current liabilities	7,125	8,110	Other current liabilities	7,354	8,752
Long-term loans payable to affiliates	Long-term loans payable to affiliates	39,645	41,370	Long-term loans payable to affiliates	37,943	37,626
Other long-term liabilities	Other long-term liabilities	43,994	41,353	Other long-term liabilities	48,213	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

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, we 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 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 motion was fully briefed in March 2022. On August 18, 2022, Judge Neff denied the AG’s motion to remand and on August 30, 2022, the AG filed a motion to certify the August 18 Order, in order to pursue an appeal on the jurisdictional issue and Enbridge opposed that motion. On February 21, 2023, the Court granted the AG’s motion to certify the August 18, 2022 Order. On March 2, 2023, the AG filed her Petition for Permission to Appeal in the 6th Circuit Court of Appeals. Enbridge’s Response was filed on March 13, 2023. We anticipate a response from the 6th Circuit Court of Appeals within the next few months. In the meantime, this case will remain on hold in US District Court. If the Court of Appeals hears the appeal, it will likely take 12-18 months for briefing a decision.

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

On July 22, 2021, the Army Corps filed a notice with the District Court advising that the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a notice asserting violations of federal safety regulations resulting from the operation of DAPL. The Army Corps stated that it would consider PHMSA’s notice as part of its ongoing consideration of whether and how the Army Corps will enforce its rights on property crossed by the pipeline and in the context of the ongoing EIS. The Army Corps also granted the request from the Tribes to extend the draft EIS completion date to September 2022. The Army Corps now expects to complete the draft EIS in the spring of 2023.

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 ~~June 30, 2022,~~March 31, 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 ~~June 30, 2022~~March 31, 2023 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I. Item 1A. Risk Factors of our annual report on Form 10-K for the year ended December 31, ~~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 programs1
January 2023 (January 1 - January 31)	—	N/A	—	27,938,163
February 2023 (February 1 - February 28)	—	N/A	—	27,938,163
March 2023 (March 1 - March 31)	—	N/A	—	27,938,163

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 2022
(April 1 - April 30)
— N/A — 30,112,307
May 2022
(May 1 - May 31)
910,405 CAD$55.19 (TSX)/
CAD$55.18 (Other) 910,405 29,201,902
June 2022
(June 1 - June 30)
877,536 CAD$56.98 (TSX)/
US$47.92 (NYSE) 877,536 28,324,366

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 ~~(NYSE)~~ 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.

ITEM 6. EXHIBITS

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


Exhibit No.		Description
10.110 .1	+	Enbridge Inc. Directors’ Compensation Plan dated February 8, 2023 and effective January 1, 2023
10 .2	+	Form of Executive Employment Agreement ~~(2022)~~(2023) with Enbridge Employee Services, Inc.(incorporated by reference to Exhibit 10.1 to Enbridge’s Current Report on Form 8-K Amendment No. 2 filed March 20, 2023)
22.1*		Subsidiary Guarantors
31.1*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*		Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*		Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.SCH*		Inline XBRL Taxonomy Extension Schema Document.
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104		Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101)

5850

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:	~~July 29, 2022~~May 5, 2023	By:	/s/ ~~Al Monaco~~Gregory L. Ebel
			~~Al Monaco~~Gregory L. Ebel President, ~~and~~ Chief Executive Officer and Director (Principal Executive Officer)

Date:	~~July 29, 2022~~May 5, 2023	By:	/s/ Vern D. Yu
			Vern D. Yu Executive Vice President, Corporate Development, ~~and~~ Chief Financial Officer and President, New Energy Technologies (Principal Financial Officer)

5951


	Three months ended June 30,		Six months ended June 30,
	2022	2021	2022	2021
(millions of Canadian dollars)
Service cost	45	48	90	96
Interest cost1	41	32	82	64
Expected return on plan assets1	(98)	(84)	(196)	(168)
Amortization of actuarial (gain)/loss1	(1)	14	(2)	28
Net periodic benefit (credit)/cost	(13)	10	(26)	20