10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2023

OR

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

For the transition period from            to           

Commission file number 001-15254

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

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

200, 425 - 1st Street S.W.

Calgary, Alberta, Canada T2P 3L8

(Address of Principal Executive Offices) (Zip Code)

(403) 231-3900

(Registrant’s Telephone Number, Including Area Code)

_______________________________

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

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Shares	ENB	New York Stock Exchange

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

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

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

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

Large accelerated filer	x	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 2,024,676,423 common shares outstanding as at April 28, 2023.

	PART I	PAGE
Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	48
	PART II
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 3.	Defaults Upon Senior Securities	49
Item 4.	Mine Safety Disclosures	49
Item 5.	Other Information	50
Item 6.	Exhibits	50
	Signatures	51

2

GLOSSARY

AG	Attorney General
AOCI	Accumulated other comprehensive income/(loss)
DAPL	Dakota Access Pipeline
DCP	DCP Midstream, LP
EBITDA	Earnings before interest, income taxes and depreciation and amortization
EEP	Enbridge Energy Partners, L.P.
EIS	Environmental Impact Statement
Enbridge	Enbridge Inc.
Enbridge Gas	Enbridge Gas Inc.
Exchange Act	United States Securities Exchange Act of 1934, as amended
NCIB	Normal course issuer bid
NGL	Natural gas liquids
OCI	Other comprehensive income/(loss)
OPEB	Other postretirement benefits
SEP	Spectra Energy Partners, LP
Texas Eastern	Texas Eastern Transmission, LP
Tres Palacios	Tres Palacios Holdings LLC
US	United States

3

CONVENTIONS

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

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

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this quarterly report on Form 10-Q to provide information about us and our subsidiaries and affiliates, including management’s assessment of our and our subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: our corporate vision and strategy, including strategic priorities and enablers; expected supply of, demand for, exports of and prices of crude oil, natural gas, natural gas liquids (NGL), liquified natural gas (LNG) and renewable energy; energy transition and lower-carbon energy, and our approach thereto; environmental, social and governance goals, practices and performance; industry and market conditions; anticipated utilization of our assets; dividend growth and payout policy; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected strategic priorities and performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation and Energy Services businesses; expected costs, benefits and in-service dates related to announced projects and projects under construction; expected capital expenditures; investable capacity and capital allocation priorities; share repurchases under 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, and the timing and impact thereof; toll and rate cases discussions and proceedings and anticipated timeline and impact therefrom, including Mainline Tolling and those relating to the Gas Transmission and Midstream and Gas Distribution and Storage businesses; operational, industry, regulatory, climate change and other risks associated with our businesses; and our assessment of the potential impact of the various risk factors identified herein.

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

4

our supply chain; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes.

Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities, operating performance; legislative and regulatory parameters; litigation; acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom; operational dependence on third parties; dividend policy; project approval and support; renewals of rights-of-way; weather; economic and competitive conditions; public opinion; changes in tax laws and tax rates; exchange rates; inflation; interest rates; commodity prices; access to and cost of capital; political decisions; global geopolitical conditions; and the supply of, demand for and prices of commodities and other alternative energy, including but not limited to, those risks and uncertainties discussed in this quarterly report on Form 10-Q and in our other filings with Canadian and US securities regulators. The impact of any one assumption, risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statement made in this quarterly report on Form 10-Q or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

NON-GAAP AND OTHER FINANCIAL MEASURES

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

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

5

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS

	Three months ended March 31,
	2023	2022
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	4,783	8,325
Gas distribution sales	2,279	2,098
Transportation and other services	5,013	4,674
Total operating revenues (Note 2)	12,075	15,097
Operating expenses
Commodity costs	4,636	8,291
Gas distribution costs	1,594	1,456
Operating and administrative	2,037	1,875
Depreciation and amortization	1,146	1,055
Total operating expenses	9,413	12,677
Operating income	2,662	2,420
Income from equity investments	517	491
Other income (Note 9)	102	458
Interest expense	(905)	(719)
Earnings before income taxes	2,376	2,650
Income tax expense	(510)	(593)
Earnings	1,866	2,057
Earnings attributable to noncontrolling interests	(49)	(28)
Earnings attributable to controlling interests	1,817	2,029
Preference share dividends	(84)	(102)
Earnings attributable to common shareholders	1,733	1,927
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)	0.85	0.95

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

6

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended March 31,
	2023	2022
(unaudited; millions of Canadian dollars)
Earnings	1,866	2,057
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	(45)	294
Change in unrealized gain on net investment hedges	15	133
Excluded components of fair value hedges	7	(1)
Reclassification to earnings of loss on cash flow hedges	7	57
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(4)	(2)
Foreign currency translation adjustments	(59)	(708)
Other comprehensive loss, net of tax	(79)	(227)
Comprehensive income	1,787	1,830
Comprehensive income attributable to noncontrolling interests	(64)	(13)
Comprehensive income attributable to controlling interests	1,723	1,817
Preference share dividends	(84)	(102)
Comprehensive income attributable to common shareholders	1,639	1,715

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

7

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Three months ended March 31,
	2023	2022
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares
Balance at beginning of period	6,818	7,747
Redemption of preference shares	—	(737)
Balance at end of period	6,818	7,010
Common shares
Balance at beginning of period	64,760	64,799
Shares issued on exercise of stock options	2	36
Shares issued on vesting of restricted stock units (RSU)	12	—
Share purchases at stated value	—	(30)
Other	—	(4)
Balance at end of period	64,774	64,801
Additional paid-in capital
Balance at beginning of period	275	365
Stock-based compensation	—	13
Options exercised	(1)	(34)
Other	—	(28)
Balance at end of period	274	316
Deficit
Balance at beginning of period	(15,486)	(10,989)
Earnings attributable to controlling interests	1,817	2,029
Preference share dividends	(84)	(102)
Share purchases in excess of stated value	—	(20)
Balance at end of period	(13,753)	(9,082)
Accumulated other comprehensive income/(loss) (Note 6)
Balance at beginning of period	3,520	(1,096)
Other comprehensive loss attributable to common shareholders, net of tax	(94)	(212)
Balance at end of period	3,426	(1,308)
Total Enbridge Inc. shareholders’ equity	61,539	61,737
Noncontrolling interests
Balance at beginning of period	3,511	2,542
Earnings attributable to noncontrolling interests	49	28
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain on cash flow hedges	17	2
Foreign currency translation adjustments	(2)	(17)
	15	(15)
Comprehensive income attributable to noncontrolling interests	64	13
Distributions	(92)	(60)
Contributions	4	6
Other	(1)	35
Balance at end of period	3,486	2,536
Total equity	65,025	64,273
Dividends paid per common share	0.888	0.860

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

8

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three months ended March 31,
	2023	2022
(unaudited; millions of Canadian dollars)
Operating activities
Earnings	1,866	2,057
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	1,146	1,055
Deferred income tax expense	484	423
Unrealized derivative fair value gain, net (Note 7)	(520)	(369)
Income from equity investments	(517)	(491)
Distributions from equity investments	453	394
Other	40	47
Changes in operating assets and liabilities	914	(177)
Net cash provided by operating activities	3,866	2,939
Investing activities
Capital expenditures	(1,129)	(1,048)
Long-term investments and restricted long-term investments	(413)	(314)
Distributions from equity investments in excess of cumulative earnings	100	97
Additions to intangible assets	(66)	(53)
Affiliate loans, net	71	—
Net cash used in investing activities	(1,437)	(1,318)
Financing activities
Net change in short-term borrowings	(559)	89
Net change in commercial paper and credit facility draws	(2,921)	(283)
Debenture and term note issues, net of issue costs	4,111	2,643
Debenture and term note repayments	(968)	(1,155)
Contributions from noncontrolling interests	4	6
Distributions to noncontrolling interests	(92)	(60)
Common shares issued	—	2
Common shares repurchased	—	(50)
Preference share dividends	(84)	(91)
Common share dividends	(1,798)	(1,742)
Redemption of preference shares	—	(750)
Affiliate loans, net	51	—
Other	(33)	(92)
Net cash used in financing activities	(2,289)	(1,483)
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	144	134
Cash and cash equivalents and restricted cash at beginning of period	907	320
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.

9

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	March 31, 2023	December 31, 2022
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	976	861
Restricted cash	75	46
Trade receivables and unbilled revenues	4,755	5,616
Other current assets	2,701	3,255
Accounts receivable from affiliates	100	114
Inventory	1,311	2,255
	9,918	12,147
Property, plant and equipment, net	104,251	104,460
Long-term investments	16,320	15,936
Restricted long-term investments	646	593
Deferred amounts and other assets	9,148	9,542
Intangible assets, net	3,913	4,018
Goodwill	32,411	32,440
Deferred income taxes	463	472
Total assets	177,070	179,608
Liabilities and equity
Current liabilities
Short-term borrowings	1,437	1,996
Trade payables and accrued liabilities	4,098	6,172
Other current liabilities	3,051	5,220
Accounts payable to affiliates	47	105
Interest payable	709	763
Current portion of long-term debt	7,436	6,045
	16,778	20,301
Long-term debt	71,740	72,939
Other long-term liabilities	9,235	9,189
Deferred income taxes	14,292	13,781
	112,045	116,210
Contingencies (Note 10)
Equity
Share capital
Preference shares	6,818	6,818
Common shares (2,025 outstanding at March 31, 2023 and December 31, 2022)	64,774	64,760
Additional paid-in capital	274	275
Deficit	(13,753)	(15,486)
Accumulated other comprehensive income (Note 6)	3,426	3,520
Total Enbridge Inc. shareholders’ equity	61,539	59,887
Noncontrolling interests	3,486	3,511
	65,025	63,398
Total liabilities and equity	177,070	179,608

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

10

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by US GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2022. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our audited consolidated financial statements for the year ended December 31, 2022. Amounts are stated in Canadian dollars unless otherwise noted.

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

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

11

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
Three months ended March 31, 2023
(millions of Canadian dollars)
Transportation revenue	2,942	1,384	276	—	—	—	4,602
Storage and other revenue	64	95	99	—	—	—	258
Gas distribution revenue	—	—	2,287	—	—	—	2,287
Electricity revenue	—	—	—	66	—	—	66
Total revenue from contracts with customers	3,006	1,479	2,662	66	—	—	7,213
Commodity sales	—	—	—	—	4,783	—	4,783
Other revenue1,2	30	11	(40)	78	—	—	79
Intersegment revenue	129	1	3	—	18	(151)	—
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 March 31, 2022
(millions of Canadian dollars)
Transportation revenue	2,685	1,194	251	—	—	—	4,130
Storage and other revenue	51	84	47	—	—	—	182
Gas gathering and processing revenue	—	15	—	—	—	—	15
Gas distribution revenue	—	—	2,098	—	—	—	2,098
Electricity revenue	—	—	—	62	—	—	62
Total revenue from contracts with customers	2,736	1,293	2,396	62	—	—	6,487
Commodity sales	—	—	—	—	8,325	—	8,325
Other revenue1,2	178	7	4	94	2	—	285
Intersegment revenue	141	—	11	—	10	(162)	—
Total revenue	3,055	1,300	2,411	156	8,337	(162)	15,097

1Includes realized and unrealized gains and losses from our hedging program which for the three months ended March 31, 2023 were a net $55 million loss (2022 - $94 million gain).

2 Includes revenues from lease contracts for the three months ended March 31, 2023 and 2022 of $144 million and $164 million, respectively.

We disaggregate 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.

12

Contract Balances

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

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the three months ended March 31, 2023 included in contract liabilities at the beginning of the period was $36 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the three months ended March 31, 2023 were $124 million.

Performance Obligations

There was no material revenue recognized in the three months ended March 31, 2023 from performance obligations satisfied in previous periods.

Revenue to be Recognized from Unfulfilled Performance Obligations

Total revenue from performance obligations expected to be fulfilled in future periods is $60.0 billion, of which $6.0 billion and $6.7 billion are expected to be recognized during the remaining nine months ending December 31, 2023 and the year ending December 31, 2024, respectively.

The revenues excluded from the amounts above, based on optional exemptions available under Accounting Standards Codification (ASC) 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for 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 months ended 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, interim toll revenue recognized during the three months ended March 31, 2023 is considered variable consideration.

13

Recognition and Measurement of Revenues

	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 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.

14

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.

15

4. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

BASIC

Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding.

DILUTED

The treasury stock method is used to determine the dilutive impact of stock options and RSUs. This method assumes any proceeds from the exercise of stock options and vesting of RSUs would be used to purchase common shares at the average market price during the period.

Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:

	Three months ended March 31,
	2023	2022
(number of shares in millions)
Weighted average shares outstanding	2,025	2,026
Effect of dilutive options and RSUs	3	3
Diluted weighted average shares outstanding	2,028	2,029

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

DIVIDENDS PER SHARE

On May 2, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on June 1, 2023 to shareholders of record on May 15, 2023.

	Dividend per share
Common Shares1	$0.88750
Preference Shares, Series A	$0.34375
Preference Shares, Series B	$0.32513
Preference Shares, Series D2	$0.33825
Preference Shares, Series F	$0.29306
Preference Shares, Series H	$0.27350
Preference Shares, Series L	US$0.36612
Preference Shares, Series N	$0.31788
Preference Shares, Series P	$0.27369
Preference Shares, Series R	$0.25456
Preference Shares, Series 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	$0.38825

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

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

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

16

5. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at March 31, 2023:

	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2023-2027	9,623	7,053	2,570
Enbridge (U.S.) Inc.	2024-2027	8,594	1,702	6,892
Enbridge Pipelines Inc.	2024	2,000	876	1,124
Enbridge Gas Inc.	2024	2,500	1,440	1,060
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.

In March 2023, Enbridge Gas Inc. (Enbridge Gas) increased its 364-day extendible credit facility from $2.0 billion to $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 $720 million was unutilized as at March 31, 2023. As at December 31, 2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $689 million was unutilized.

Our credit facilities 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 March 31, 2023 and December 31, 2022, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $9.0 billion and $10.5 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.

LONG-TERM DEBT ISSUANCES

During the three months ended March 31, 2023, we completed the following long-term debt issuances totaling US$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

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

17

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 40 basis points.

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

SUBORDINATED TERM NOTES

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

FAIR VALUE ADJUSTMENT

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

During the three months ended 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.

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 March 31, 2023, we were in compliance with all covenant provisions.

18

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

Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to our common shareholders for the three months ended March 31, 2023 and 2022 are as follows:

	Cash Flow Hedges	Excluded Components of Fair Value Hedges	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees	Pension and OPEB Adjustment	Total
(millions of Canadian dollars)
Balance as at January 1, 2023	121	(35)	(1,137)	4,348	5	218	3,520
Other comprehensive income/(loss) retained in AOCI	(90)	7	15	(57)	—	—	(125)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	8	—	—	—	—	—	8
Other contracts2	1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(5)	(5)
	(81)	7	15	(57)	—	(5)	(121)
Tax impact
Income tax on amounts retained in AOCI	28	—	—	—	—	—	28
Income tax on amounts reclassified to earnings	(2)	—	—	—	—	1	(1)
	26	—	—	—	—	1	27
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
(millions of Canadian dollars)
Balance as at January 1, 2022	(897)	—	(166)	56	(5)	(84)	(1,096)
Other comprehensive income/(loss) retained in AOCI	384	(1)	133	(691)	—	—	(175)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	76	—	—	—	—	—	76
Foreign exchange contracts4	(4)	—	—	—	—	—	(4)
Other contracts2	2	—	—	—	—	—	2
Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(3)	(3)
	458	(1)	133	(691)	—	(3)	(104)
Tax impact
Income tax on amounts retained in AOCI	(92)	—	—	—	—	—	(92)
Income tax on amounts reclassified to earnings	(17)	—	—	—	—	1	(16)
	(109)	—	—	—	—	1	(108)
Balance as at March 31, 2022	(548)	(1)	(33)	(635)	(5)	(86)	(1,308)

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

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

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

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

19

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 investments and subsidiaries using foreign currency derivatives and US 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' approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps. These hedges have an average fixed rate of 4.1%.

On March 8, 2023, we issued US$700 million three-year fixed rate 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 similar right to cancel the swap after the first year. This swap has a fixed rate of 6.0%. This instrument is our only pay floating-receive fixed interest rate 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 forecasted term debt issuances via the execution of floating-to-fixed interest rate swaps with an average swap rate of 2.5%.

20

Commodity Price Risk

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

Equity Price Risk

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

TOTAL DERIVATIVE INSTRUMENTS

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

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

21

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)
Other current assets
Foreign exchange contracts	—	68	54	122	(13)	109
Interest rate contracts	194	—	21	215	(11)	204
Commodity contracts	—	—	193	193	(118)	75
Other contracts	—	—	2	2	—	2
	194	68	270	532	(142)	390
Deferred amounts and other assets
Foreign exchange contracts	—	83	131	214	(108)	106
Interest rate contracts	154	—	44	198	(43)	155
Commodity contracts	—	—	67	67	(30)	37
	154	83	242	479	(181)	298
Other current liabilities
Foreign exchange contracts	—	(42)	(89)	(131)	13	(118)
Interest rate contracts	(19)	—	(1)	(20)	11	(9)
Commodity contracts	(30)	—	(218)	(248)	118	(130)
	(49)	(42)	(308)	(399)	142	(257)
Other long-term liabilities
Foreign exchange contracts	—	—	(980)	(980)	108	(872)
Interest rate contracts	(4)	—	(45)	(49)	43	(6)
Commodity contracts	(21)	—	(123)	(144)	30	(114)
	(25)	—	(1,148)	(1,173)	181	(992)
Total net derivative asset/(liability)
Foreign exchange contracts	—	109	(884)	(775)	—	(775)
Interest rate contracts	325	—	19	344	—	344
Commodity contracts	(51)	—	(81)	(132)	—	(132)
Other contracts	—	—	2	2	—	2
	274	109	(944)	(561)	—	(561)

22

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:

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

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

23

Fair Value Derivatives

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

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	(11)	76
Unrealized gain/(loss) on hedged item	11	(87)
Realized loss on derivative	(11)	(75)
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

1Reported within Transportation and other services revenues and 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 $20 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 33 months as at March 31, 2023.

24

Non-Qualifying Derivatives

The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives:

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Foreign exchange contracts1	556	433
Interest rate contracts2	10	—
Commodity contracts3	(39)	(68)
Other contracts4	(7)	4
Total unrealized derivative fair value gain/(loss), net	520	369

1For the respective three months ended periods, reported within Transportation and other services revenues (2023 - $645 million gain; 2022 - $134 million gain) and Other income (2023 - $89 million loss; 2022 - $299 million gain) in the Consolidated Statements of Earnings.

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

3For the respective three months ended periods, reported within Transportation and other services revenues (2023 - $6 million gain; 2022 - $16 million loss), Commodity sales (2023 - $69 million gain; 2022 - $16 million loss), Commodity costs (2023 - $75 million loss; 2022 - $37 million loss) and Operating and administrative expense (2023 - $39 million loss; 2022 - $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 were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at March 31, 2023. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities.

CREDIT RISK

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

25

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

	March 31, 2023	December 31, 2022
(millions of Canadian dollars)
Canadian financial institutions	471	644
US financial institutions	115	277
European financial institutions	178	334
Asian financial institutions	97	224
Other1	88	105
	949	1,584

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

As at 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 March 31, 2023 and December 31, 2022.

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

Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, the assessment of credit ratings and netting arrangements. Within Enbridge Gas, credit risk is mitigated by the utility's large and diversified customer base and the ability to recover an estimate for expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

FAIR VALUE MEASUREMENTS

Our financial assets and liabilities measured at fair value on a recurring basis include derivatives and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.

FAIR VALUE OF FINANCIAL INSTRUMENTS

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

Level 1

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

26

Level 2

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

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

Level 3

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

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

27

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

March 31, 2023	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	122	—	122
Interest rate contracts	—	215	—	215
Commodity contracts	46	63	84	193
Other contracts	—	2	—	2
	46	402	84	532
Long-term derivative assets
Foreign exchange contracts	—	214	—	214
Interest rate contracts	—	198	—	198
Commodity contracts	—	17	50	67
	—	429	50	479
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(131)	—	(131)
Interest rate contracts	—	(20)	—	(20)
Commodity contracts	(36)	(48)	(164)	(248)
	(36)	(199)	(164)	(399)
Long-term derivative liabilities
Foreign exchange contracts	—	(980)	—	(980)
Interest rate contracts	—	(49)	—	(49)
Commodity contracts	—	(26)	(118)	(144)
	—	(1,055)	(118)	(1,173)
Total net financial asset/(liability)
Foreign exchange contracts	—	(775)	—	(775)
Interest rate contracts	—	344	—	344
Commodity contracts	10	6	(148)	(132)
Other contracts	—	2	—	2
	10	(423)	(148)	(561)

28

December 31, 2022	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	46	—	46
Interest rate contracts	—	660	—	660
Commodity contracts	65	90	147	302
Other contracts	—	7	—	7
	65	803	147	1,015
Long-term derivative assets
Foreign exchange contracts	—	309	—	309
Interest rate contracts	—	254	—	254
Commodity contracts	—	17	44	61
Other contracts	—	3	—	3
	—	583	44	627
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(566)	—	(566)
Commodity contracts	(60)	(77)	(195)	(332)
	(60)	(643)	(195)	(898)
Long-term derivative liabilities
Foreign exchange contracts	—	(1,116)	—	(1,116)
Interest rate contracts	—	(4)	—	(4)
Commodity contracts	—	(38)	(132)	(170)
	—	(1,158)	(132)	(1,290)
Total net financial asset/(liability)
Foreign exchange contracts	—	(1,327)	—	(1,327)
Interest rate contracts	—	910	—	910
Commodity contracts	5	(8)	(136)	(139)
Other contracts	—	10	—	10
	5	(415)	(136)	(546)

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

March 31, 2023	Fair Value	Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	(34)	Forward gas price	2.30	10.29	4.60	$/mmbtu2
Crude	(12)	Forward crude price	72.61	104.87	92.25	$/barrel
Power	(92)	Forward power price	25.07	214.37	70.68	$/MW/H
Commodity contracts - physical1
Natural gas	(34)	Forward gas price	0.60	8.14	3.51	$/mmbtu2
Crude	(9)	Forward crude price	74.97	116.60	91.05	$/barrel
Power	33	Forward power price	13.30	107.36	55.46	$/MW/H
	(148)

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

2One million British thermal units (mmbtu).

29

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:

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(136)	(108)
Total gain/(loss)
Included in earnings1	(44)	(52)
Included in OCI	33	4
Settlements	(1)	(24)
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 March 31, 2023 or December 31, 2022.

NET INVESTMENT HEDGES

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

During the three months ended March 31, 2023 and 2022, we recognized unrealized foreign exchange gains of $59 million and $133 million, respectively, on the translation of US dollar-denominated debt, in OCI. No unrealized gains or losses on the change in fair value of our outstanding foreign exchange forward contracts were recognized in OCI during the three months ended March 31, 2023 and 2022. No realized gains or losses associated with the settlement of foreign exchange forward contracts were 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 debt that had matured during the period, in OCI.

FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS

Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $209 million and $102 million as at March 31, 2023 and December 31, 2022, respectively.

As at March 31, 2023, we had investments with a fair value of $646 million included in Restricted long-term investments in the Consolidated Statements of Financial Position (December 31, 2022 - $593 million). These securities are classified as available-for-sale and represent restricted funds which are collected from customers and held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements.

We had restricted long-term investments held in trust totaling $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 gains of $34 million on these investments for the three months ended March 31, 2023 (2022 - losses of $60 million).

30

We have wholly-owned captive insurance subsidiaries whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. As at March 31, 2023, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiaries was $351 million and $309 million, respectively (December 31, 2022 - $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 $8 million for the three months ended March 31, 2023 and 2022, respectively.

As at March 31, 2023 and December 31, 2022, our long-term debt had a carrying value of $79.5 billion and $79.3 billion, respectively, before debt issuance costs and a fair value of $74.9 billion and $73.5 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at March 31, 2023 and December 31, 2022, the non-current notes receivable had a carrying value of $691 million and $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.

8. INCOME TAXES

The effective income tax rates for the three months ended March 31, 2023 and 2022 were 21.5% and 22.4%, respectively.

The period-over-period decrease in the effective income tax rate is due to higher investment tax credits available on certain capital projects in the US, and the effects of rate-regulated accounting for income taxes relative to earnings.

9. OTHER INCOME

	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

31

10. CONTINGENCIES

LITIGATION

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

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.

32

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our interim consolidated financial statements and the accompanying notes included in Part I. Item 1. Financial Statements of this quarterly report on Form 10-Q and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of our annual report on Form 10-K for the year ended December 31, 2022.

We continue to qualify as a foreign private issuer for purposes of the United States Securities Exchange Act of 1934, as amended (Exchange Act), as determined annually as of the end of our second fiscal quarter. We intend to continue to file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K with the United States (US) Securities and Exchange Commission (SEC) instead of filing the reporting forms available to foreign private issuers. We also intend to maintain our Form S-3 registration statements.

RECENT DEVELOPMENTS

MAINLINE TOLLING AGREEMENT

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

33

ACQUISITIONS

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. Tres Palacios is comprised of three natural gas storage salt caverns with a total FERC-certificated working gas capacity of approximately 35 billion cubic feet (Bcf) and also owns an integrated 62-mile natural gas header pipeline system, with eleven inter- and intrastate natural gas pipeline connections.

Aitken Creek Gas Storage

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

GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS

Texas Eastern Transmission

The Stipulation and Agreement for Texas Eastern Transmission, LP’s (Texas Eastern) consolidated 2021 rate cases was approved by the FERC on November 30, 2022, and became effective on January 1, 2023. Texas Eastern received FERC approval on April 3, 2023 to implement the settled rates and other settlement provisions.

Maritimes & Northeast Pipeline

The current toll settlement agreement for the Canadian portion of Maritimes & Northeast (M&N) Pipeline expires in December 2023. Settlement negotiations with M&N Pipeline shippers are 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) for review and approval. A CER decision is expected in the first quarter of 2024.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

Incentive Regulation Rate Application

In October 2022, Enbridge Gas Inc. (Enbridge Gas) filed its application with the Ontario Energy Board (OEB) to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application 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 (Phase 2) to be used for the remainder of the IR term (2025 – 2028). An OEB decision is expected on Phase 1 of the application in the second half of 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 March 2023, the April 1, 2023 QRAM application was filed and approved by the OEB, which included an adjustment to the prior mitigation approved as part of the July 1, 2022 QRAM. The recovery of the outstanding PGVA balance from the extended recovery period approved as part of the July 1, 2022 QRAM will now be completed by March 31, 2024.

As at March 31, 2023, Enbridge Gas' PGVA receivable balance was $287 million.

34

FINANCING UPDATE

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

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

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

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

As at 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 March 31,
	2023	2022
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
Liquids Pipelines	2,363	2,329
Gas Transmission and Midstream	1,205	1,014
Gas Distribution and Storage	716	665
Renewable Power Generation	136	162
Energy Services	1	(101)
Eliminations and Other	6	355
Earnings before interest, income taxes and depreciation and amortization1	4,427	4,424
Depreciation and amortization	(1,146)	(1,055)
Interest expense	(905)	(719)
Income tax expense	(510)	(593)
Earnings attributable to noncontrolling interests	(49)	(28)
Preference share dividends	(84)	(102)
Earnings attributable to common shareholders	1,733	1,927
Earnings per common share attributable to common shareholders	0.86	0.95
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.

35

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended March 31, 2023, compared with the three months ended March 31, 2022

Earnings attributable to common shareholders were negatively impacted by $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 gain of $532 million ($399 million after-tax) in 2023, compared to a net gain of $433 million ($331 million after-tax) in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;

•a non-cash, net positive equity earnings adjustment of $8 million ($6 million after-tax) in 2023, compared to a net negative adjustment of $63 million ($47 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);

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

•the absence of a $44 million ($33 million after-tax) impairment of lease assets in 2022;

•a non-cash, net unrealized gain of $8 million ($6 million after-tax) in 2023, compared to a net loss of $21 million ($16 million after-tax) in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices; and

•a net unrealized gain of $13 million ($11 million after-tax) in 2023, reflecting changes in the mark-to-market value of equity fund investments held by our 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 $21 million increase in earnings attributable to common shareholders is primarily explained by:

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

•higher contributions from Mainline System and Line 9 in 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

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

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

•lower commodity prices impacting the DCP and Aux Sable 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 Interest expense primarily due to higher interest rates and higher average principal.

36

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 March 31, 2023, compared with the three months ended March 31, 2022

EBITDA was negatively impacted by $103 million due to certain infrequent or other non-operating factors, primarily explained 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 gain of $613 million in 2023, compared with a net gain of $122 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks; and

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

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

•higher contributions from the Gulf Coast and Mid-Continent Systems due primarily to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and higher volumes from the Flanagan South Pipeline;

•higher Mainline System ex-Gretna average throughput of 3.1 million barrels per day (mmbpd) in 2023 as compared to 3.0 mmbpd in 2022, and higher Line 9 deliveries to eastern Canada driven by increased crude demand, net of a lower L3R surcharge and the recognition of a higher provision against the interim Mainline IJT;

•higher contributions from certain Bakken pipelines due to higher volumes; and

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

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

37

GAS TRANSMISSION AND MIDSTREAM 

	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 March 31, 2023, compared with the three months ended March 31, 2022

EBITDA was positively impacted by $60 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net positive equity earnings adjustment of $8 million in 2023, compared to a net negative adjustment of $63 million in 2022 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investee, DCP.

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

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

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

•a reduction in earnings from our investment in DCP as a result of our decreased interest due to the joint venture merger transaction with Phillips 66 that closed during the third quarter in 2022; and

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

GAS DISTRIBUTION AND STORAGE

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	716	665

Three months ended March 31, 2023, compared with the three months ended March 31, 2022

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

•higher distribution charges 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 in 2022, resulting in a negative EBITDA impact of approximately $63 million year-over- year.

38

RENEWABLE POWER GENERATION 

	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 March 31, 2023, compared with the three months ended March 31, 2022

EBITDA was negatively impacted by $26 million primarily due to weaker wind resources at Canadian and European wind facilities and lower energy pricing at European offshore wind facilities.

ENERGY SERVICES

	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 March 31, 2023, compared with the three months ended March 31, 2022

EBITDA was positively impacted by $37 million due to certain non-operating factors, primarily explained by a non-cash, net unrealized gain of $8 million in 2023, compared with a net loss of $21 million in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as to manage the exposure to movements in commodity prices.

After taking into consideration the factor above, the remaining $65 million increase is primarily explained by:

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

•expiration of transportation commitments; and

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

ELIMINATIONS AND OTHER

	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 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.

39

Three months ended March 31, 2023, compared with the three months ended March 31, 2022

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

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

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

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

After taking into consideration the non-operating factors above, the remaining $33 million decrease is primarily explained by lower realized foreign exchange gains on hedge settlements in 2023.

GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS

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

		Enbridge's Ownership Interest		Estimated Capital Cost1	Expenditures to Date2	Status2	Expected In-Service Date
(Canadian dollars, unless stated otherwise)
GAS TRANSMISSION AND MIDSTREAM
1.	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 March 31, 2023.

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

4Our equity contribution is $103 million, with the remainder 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, 2022. No significant updates have occurred since the date of filing of our Form 10-K.

40

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

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

CAPITAL MARKET ACCESS

We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for 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 March 31, 2023:

	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2023-2027	9,623	7,053	2,570
Enbridge (U.S.) Inc.	2024-2027	8,594	1,702	6,892
Enbridge Pipelines Inc.	2024	2,000	876	1,124
Enbridge Gas Inc.	2024	2,500	1,440	1,060
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.

In March 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to $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 $720 million was unutilized as at March 31, 2023. As at December 31, 2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $689 million was unutilized.

41

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

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

LONG-TERM DEBT ISSUANCES

During the three months ended March 31, 2023, we completed the following long-term debt issuances totaling US$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

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

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 40 basis points.

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

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 $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.

42

Excluding current maturities of long-term debt, as at March 31, 2023 and December 31, 2022, we had positive and negative working capital positions of $576 million and $2.1 billion, 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 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

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Operating activities	3,866	2,939
Investing activities	(1,437)	(1,318)
Financing activities	(2,289)	(1,483)
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	144	134

Significant sources and uses of cash for the three months ended March 31, 2023 and 2022 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 infrequent or other non-operating factors, as discussed 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, construction and in-service dates impacts the timing of cash requirements. The increase in cash used in investing activities period-over-period was also due to the acquisition of an additional 10.0% ownership in the Gray Oak Pipeline, partially offset by net receipts of long-term notes receivable from affiliates, in the first quarter of 2023.

Financing Activities

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

•higher net commercial paper and credit facility repayments in 2023 when compared to the same period in 2022;

•net repayments of short-term borrowings in 2023 when compared to net issuances during the same period in 2022; and

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

43

The factors above were partially offset by:

•higher long-term debt issuances in 2023 when compared to the same period in 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 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 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 March 31, 2023, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.

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

44

Enbridge Notes under Guarantees

USD Denominated1	CAD Denominated2
Floating Rate Senior Notes due 2024	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
4.250% Senior Notes due 2026	7.220% Senior Notes due 2030
1.600% Senior Notes due 2026	7.200% Senior Notes due 2032
5.969% Senior Notes due 2026	6.100% Sustainability-Linked Senior Notes due 2032
3.700% Senior Notes due 2027	3.100% Sustainability-Linked Senior Notes due 2033
3.125% Senior Notes due 2029	5.570% Senior Notes due 2035
2.500% Sustainability-Linked Senior Notes due 2033	5.750% Senior Notes due 2039
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 March 31, 2023, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$13.5 billion.

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

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

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

Summarized Combined Statement of Earnings

Three months ended March 31,	2023
(millions of Canadian dollars)
Operating income	1
Earnings	499
Earnings attributable to common shareholders	414

45

Summarized Combined Statements of Financial Position

	March 31, 2023	December 31, 2022
(millions of Canadian dollars)
Cash and cash equivalents	532	425
Accounts receivable from affiliates	2,053	2,486
Short-term loans receivable from affiliates	4,232	5,232
Other current assets	706	969
Long-term loans receivable from affiliates	45,885	43,873
Other long-term assets	3,657	4,111
Accounts payable to affiliates	1,943	1,375
Short-term loans payable to affiliates	1,261	1,745
Other current liabilities	7,354	8,752
Long-term loans payable to affiliates	37,943	37,626
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;

46

•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.

47

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

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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk is described in Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our annual report on Form 10-K for the year ended December 31, 2022. We believe our exposure to market risk has not changed materially since then.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as at 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 March 31, 2023 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

48

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I. Item 1A. Risk Factors of our annual report on Form 10-K for the year ended December 31, 2022, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors.

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

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

49

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
10.1*	+	Enbridge Inc. Directors’ Compensation Plan dated February 8, 2023 and effective January 1, 2023
10.2	+	Form of Executive Employment Agreement (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)

50

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:	May 5, 2023	By:	/s/ Gregory L. Ebel
			Gregory L. Ebel President, Chief Executive Officer and Director (Principal Executive Officer)
Date:	May 5, 2023	By:	/s/ Vern D. Yu
			Vern D. Yu Executive Vice President, Corporate Development, Chief Financial Officer and President, New Energy Technologies (Principal Financial Officer)

51

EX-10.1

Exhibit 10.1

ENBRIDGE INC.

DIRECTORS’ COMPENSATION PLAN

February 8, 2023

Effective January 1, 2023

1

ENBRIDGE INC.

DIRECTORS’ COMPENSATION PLAN

1.DEFINED TERMS

As used herein, the following terms shall have the following meanings, respectively:

“Beneficiary” means any person(s) designated by a Director as indicated on the Designation of Beneficiary Form, to receive any cash amount or Shares under this Plan in the event of the Director’s death;

“Board” means the Board of Directors of the Corporation;

“Bonus Retainer” means a direct grant of DSUs to a Director in addition to such Director’s regular retainer.

“Canadian Election Form” means the election form required to be submitted by the Canadian Taxpayers to the Corporation;

“Canadian Taxpayer” means a Director whose income is subject to Canadian federal income taxation;

“Code” means the U.S. Internal Revenue Code of 1986, as amended;

“Comparator Group” has the meaning set forth in Section 4;

“Compensation” has the meaning set forth in Section 7;

“Corporation” means Enbridge Inc., and includes any successor corporation thereto;

“Deferred Stock Unit Account” has the meaning set forth in Subsection 9(a);

“Deferred Stock Units” or “DSUs” mean units credited to a Director in accordance with Subsection 9(b);

“Designation of Beneficiary Form” means the form attached hereto as Appendix “B”;

“Director” means a director of the Corporation;

“DRS” means the Direct Registration System;

“Dual-Taxed Member” means a Director that is both a U.S. Taxpayer and a Canadian Taxpayer;

“Estate” means the estate of a deceased Director;

“Governance Committee” means the Governance Committee of the Board;

“Market Value”, as of a particular day, means the weighted average of the trading price for one (1) Share on The Toronto Stock Exchange for the five (5) Trading Days immediately preceding that day;

2

“Payment Date” means the date on which Directors would normally receive payments of Compensation;

“Plan” means this Directors’ Compensation Plan effective January 1, 2018, as the same may be amended or varied from time to time;

“Retirement Date”,in respect of a Director, means the effective date on which the Director ceases to be a Director, for any reason whatsoever;

“Share” means a common share of the Corporation;

“Trading Day” means any day, other than a Saturday or Sunday, on which The Toronto Stock Exchange is open for trading;

“Trustee” means the trustee engaged by the Corporation for purposes of facilitating the payment of Share-based Compensation in accordance with Section 8.

“U.S. Election Form” means the election form required to be submitted by U.S. Taxpayers to the Corporation; and

“U.S. Taxpayer” means a Director whose income is subject to U.S. federal income taxation.

2.PURPOSE AND OBJECTIVES

a.The purpose of this Plan is to provide a compensation system for Directors. This Plan applies only to the members of the Board and does not apply to board members of affiliate organizations or employees of the Corporation or any of its subsidiaries.

b.The objectives of this Plan are:

i.to compensate Directors commensurate with the risks, responsibilities and time commitments assumed by Board members;

ii.to attract and retain the services of the most qualified individuals to serve on the Board;

iii.to align the interests of Directors with the Corporation’s shareholders;

iv.to provide competitive levels of compensation by considering various pay components typically provided to directors; and

v.to deliver such compensation in a tax effective manner.

c.The Board provides oversight and stewardship over this Plan through the Governance Committee and has overall responsibility for determining the philosophical framework of the Directors’ compensation program.

3

3.ADMINISTRATION

The Governance Committee will administer this Plan in its discretion.The Governance Committee shall have the power to interpret the provisions of this Plan and to make regulations and formulate administrative provisions for its implementation, and to make such changes in the regulations and administrative provisions as, from time to time, the Governance Committee deems proper and in the best interests of the Corporation.Such regulations and provisions may include the delegation to any Director(s) or any officer(s) of the Corporation of such administrative duties and powers of the Governance Committee as it may see fit.

4.EXTERNAL BENCHMARKING

a.The Board supports maintaining a level of compensation for Directors that is competitive with compensation levels paid to directors of comparable public corporations; reflects the risks accompanying Board membership and the time commitments and responsibilities required of Directors, committee members and Board or Committee Chairs; and reflects the size and complexity of the Corporation’s business.

b.The Governance Committee will, from time to time, with the assistance of qualified external experts in the area of compensation benchmarking, review and determine the appropriate comparable public corporations against which comparisons are made (the “Comparator Group”) with the intention that such Comparator Group be consistent with the periodic evaluation of executive management compensation.

c.To the extent possible and appropriate, the Governance Committee shall align the Comparator Group with the group used to benchmark executive management compensation practices as approved by the Human Resources & Compensation Committee (refer to Enbridge Inc. senior management compensation policy Compensation Comparators).

5.COMMUNICATION

The Board recognizes that Compensation is an important component of corporate governance and is committed to ensuring that the material terms of the compensation program are properly disclosed to shareholders and regulators.

4

6.APPLICATION

This Plan applies to each individual while serving as a Director and, subject to Subsections 10(c), (d), (e), (f) and 11(a) (ii) and (iii), (c), (d) and (e), shall cease to apply on the Director’s Retirement Date.

7.DIRECTORS’ COMPENSATION

a.General

The Board, on the recommendation of the Governance Committee, shall determine from time to time the amount of compensation to be paid to Directors (the “Compensation”) including, without limitation, amounts in respect of retainers (including the retainer for the Chair of the Corporation and Chairs of committees of the Board), Board meeting and committee meeting attendance fees, and any other amounts which the Board in its discretion considers to be appropriate. In addition, the Board shall determine the amount of expenses, if any, for which the Directors will be reimbursed.

b.Fee Structure and Payment Particulars

i.Compensation will be made on the basis of a flat fee structure that incorporates all Board, committee, and Chair retainers as determined by the Board. The Board’s policy is to target flat fee levels at the 50th percentile of total compensation levels paid to directors of the Comparator Group (as defined in Section 4).

ii.As of April 1, 2021, Compensation shall be as set out in Appendix “A”.Changes to Appendix “A” may be made by the Board following a recommendation of or consultation with the Governance Committee.Upon any such change being approved by the Board, a new Appendix “A” incorporating the changes and effective as of the date established by the Board shall be attached to the Plan and become Appendix “A” for all purposes of the Plan.

iii.Compensation is paid quarterly, in arrears.All Directors, regardless of country of residency, shall be paid in US dollars.

iv.A percentage of the Compensation may be withheld in cases where a Director’s attendance at Board meetings or Committee meetings or both, falls below the established minimum. The Governance Committee will

5

review the continuation of the Director on the Board if an inordinate number of meetings are missed.

v.At any time, the Board, on the recommendation of the Governance Committee, may grant to Directors a Bonus Retainer in the form of a direct grant of DSUs. For U.S. Taxpayers only, DSUs comprising a Bonus Retainer shall be payable on December 31 of the year following the year of the Director’s Retirement Date and no U.S. Taxpayer shall be permitted to elect the form or timing of payment of any portion of a Bonus Retainer.

c.Forms of Payment

The Board, on the recommendation of the Governance Committee, shall determine the portion(s), if any, of the Compensation that a Director may elect to receive by way of cash, Shares or Deferred Stock Units. Until revised by the Board, each Director and Chair of the Board will, subject to requirements of minimum share ownership criteria, as set out in Appendix “A”, elect to receive Compensation as cash, Shares or Deferred Stock Units, in whole or in part, in increments of 5% (totalling 100% of the Compensation payable to such Director).

8.COMPENSATION - SHARES

a.In respect of any amount of Compensation payable to a Director in Shares, funds sufficient for the purchase in the open market of such Shares shall be paid to the Trustee by the Corporation in trust for such Director from time to time, and shall be applied by the Trustee to the purchase of Shares, in the open market on a stock exchange, for that Director.

b.The Shares to which a Director becomes entitled hereunder shall be calculated on the basis of the Market Value thereof two (2) weeks prior to the Payment Date.

c.The Trustee shall cause such Shares to be registered in the name of the Director and held in electronic book-entry form through the DRS.

d.The Trustee shall cause the transfer agent to provide (i) a Direct Registration (DRS) Advice to each Director promptly after each purchase of Shares on such Director’s behalf, which will set out the number of Shares so purchased and the aggregate number of Shares held by such Director in the DRS, and (ii) a Direct Registration (DRS) Statement to each such Director annually.In addition, the

6

Trustee shall promptly provide any other information required by the Director for tax reporting purposes.

9.COMPENSATION - DEFERRED STOCK UNITS

a.Deferred Stock Unit Account

An account, to be known as a “Deferred Stock Unit Account”, shall be maintained by the Corporation for each Director and will show the number of Deferred Stock Units credited to a Director, to four (4) decimal places, from time to time.

b.Crediting Deferred Stock Unit Account

In respect of any amount of Compensation payable to a Director in Deferred Stock Units, the number of Deferred Stock Units to be credited to that Director will be calculated by dividing the dollar amount of the quarterly Compensation payable to that Director in Deferred Stock Units on the Payment Date by the Market Value two (2) weeks prior to such date.

c.Additional Deferred Stock Units From Dividends On Shares

In addition to Subsection 9(b), whenever any cash dividend or other cash distribution is paid on the Shares, additional Deferred Stock Units will be credited to the Director’s Deferred Stock Unit Account.The number of such additional Deferred Stock Units will be calculated by dividing the aggregate dividends that would have been paid to such Director if the Deferred Stock Units in the Director’s Deferred Stock Unit Account had been Shares, by the Market Value of a Share on the date on which the dividends are paid on the Shares, less the amount of any discount then in effect for the reinvestment of dividends under the Corporation’s Dividend Reinvestment and Share Purchase Plan.

10.CANADIAN TAXPAYER - DEFERRED STOCK UNITS

This Section 10 only applies to Canadian Taxpayers:

a.Choice of Compensation Mix

i.The Directors shall elect on or before December 31 of the preceding year in which Compensation will be earned, the portion of such Compensation, excluding any Bonus Retainer, to be received by the Director in cash, Shares or Deferred Stock Units in respect of that calendar year, and, failing such election, the Director shall, subject to any minimum amounts

7

of cash, Shares or Deferred Stock Units as set out in Appendix “A”, be deemed to have elected 100% in cash.

ii.Where a Director joins the Board after January 1 in any year, such Director shall make his or her compensation mix election within thirty (30) days of his or her election or appointment to the Board.

iii.In all cases, the Directors’ elections shall be irrevocable and shall remain in force from the date of such election until the date of the next election.

b.Canadian Election Form

Each Director shall fill out a Canadian Election Form indicating their elected compensation mix and deliver such Canadian Election Form to the Corporation on the dates set out above.

c.Elected Payment Date – Canadian Taxpayer

Except as provided in Subsection 10(e), the determined value of the Deferred Stock Units credited to the Deferred Stock Unit Account of a Director whose income is subject to Canadian income tax, net of required withholdings, shall be paid to that Director on a date to be agreed upon by that Director and the Corporation, provided that the payment date must be a date subsequent to the Retirement Date and may be no later than December 31 of the first calendar year commencing after that Retirement Date.

d.No Election Default

If no such payment date agreement is reached, pursuant to Subsection 10(c), the payment date will be December 31 of the first calendar year commencing after that Director’s Retirement Date.

e.Payment on Death of a Canadian Taxpayer

i.When a Director dies, the value of the Deferred Stock Units credited to that Director’s Deferred Stock Unit Account, net of applicable withholdings, shall be paid to his or her Beneficiary as soon as practicable after the Director’s death, provided that the payment shall be made no later than December 31 of the first calendar year commencing after that Director’s Retirement Date.

ii.Notwithstanding the above, if the Beneficiary of the deceased Director has not been determined within sixty (60) days after the Director’s death, the Corporation shall make such payment to the Estate.

8

f.Determining Value for Canadian Taxpayers

To determine the value of Deferred Stock Units for the purposes of a payment to a Director (or, where the Director has died, his or her Beneficiary or Estate, as the case may be) under Subsections 10(c), (d) or (e), a Deferred Stock Unit will be valued equal to the Market Value multiplied by the number of Deferred Stock Units (including fractional Units) credited to a Director’s Deferred Stock Unit Account on the following basis:

i.for Subsections 10 (c) and (d), the Market Value on the third (3rd) Trading Day before the elected payment date; and

ii.for Subsection 10(e), the Market Value on the next Trading Day after the Director’s death.

g.Effect of Reorganization of the Corporation for Canadian Taxpayers

In the event of any merger, consolidation or other reorganization of the Corporation in which the Corporation is not the surviving or continuing corporation, all Deferred Stock Units granted hereunder and outstanding on the date of such reorganization shall be assumed by the surviving or continuing corporation.If, in the event of any such merger, consolidation or other reorganization, provision for such assumption satisfactory to an owner of a Deferred Stock Unit granted under this Plan is not made by the surviving or continuing corporation, such owner shall have distributed to him or her within sixty (60) days after the reorganization, in full satisfaction, cash in payment of the Market Value on the Trading Day immediately preceding the day of such reorganization.

11.US TAXPAYER- DEFERRED STOCK UNITS

This Section 11 only applies to U.S. Taxpayers:

a.Choice of Compensation Mix and Election Payment Date

Directors shall elect on or before December 31 of the calendar year immediately preceding the calendar year in which Compensation will be earned:

i.the portion of such Compensation, excluding any Bonus Retainer, to be received by those Directors in cash, Shares or Deferred Stock Units in respect of that calendar year. If no election is made the Director shall, subject to any minimum amounts of cash, Shares or Deferred Stock Units as set out in Appendix “A”, be deemed to have elected 100% in cash;

9

ii.the date, to be agreed upon by each of the Directors and the Corporation for payment of such Director’s Deferred Stock Unit Account where such date may be any date after that Director’s Retirement Date, provided that the payment date is after that Retirement Date and no later than December 31 of the first calendar year commencing after that Retirement Date. If no such payment date is determined, the Corporation, at its sole discretion, shall pay the amount owing from Director’s Deferred Stock Unit Account within ninety (90) days following that Director’s Retirement Date;

iii.where a Director joins the Board after January 1 in any year, such Director shall make his or her election for both compensation mix and payment date within thirty (30) days of his or her election or appointment to the Board; and

iv.in all cases, the Directors’ elections shall be irrevocable and shall remain in force from the date of such election until the Director’s Retirement Date.

b.U.S. Election Form

Each Director shall fill out a U.S. Election Form indicating their elected compensation mix and payment date of their Deferred Stock Unit Account and deliver such U.S. Election Form to the Corporation. Such form shall be irrevocable.

c.Specified Employee

Notwithstanding Subsection 11 (a), if the payment of a Director’s Deferred Stock Unit Account would be subject to taxation or penalties under Code Section 409A because the timing of such payment is not delayed as provided in Section 409A for a “specified employee,” then if the Director is (1) a U.S. Taxpayer and (2) a “specified employee” under Code Section 409A, any payment which that Director would otherwise be entitled to receive during the six (6) month period following the Director’s Retirement Date shall be delayed and paid within fifteen (15) days after the date that is six (6) months following the Director’s Retirement Date, or such earlier date upon which such amount can be paid under Code Section 409A without being subject to such taxation, such as upon that Director’s death.

10

d.Payment on Death of a U.S. Taxpayer

i.When a Director dies, the value of the Deferred Stock Unit Account, credited to that Director’s Deferred Stock Unit Account, net of applicable withholdings, shall be paid to his or her Beneficiary not later than by the later of (i) the end of the calendar year of the Director’s Retirement Date, or (ii) ninety (90) days following that Director’s date of death, provided that the Beneficiary shall not be permitted to designate the taxable year in which such payment is made.

ii.Notwithstanding the above, if the Beneficiary of the deceased Director has not been determined within sixty (60) days after the Director’s death, the Corporation shall make such payment to the Estate.

e.Determining Value for U.S. Taxpayers

i.To determine the value of Deferred Stock Units for the purposes of a payment to a Director (or, where the Director has died, his or her Beneficiary or Estate, as the case may be) under Subsections 11(a)(ii), (iii), (c) or (d), a Deferred Stock Unit will be valued equal to the Market Value multiplied by the number of Deferred Stock Units (including fractional Units) credited to a Director’s Deferred Stock Unit Account on the following basis:

(i)for Subsections 11(a)(ii),(iii) and (c), the Market Value on the third (3rd) Trading Day before the elected payment date; and

(ii) for Subsection 11(d), the Market Value on the next Trading Day after the Director’s death.

f.Dual-Taxed Members

In the event that a Director is both a U.S. Taxpayer and a Canadian Taxpayer at the time that the Director’s Deferred Stock Units become payable, the provisions of this Section 11(f) shall apply:

i.If the Director has made a valid election under Section 11(a) and (b) with regard to payment of the Director’s Deferred Stock Units, payment of such Director’s Deferred Stock Unit Account shall be made in accordance such election, subject to Section 11(c).

11

ii.If the Director has not made a valid election under Section 11(a) and (b) with regard to payment of the Director’s Deferred Stock Units, payment of such Director’s Deferred Stock Unit Account shall be made as of a date determined by the Corporation in its discretion, with such payment date to be within ninety (90) days following the Director’s Retirement Date, subject to the following:

(i) If the ninety (90) day period begins in one calendar year and ends in the following calendar year, the payment date within such 90-day period shall be determined in the sole discretion of the Corporation, and the Director shall not be permitted to make a payment election under Section 10(c) and (d) of the Plan that applies for a Canadian Taxpayer; or

(ii) If the ninety (90) day period begins and ends in the same calendar year, the Director shall be permitted to make a payment election under Section 10(c) and (d) of the Plan, but the payment date elected by the Director must fall within the 90-day period following the Director’s Retirement Date

g.Code Section 409A Compliance

With respect to any Director who is a U.S. Taxpayer, the Corporation intends that this Plan shall comply with the applicable provisions of Code Section 409A, or an exemption from the application of Code Section 409A, in order to prevent the inclusion in the gross income of such Director of any deferred amount in a taxable year that is prior to the taxable year in which such amount would otherwise be distributed or made available to such Director under the terms of this Plan.This Plan shall be construed, interpreted and administered in a manner consistent with such intent.In furtherance of this intent, to the extent that any term of this Plan is ambiguous, such term shall be interpreted to comply with Code Section 409A, or an exemption from the application of Code Section 409A, as determined by the Corporation.

h.Effect of Reorganization of the Corporation for U.S. Taxpayers and Dual-Taxed Members

12

In the event of any merger, consolidation or other reorganization of the Corporation where the surviving or continuing corporation does not assume all of the Director’s Deferred Stock Units that are outstanding on the date of such reorganization, and such event constitutes a “change in control” of the Corporation within the meaning of Code Section 409A, then the surviving or continuing corporation shall distribute to the Director, within sixty (60) days after the closing date of such event, in complete satisfaction of all the rights of the Director under this Plan, cash in full payment of the Market Value of the Director’s Deferred Stock Units as valued as of the Trading Day immediately preceding the closing date of such event. In the event that the Director is a Dual-Taxed Member, this Section 11(h) shall apply and Section 10(g) shall be inapplicable

12.BROKERAGE COMMISSIONS

All brokerage commissions and other transaction costs in respect of Share purchases made under Section 8 of this Plan shall be paid by the Corporation.

13.TAXES AND REPORTING

a.The Corporation shall deduct from all amounts otherwise payable to a Director (or Beneficiary or Estate, as the case may be) all amounts, including applicable taxes, that are required by law to be withheld with respect to the amount otherwise payable.

b.Notwithstanding anything else contained herein, each Director who participates in this Plan shall be responsible for:

i.the payment of all applicable taxes including, but not limited to, income taxes payable in connection with the acquisition, holding and delivery of Shares for or to a Director pursuant to this Plan and the payment of the value of the Deferred Stock Units, subject to deduction and remittance by the Corporation of applicable withholding taxes; and

ii.compliance with the continuous disclosure requirements of the applicable securities commissions or similar regulatory authorities in Canada and those exchanges upon which the Corporation’s Shares are traded, including, but not limited to, the preparation and filing of insider trading reports respecting the acquisition of Shares pursuant to this Plan, and the Corporation, its employees and agents shall bear no liability in connection

13

with the payment of such taxes or the compliance with such disclosure requirements.

14.DILUTION ADJUSTMENTS

In the event that the outstanding Shares of the Corporation shall be increased or decreased, or changed into, or exchanged for a different number or kind of shares or other securities of the Corporation or another corporation, whether through a stock dividend, stock split, consolidation, recapitalization, amalgamation, reorganization, arrangement or other transaction, the Governance Committee or the Board may make appropriate adjustments to the number or kind of shares or securities upon which Deferred Stock Units are based under this Plan, and as regards Deferred Stock Units previously granted or to be granted pursuant to this Plan, in the number or kind of shares or securities upon which Deferred Stock Units are based and the purchase price therefor.

15.OPERATION OF RIGHTS PLAN

The appropriate adjustments in the number of Deferred Stock Units may be made by the Board in its discretion in order to give effect to the adjustments in the number of Shares of the Corporation resulting from the implementation and operation of the Shareholder Rights Plan Agreement originally dated as of November 9, 1995 and as amended from time to time.

16.AMENDMENTS, ETC.

Subject to applicable regulatory approval, the Board may revise, suspend or discontinue this Plan in whole or in part.No such revision, suspension, or discontinuance shall alter or impair the rights of a Director in respect of Deferred Stock Units or Shares previously granted or received under this Plan, without the consent of that Director.

17.PERIODIC REVIEW

The compensation available, and competitiveness of this Plan relative to the Comparator Group, will be reviewed:

a.by external consultants every second year, commencing in 2015; and

b.by internal management every second year, commencing in 2014.

14

18.EFFECTIVE DATE

This Plan is effective as of April 1, 2021, and may be amended from time to time.Commencing April 1, 2021, no new Shares or Deferred Stock Units shall be granted or received under any previous “Directors’ Compensation Plan” for Enbridge Inc.Any Shares or Deferred Stock Units previously granted or received under such previous compensation plans shall continue without alteration, including any previous elected payment date made by a Director, or impairment of the rights of a Director with respect to such Compensation.

APPENDIX “A”

to the Directors’ Compensation Plan

Retainer and Fees

1.Flat Fee Schedule

The following table establishes the annual fee schedule for Directors and is effective as of April 1, 2021.

15

.

16

		Elective Payment Form1
Compensation Elements	Annual Fee2	Before minimum share ownership			After minimum share ownership
		Cash	Shares	DSUs	Cash3	Shares3	DSUs3
Board Retainer	$300,000	Up to 50%	Up to 50%	50% to 100%	Up to 65%	Up to 65%	35% to 100%
Additional Board Chair Retainer	$265,000
Additional Committee Chair Retainer: AFRC HRCC S&R GC CSR	$25,000 $20,000 $15,000 $20,000 $15,000

1. Directors may elect the form of payment in increments of 5% up to the percentage amounts specified in the table.

2. All fees in U.S. dollars.

2.Penalty for Non-Attendance

At the end of each year, the Governance Committee will review the record of attendance of Directors at Committee meetings and Board meetings.The Chair of the Governance Committee along with the Board Chair, at their discretion, will recommend to the Board appropriate penalties for non-attendance by Directors at Committee and Board meetings.

3.Travel Fees

A per diem allowance of $1,500 U.S. shall be paid in cash to Directors who travel from their home state or province to a meeting in another state or province.

17

4.Share Ownership Requirement

Effective January 1, 2016, Directors shall hold a personal investment in Shares and Deferred Stock Units of at least three (3) times the amount of the annual Board Retainer, expressed in Canadian currency[1]and be required to achieve such investment within five (5) years of joining the Board.

[1]U.S. Currency for those Directors paid in U.S. funds.

18

APPENDIX “B”

to the Directors’ Compensation Plan

DESIGNATION OF BENEFICIARY FORM

I, _____________________________________ (Director’s Name) for the purposes of

designating a Beneficiary pursuant to the Directors’ Compensation Plan of Enbridge Inc.

hereby designate _______________________ (insert name of Beneficiary (ies)) as my

Beneficiary of the Compensation owed to me by the Corporation.

At my own discretion, I make an additional designation should my Beneficiary not survive me.

I designate as my contingent Beneficiary _________________________________ (insert

name of contingent Beneficiary) of the Compensation owed to me by the Corporation.

I make this designation on the _____ day of _______, 20____.

________________________

Signature

________________________

Print Name

Instructions:

This Designation of Beneficiary Form should be completed, signed and delivered to Enbridge Inc. as soon as possible once you have been appointed to the Board of the Corporation. Any changes to the above will require the delivery of an amended form.

In the event that you would like to name a contingent beneficiary, should your primary beneficiary not survive you, please indicate above, a contingent beneficiary.

For questions regarding your Plan or Form, please call Karen Uehara at (587)955-2986.

For delivery to Enbridge Inc., please fax your Form to (403) 231-5929.

EX-22.1

Exhibit 22.1

Subsidiary Guarantors

As of March 31, 2023, each of the following subsidiaries of Enbridge Inc. (“Enbridge”), both of which are indirect, wholly-owned subsidiaries of Enbridge, has fully and unconditionally guaranteed on an unsecured, joint and several basis, each of the registered debt securities of the Company listed below:

Subsidiary Guarantors

1.Spectra Energy Partners, LP, a Delaware limited partnership

2.Enbridge Energy Partners, L.P., a Delaware limited partnership

Registered Debt Securities of Enbridge Guaranteed by each of the Subsidiary Guarantors

1.0.550% Senior Notes due 2023

2.4.000% Senior Notes due 2023

3.Floating Rate Senior Notes due 2024

4.3.500% Senior Notes due 2024

5.2.150% Senior Notes due 2024

6.2.500% Senior Notes due 2025

7.2.500% Senior Notes due 2025

8.4.250% Senior Notes due 2026

9.1.600% Senior Notes due 2026

10.5.969% Senior Notes due 2026

11.3.700% Senior Notes due 2027

12.3.125% Senior Notes due 2029

13.2.500% Sustainability-Linked Senior Notes due 2033

14.5.700% Sustainability-Linked Senior Notes due 2033

15.4.500% Senior Notes due 2044

16.5.500% Senior Notes due 2046

17.4.000% Senior Notes due 2049

18.3.400% Senior Notes due 2051

EX-31.1

EXHIBIT 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Gregory L. Ebel, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Enbridge Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.    Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.    Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 5, 2023	By:	/s/ Gregory L. Ebel
			Gregory L. Ebel
			President and Chief Executive Officer (Principal Executive Officer) Enbridge Inc.

EX-31.2

EXHIBIT 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Vern D. Yu, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Enbridge Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.    Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.    Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.     Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

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

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Enbridge Inc. on Form 10-Q for the period ending March 31, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gregory L. Ebel, President and Chief Executive Officer of Enbridge Inc., certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

1.The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Enbridge Inc.

Date:	May 5, 2023	By:	/s/ Gregory L. Ebel
			Gregory L. Ebel
			President and Chief Executive Officer (Principal Executive Officer) Enbridge Inc.

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Enbridge Inc. on Form 10-Q for the period ending March 31, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Vern D. Yu, Executive Vice President, Corporate Development, Chief Financial Officer and President, New Energy Technologies of Enbridge Inc., certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

1.The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Enbridge Inc.

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

XML

COVER - shares	3 Months Ended
	Mar. 31, 2023	Apr. 28, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2023
Document Transition Report	false
Entity File Number	001-15254
Entity Registrant Name	ENBRIDGE INC.
Entity Incorporation, State or Country Code	Z4
Entity Tax Identification Number	98-0377957
Entity Address, Address Line One	200, 425 - 1st Street S.W.
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Country	CA
Entity Address, Postal Zip Code	T2P 3L8
City Area Code	403
Local Phone Number	231-3900
Title of 12(b) Security	Common Shares
Trading Symbol	ENB
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		2,024,676,423
Entity Central Index Key	0000895728
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q1

XML

CONSOLIDATED STATEMENTS OF EARNINGS - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Operating revenues
Total operating revenues	$ 12,075	$ 15,097
Operating expenses
Operating and administrative	2,037	1,875
Depreciation and amortization	1,146	1,055
Total operating expenses	9,413	12,677
Operating income	2,662	2,420
Income from equity investments	517	491
Other income	102	458
Interest expense	(905)	(719)
Earnings before income taxes	2,376	2,650
Income tax expense	(510)	(593)
Earnings	1,866	2,057
Earnings attributable to noncontrolling interests	(49)	(28)
Earnings attributable to controlling interests	1,817	2,029
Preference share dividends	(84)	(102)
Earnings attributable to common shareholders	$ 1,733	$ 1,927
Earnings per common share attributable to common shareholders (in Canadian dollars per share)	$ 0.86	$ 0.95
Diluted earnings per common share attributable to common shareholders (in Canadian dollars per share)	$ 0.85	$ 0.95
Commodity sales
Operating revenues
Total operating revenues	$ 4,783	$ 8,325
Operating expenses
Commodity costs and Gas distribution costs	4,636	8,291
Gas distribution sales
Operating revenues
Total operating revenues	2,279	2,098
Operating expenses
Commodity costs and Gas distribution costs	1,594	1,456
Transportation and other services
Operating revenues
Total operating revenues	$ 5,013	$ 4,674

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Statement of Comprehensive Income [Abstract]
Earnings	$ 1,866	$ 2,057
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	(45)	294
Change in unrealized gain on net investment hedges	15	133
Excluded components of fair value hedges	7	(1)
Reclassification to earnings of loss on cash flow hedges	7	57
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(4)	(2)
Foreign currency translation adjustments	(59)	(708)
Other comprehensive loss, net of tax	(79)	(227)
Comprehensive income	1,787	1,830
Comprehensive income attributable to noncontrolling interests	(64)	(13)
Comprehensive income attributable to controlling interests	1,723	1,817
Preference share dividends	(84)	(102)
Comprehensive income attributable to common shareholders	$ 1,639	$ 1,715

XML

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - CAD ($) $ in Millions	Total	Preference shares	Common shares	Additional paid-in capital	Deficit	Accumulated other comprehensive income (loss)	Total Enbridge Inc. shareholders’ equity	Noncontrolling interests
Balance at the beginning of the period at Dec. 31, 2021		$ 7,747	$ 64,799	$ 365	$ (10,989)	$ (1,096)		$ 2,542
Increase (Decrease) in Stockholders' Equity
Redemption of preference shares		(737)
Options exercised			36	(34)
Shares issued on vesting of restricted stock units (RSU)			0
Share purchases at stated value			(30)
Other			(4)	(28)
Stock-based compensation				13
Earnings attributable to controlling interests	$ 2,029				2,029
Preference share dividends					(102)
Share purchases in excess of stated value					(20)
Other								35
Other comprehensive loss attributable to common shareholders, net of tax						(212)
Earnings attributable to noncontrolling interests								28
Change in unrealized gain on cash flow hedges								2
Foreign currency translation adjustments								(17)
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax								(15)
Comprehensive income attributable to noncontrolling interests	(13)							13
Distributions								(60)
Contributions								6
Balance at the end of the period at Mar. 31, 2022	$ 64,273	7,010	64,801	316	(9,082)	(1,308)	$ 61,737	2,536
Increase (Decrease) in Stockholders' Equity
Common stock, dividends per share, paid (in dollars per share)	$ 0.860
Balance at the beginning of the period at Dec. 31, 2022	$ 63,398	6,818	64,760	275	(15,486)	3,520		3,511
Increase (Decrease) in Stockholders' Equity
Redemption of preference shares		0
Options exercised			2	(1)
Shares issued on vesting of restricted stock units (RSU)			12
Share purchases at stated value			0
Other			0	0
Stock-based compensation				0
Earnings attributable to controlling interests	1,817				1,817
Preference share dividends					(84)
Share purchases in excess of stated value					0
Other								(1)
Other comprehensive loss attributable to common shareholders, net of tax						(94)
Earnings attributable to noncontrolling interests								49
Change in unrealized gain on cash flow hedges								17
Foreign currency translation adjustments								(2)
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax								15
Comprehensive income attributable to noncontrolling interests	(64)							64
Distributions								(92)
Contributions								4
Balance at the end of the period at Mar. 31, 2023	$ 65,025	$ 6,818	$ 64,774	$ 274	$ (13,753)	$ 3,426	$ 61,539	$ 3,486
Increase (Decrease) in Stockholders' Equity
Common stock, dividends per share, paid (in dollars per share)	$ 0.888

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Operating activities
Earnings	$ 1,866	$ 2,057
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	1,146	1,055
Deferred income tax expense	484	423
Unrealized derivative fair value loss, net	(520)	(369)
Income from equity investments	(517)	(491)
Distributions from equity investments	453	394
Other	40	47
Changes in operating assets and liabilities	914	(177)
Net cash provided by operating activities	3,866	2,939
Investing activities
Capital expenditures	(1,129)	(1,048)
Long-term investments and restricted long-term investments	(413)	(314)
Distributions from equity investments in excess of cumulative earnings	100	97
Additions to intangible assets	(66)	(53)
Affiliate loans, net	71	0
Net cash used in investing activities	(1,437)	(1,318)
Financing activities
Net change in short-term borrowings	(559)	89
Net change in commercial paper and credit facility draws	(2,921)	(283)
Debenture and term note issues, net of issue costs	4,111	2,643
Debenture and term note repayments	(968)	(1,155)
Contributions from noncontrolling interests	4	6
Distributions to noncontrolling interests	(92)	(60)
Common shares issued	0	2
Common shares repurchased	0	(50)
Preference share dividends	(84)	(91)
Common share dividends	(1,798)	(1,742)
Redemption of preference shares	0	(750)
Affiliate loans, net	51	0
Other	(33)	(92)
Net cash used in financing activities	(2,289)	(1,483)
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	144	134
Cash and cash equivalents and restricted cash at beginning of period	907	320
Cash and cash equivalents and restricted cash at end of period	$ 1,051	$ 454

XML

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 976	$ 861
Restricted cash	75	46
Trade receivables and unbilled revenues	4,755	5,616
Other current assets	2,701	3,255
Accounts receivable from affiliates	100	114
Inventory	1,311	2,255
Current assets	9,918	12,147
Property, plant and equipment, net	104,251	104,460
Long-term investments	16,320	15,936
Restricted long-term investments	646	593
Deferred amounts and other assets	9,148	9,542
Intangible assets, net	3,913	4,018
Goodwill	32,411	32,440
Deferred income taxes	463	472
Total assets	177,070	179,608
Current liabilities
Short-term borrowings	1,437	1,996
Trade payables and accrued liabilities	4,098	6,172
Other current liabilities	3,051	5,220
Accounts payable to affiliates	47	105
Interest payable	709	763
Current portion of long-term debt	7,436	6,045
Current liabilities	16,778	20,301
Long-term debt	71,740	72,939
Other long-term liabilities	9,235	9,189
Deferred income taxes	14,292	13,781
Total liabilities	112,045	116,210
Contingencies
Share capital
Preference shares	6,818	6,818
Common shares (2,025 outstanding at March 31, 2023 and December 31, 2022)	64,774	64,760
Additional paid-in capital	274	275
Deficit	(13,753)	(15,486)
Accumulated other comprehensive income	3,426	3,520
Total Enbridge Inc. shareholders’ equity	61,539	59,887
Noncontrolling interests	3,486	3,511
Equity	65,025	63,398
Total liabilities and equity	$ 177,070	$ 179,608

XML

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Mar. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	2,025	2,025

XML

BASIS OF PRESENTATION

3 Months Ended

Mar. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

BASIS OF PRESENTATION

BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by US GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2022. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our audited consolidated financial statements for the year ended December 31, 2022. Amounts are stated in Canadian dollars unless otherwise noted.

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

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

XML

REVENUES

3 Months Ended

Mar. 31, 2023

Revenue from Contract with Customer [Abstract]

REVENUES

REVENUES

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Three months ended March 31, 2023
(millions of Canadian dollars)
Transportation revenue	2,942	1,384	276	—	—	—	4,602
Storage and other revenue	64	95	99	—	—	—	258
Gas distribution revenue	—	—	2,287	—	—	—	2,287
Electricity revenue	—	—	—	66	—	—	66
Total revenue from contracts with customers	3,006	1,479	2,662	66	—	—	7,213
Commodity sales	—	—	—	—	4,783	—	4,783
Other revenue1,2	30	11	(40)	78	—	—	79
Intersegment revenue	129	1	3	—	18	(151)	—
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 March 31, 2022
(millions of Canadian dollars)
Transportation revenue	2,685	1,194	251	—	—	—	4,130
Storage and other revenue	51	84	47	—	—	—	182
Gas gathering and processing revenue	—	15	—	—	—	—	15
Gas distribution revenue	—	—	2,098	—	—	—	2,098
Electricity revenue	—	—	—	62	—	—	62
Total revenue from contracts with customers	2,736	1,293	2,396	62	—	—	6,487
Commodity sales	—	—	—	—	8,325	—	8,325
Other revenue1,2	178	7	4	94	2	—	285
Intersegment revenue	141	—	11	—	10	(162)	—
Total revenue	3,055	1,300	2,411	156	8,337	(162)	15,097

1Includes realized and unrealized gains and losses from our hedging program which for the three months ended March 31, 2023 were a net $55 million loss (2022 - $94 million gain).

2 Includes revenues from lease contracts for the three months ended March 31, 2023 and 2022 of $144 million and $164 million, respectively.

We disaggregate 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.

Contract Balances

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

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the three months ended March 31, 2023 included in contract liabilities at the beginning of the period was $36 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the three months ended March 31, 2023 were $124 million.

Performance Obligations

There was no material revenue recognized in the three months ended March 31, 2023 from performance obligations satisfied in previous periods.

Revenue to be Recognized from Unfulfilled Performance Obligations

Total revenue from performance obligations expected to be fulfilled in future periods is $60.0 billion, of which $6.0 billion and $6.7 billion are expected to be recognized during the remaining nine months ending December 31, 2023 and the year ending December 31, 2024, respectively.

The revenues excluded from the amounts above, based on optional exemptions available under Accounting Standards Codification (ASC) 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for 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 months ended 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, interim toll revenue recognized during the three months ended 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 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 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.

XML

SEGMENTED INFORMATION

3 Months Ended

Mar. 31, 2023

Segment Reporting [Abstract]

SEGMENTED INFORMATION

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.

XML

EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

3 Months Ended

Mar. 31, 2023

Earnings Per Share [Abstract]

EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

BASIC

Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding.

DILUTED

The treasury stock method is used to determine the dilutive impact of stock options and RSUs. This method assumes any proceeds from the exercise of stock options and vesting of RSUs would be used to purchase common shares at the average market price during the period.

Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:

	Three months ended March 31,
	2023	2022
(number of shares in millions)
Weighted average shares outstanding	2,025	2,026
Effect of dilutive options and RSUs	3	3
Diluted weighted average shares outstanding	2,028	2,029

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

DIVIDENDS PER SHARE

On May 2, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on June 1, 2023 to shareholders of record on May 15, 2023.

	Dividend per share
Common Shares1	$0.88750
Preference Shares, Series A	$0.34375
Preference Shares, Series B	$0.32513
Preference Shares, Series D2	$0.33825
Preference Shares, Series F	$0.29306
Preference Shares, Series H	$0.27350
Preference Shares, Series L	US$0.36612
Preference Shares, Series N	$0.31788
Preference Shares, Series P	$0.27369
Preference Shares, Series R	$0.25456
Preference Shares, Series 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	$0.38825

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

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

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

XML

DEBT

3 Months Ended

Mar. 31, 2023

Debt Disclosure [Abstract]

DEBT

DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at March 31, 2023:

	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2023-2027	9,623	7,053	2,570
Enbridge (U.S.) Inc.	2024-2027	8,594	1,702	6,892
Enbridge Pipelines Inc.	2024	2,000	876	1,124
Enbridge Gas Inc.	2024	2,500	1,440	1,060
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.

In March 2023, Enbridge Gas Inc. (Enbridge Gas) increased its 364-day extendible credit facility from $2.0 billion to $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 $720 million was unutilized as at March 31, 2023. As at December 31, 2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $689 million was unutilized.

Our credit facilities 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 March 31, 2023 and December 31, 2022, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $9.0 billion and $10.5 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.

LONG-TERM DEBT ISSUANCES

During the three months ended March 31, 2023, we completed the following long-term debt issuances totaling US$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

1The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on September 8, 2031, the interest rate will be set to equal 5.70% plus 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 40 basis points.

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

SUBORDINATED TERM NOTES

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

FAIR VALUE ADJUSTMENT

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

During the three months ended 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.

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 March 31, 2023, we were in compliance with all covenant provisions.

XML

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

3 Months Ended

Mar. 31, 2023

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to our common shareholders for the three months ended March 31, 2023 and 2022 are as follows:

	Cash Flow Hedges	Excluded Components of Fair Value Hedges	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees	Pension and OPEB Adjustment	Total
(millions of Canadian dollars)
Balance as at January 1, 2023	121	(35)	(1,137)	4,348	5	218	3,520
Other comprehensive income/(loss) retained in AOCI	(90)	7	15	(57)	—	—	(125)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	8	—	—	—	—	—	8
Other contracts2	1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(5)	(5)
	(81)	7	15	(57)	—	(5)	(121)
Tax impact
Income tax on amounts retained in AOCI	28	—	—	—	—	—	28
Income tax on amounts reclassified to earnings	(2)	—	—	—	—	1	(1)
	26	—	—	—	—	1	27
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
(millions of Canadian dollars)
Balance as at January 1, 2022	(897)	—	(166)	56	(5)	(84)	(1,096)
Other comprehensive income/(loss) retained in AOCI	384	(1)	133	(691)	—	—	(175)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	76	—	—	—	—	—	76
Foreign exchange contracts4	(4)	—	—	—	—	—	(4)
Other contracts2	2	—	—	—	—	—	2
Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(3)	(3)
	458	(1)	133	(691)	—	(3)	(104)
Tax impact
Income tax on amounts retained in AOCI	(92)	—	—	—	—	—	(92)
Income tax on amounts reclassified to earnings	(17)	—	—	—	—	1	(16)
	(109)	—	—	—	—	1	(108)
Balance as at March 31, 2022	(548)	(1)	(33)	(635)	(5)	(86)	(1,308)

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

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

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

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

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

3 Months Ended

Mar. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

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

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

Foreign Exchange Risk

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

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

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' approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps. These hedges have an average fixed rate of 4.1%.

On March 8, 2023, we issued US$700 million three-year fixed rate 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 similar right to cancel the swap after the first year. This swap has a fixed rate of 6.0%. This instrument is our only pay floating-receive fixed interest rate 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 forecasted term debt issuances via the execution of floating-to-fixed interest rate swaps with an average swap rate of 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 outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, RSUs. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

TOTAL DERIVATIVE INSTRUMENTS

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

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

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)
Other current assets
Foreign exchange contracts	—	68	54	122	(13)	109
Interest rate contracts	194	—	21	215	(11)	204
Commodity contracts	—	—	193	193	(118)	75
Other contracts	—	—	2	2	—	2
	194	68	270	532	(142)	390
Deferred amounts and other assets
Foreign exchange contracts	—	83	131	214	(108)	106
Interest rate contracts	154	—	44	198	(43)	155
Commodity contracts	—	—	67	67	(30)	37
	154	83	242	479	(181)	298
Other current liabilities
Foreign exchange contracts	—	(42)	(89)	(131)	13	(118)
Interest rate contracts	(19)	—	(1)	(20)	11	(9)
Commodity contracts	(30)	—	(218)	(248)	118	(130)
	(49)	(42)	(308)	(399)	142	(257)
Other long-term liabilities
Foreign exchange contracts	—	—	(980)	(980)	108	(872)
Interest rate contracts	(4)	—	(45)	(49)	43	(6)
Commodity contracts	(21)	—	(123)	(144)	30	(114)
	(25)	—	(1,148)	(1,173)	181	(992)
Total net derivative asset/(liability)
Foreign exchange contracts	—	109	(884)	(775)	—	(775)
Interest rate contracts	325	—	19	344	—	344
Commodity contracts	(51)	—	(81)	(132)	—	(132)
Other contracts	—	—	2	2	—	2
	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:

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

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

Fair Value Derivatives

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

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	(11)	76
Unrealized gain/(loss) on hedged item	11	(87)
Realized loss on derivative	(11)	(75)
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

1Reported within Transportation and other services revenues and 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 $20 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 33 months as at March 31, 2023.

Non-Qualifying Derivatives

The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives:

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Foreign exchange contracts1	556	433
Interest rate contracts2	10	—
Commodity contracts3	(39)	(68)
Other contracts4	(7)	4
Total unrealized derivative fair value gain/(loss), net	520	369

1For the respective three months ended periods, reported within Transportation and other services revenues (2023 - $645 million gain; 2022 - $134 million gain) and Other income (2023 - $89 million loss; 2022 - $299 million gain) in the Consolidated Statements of Earnings.

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

3For the respective three months ended periods, reported within Transportation and other services revenues (2023 - $6 million gain; 2022 - $16 million loss), Commodity sales (2023 - $69 million gain; 2022 - $16 million loss), Commodity costs (2023 - $75 million loss; 2022 - $37 million loss) and Operating and administrative expense (2023 - $39 million loss; 2022 - $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 were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at March 31, 2023. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities.

CREDIT RISK

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

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

	March 31, 2023	December 31, 2022
(millions of Canadian dollars)
Canadian financial institutions	471	644
US financial institutions	115	277
European financial institutions	178	334
Asian financial institutions	97	224
Other1	88	105
	949	1,584

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

As at 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 March 31, 2023 and December 31, 2022.

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

Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, the assessment of credit ratings and netting arrangements. Within Enbridge Gas, credit risk is mitigated by the utility's large and diversified customer base and the ability to recover an estimate for expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

FAIR VALUE MEASUREMENTS

Our financial assets and liabilities measured at fair value on a recurring basis include derivatives and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.

FAIR VALUE OF FINANCIAL INSTRUMENTS

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

Level 1

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

Level 2

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

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

Level 3

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

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

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

March 31, 2023	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	122	—	122
Interest rate contracts	—	215	—	215
Commodity contracts	46	63	84	193
Other contracts	—	2	—	2
	46	402	84	532
Long-term derivative assets
Foreign exchange contracts	—	214	—	214
Interest rate contracts	—	198	—	198
Commodity contracts	—	17	50	67
	—	429	50	479
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(131)	—	(131)
Interest rate contracts	—	(20)	—	(20)
Commodity contracts	(36)	(48)	(164)	(248)
	(36)	(199)	(164)	(399)
Long-term derivative liabilities
Foreign exchange contracts	—	(980)	—	(980)
Interest rate contracts	—	(49)	—	(49)
Commodity contracts	—	(26)	(118)	(144)
	—	(1,055)	(118)	(1,173)
Total net financial asset/(liability)
Foreign exchange contracts	—	(775)	—	(775)
Interest rate contracts	—	344	—	344
Commodity contracts	10	6	(148)	(132)
Other contracts	—	2	—	2
	10	(423)	(148)	(561)

December 31, 2022	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	46	—	46
Interest rate contracts	—	660	—	660
Commodity contracts	65	90	147	302
Other contracts	—	7	—	7
	65	803	147	1,015
Long-term derivative assets
Foreign exchange contracts	—	309	—	309
Interest rate contracts	—	254	—	254
Commodity contracts	—	17	44	61
Other contracts	—	3	—	3
	—	583	44	627
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(566)	—	(566)
Commodity contracts	(60)	(77)	(195)	(332)
	(60)	(643)	(195)	(898)
Long-term derivative liabilities
Foreign exchange contracts	—	(1,116)	—	(1,116)
Interest rate contracts	—	(4)	—	(4)
Commodity contracts	—	(38)	(132)	(170)
	—	(1,158)	(132)	(1,290)
Total net financial asset/(liability)
Foreign exchange contracts	—	(1,327)	—	(1,327)
Interest rate contracts	—	910	—	910
Commodity contracts	5	(8)	(136)	(139)
Other contracts	—	10	—	10
	5	(415)	(136)	(546)

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

March 31, 2023	Fair Value	Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	(34)	Forward gas price	2.30	10.29	4.60	$/mmbtu2
Crude	(12)	Forward crude price	72.61	104.87	92.25	$/barrel
Power	(92)	Forward power price	25.07	214.37	70.68	$/MW/H
Commodity contracts - physical1
Natural gas	(34)	Forward gas price	0.60	8.14	3.51	$/mmbtu2
Crude	(9)	Forward crude price	74.97	116.60	91.05	$/barrel
Power	33	Forward power price	13.30	107.36	55.46	$/MW/H
	(148)

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

2One million British thermal units (mmbtu).

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

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

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(136)	(108)
Total gain/(loss)
Included in earnings1	(44)	(52)
Included in OCI	33	4
Settlements	(1)	(24)
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 March 31, 2023 or December 31, 2022.

NET INVESTMENT HEDGES

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

During the three months ended March 31, 2023 and 2022, we recognized unrealized foreign exchange gains of $59 million and $133 million, respectively, on the translation of US dollar-denominated debt, in OCI. No unrealized gains or losses on the change in fair value of our outstanding foreign exchange forward contracts were recognized in OCI during the three months ended March 31, 2023 and 2022. No realized gains or losses associated with the settlement of foreign exchange forward contracts were 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 debt that had matured during the period, in OCI.

FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS

Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $209 million and $102 million as at March 31, 2023 and December 31, 2022, respectively.

As at March 31, 2023, we had investments with a fair value of $646 million included in Restricted long-term investments in the Consolidated Statements of Financial Position (December 31, 2022 - $593 million). These securities are classified as available-for-sale and represent restricted funds which are collected from customers and held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements.

We had restricted long-term investments held in trust totaling $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 gains of $34 million on these investments for the three months ended March 31, 2023 (2022 - losses of $60 million).

We have wholly-owned captive insurance subsidiaries whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. As at March 31, 2023, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiaries was $351 million and $309 million, respectively (December 31, 2022 - $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 $8 million for the three months ended March 31, 2023 and 2022, respectively.As at March 31, 2023 and December 31, 2022, our long-term debt had a carrying value of $79.5 billion and $79.3 billion, respectively, before debt issuance costs and a fair value of $74.9 billion and $73.5 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at March 31, 2023 and December 31, 2022, the non-current notes receivable had a carrying value of $691 million and $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.

XML

INCOME TAXES

3 Months Ended

Mar. 31, 2023

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The effective income tax rates for the three months ended March 31, 2023 and 2022 were 21.5% and 22.4%, respectively.

The period-over-period decrease in the effective income tax rate is due to higher investment tax credits available on certain capital projects in the US, and the effects of rate-regulated accounting for income taxes relative to earnings.

XML

OTHER INCOME

3 Months Ended

Mar. 31, 2023

Other Income and Expenses [Abstract]

OTHER INCOME

OTHER INCOME

	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

XML

CONTINGENCIES

3 Months Ended

Mar. 31, 2023

Loss Contingency [Abstract]

CONTINGENCIES

CONTINGENCIES

LITIGATION

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

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.

XML

SUBSEQUENT EVENT

3 Months Ended

Mar. 31, 2023

Subsequent Events [Abstract]

SUBSEQUENT EVENT

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.

XML

REVENUES (Tables)

3 Months Ended

Mar. 31, 2023

Revenue from Contract with Customer [Abstract]

Schedule of Disaggregation of Revenue

Major Products and Services

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution and Storage	Renewable Power Generation	Energy Services	Eliminations and Other	Consolidated
Three months ended March 31, 2023
(millions of Canadian dollars)
Transportation revenue	2,942	1,384	276	—	—	—	4,602
Storage and other revenue	64	95	99	—	—	—	258
Gas distribution revenue	—	—	2,287	—	—	—	2,287
Electricity revenue	—	—	—	66	—	—	66
Total revenue from contracts with customers	3,006	1,479	2,662	66	—	—	7,213
Commodity sales	—	—	—	—	4,783	—	4,783
Other revenue1,2	30	11	(40)	78	—	—	79
Intersegment revenue	129	1	3	—	18	(151)	—
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 March 31, 2022
(millions of Canadian dollars)
Transportation revenue	2,685	1,194	251	—	—	—	4,130
Storage and other revenue	51	84	47	—	—	—	182
Gas gathering and processing revenue	—	15	—	—	—	—	15
Gas distribution revenue	—	—	2,098	—	—	—	2,098
Electricity revenue	—	—	—	62	—	—	62
Total revenue from contracts with customers	2,736	1,293	2,396	62	—	—	6,487
Commodity sales	—	—	—	—	8,325	—	8,325
Other revenue1,2	178	7	4	94	2	—	285
Intersegment revenue	141	—	11	—	10	(162)	—
Total revenue	3,055	1,300	2,411	156	8,337	(162)	15,097

1Includes realized and unrealized gains and losses from our hedging program which for the three months ended March 31, 2023 were a net $55 million loss (2022 - $94 million gain).

2 Includes revenues from lease contracts for the three months ended March 31, 2023 and 2022 of $144 million and $164 million, respectively.

Recognition and Measurement of Revenues

	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 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.

Schedule of Contract with Customer, Asset and Liability

Contract Balances

	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

XML

SEGMENTED INFORMATION (Tables)

3 Months Ended

Mar. 31, 2023

Segment Reporting [Abstract]

Schedule of Reporting Information by Segment

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.

XML

EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE (Tables)

3 Months Ended

Mar. 31, 2023

Earnings Per Share [Abstract]

Schedule of Weighted Average Shares Outstanding Used to Calculate Basic and Diluted Earnings Per Common Share

Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:

	Three months ended March 31,
	2023	2022
(number of shares in millions)
Weighted average shares outstanding	2,025	2,026
Effect of dilutive options and RSUs	3	3
Diluted weighted average shares outstanding	2,028	2,029

Schedule of Preferred Stock Characteristics by Class

On May 2, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on June 1, 2023 to shareholders of record on May 15, 2023.

	Dividend per share
Common Shares1	$0.88750
Preference Shares, Series A	$0.34375
Preference Shares, Series B	$0.32513
Preference Shares, Series D2	$0.33825
Preference Shares, Series F	$0.29306
Preference Shares, Series H	$0.27350
Preference Shares, Series L	US$0.36612
Preference Shares, Series N	$0.31788
Preference Shares, Series P	$0.27369
Preference Shares, Series R	$0.25456
Preference Shares, Series 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	$0.38825

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

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

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

XML

DEBT (Tables)

3 Months Ended

Mar. 31, 2023

Debt Disclosure [Abstract]

Schedule of Credit Facilities

The following table provides details of our committed credit facilities as at March 31, 2023:

	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2023-2027	9,623	7,053	2,570
Enbridge (U.S.) Inc.	2024-2027	8,594	1,702	6,892
Enbridge Pipelines Inc.	2024	2,000	876	1,124
Enbridge Gas Inc.	2024	2,500	1,440	1,060
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.

Schedule of Long-Term Debt Instruments

During the three months ended March 31, 2023, we completed the following long-term debt issuances totaling US$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

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

Schedule of Repayment of Debt

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 40 basis points.

XML

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Tables)

3 Months Ended

Mar. 31, 2023

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

Schedule of Changes in AOCI Attributable to Enbridge, Inc. Common Shareholders

Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to our common shareholders for the three months ended March 31, 2023 and 2022 are as follows:

	Cash Flow Hedges	Excluded Components of Fair Value Hedges	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees	Pension and OPEB Adjustment	Total
(millions of Canadian dollars)
Balance as at January 1, 2023	121	(35)	(1,137)	4,348	5	218	3,520
Other comprehensive income/(loss) retained in AOCI	(90)	7	15	(57)	—	—	(125)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	8	—	—	—	—	—	8
Other contracts2	1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(5)	(5)
	(81)	7	15	(57)	—	(5)	(121)
Tax impact
Income tax on amounts retained in AOCI	28	—	—	—	—	—	28
Income tax on amounts reclassified to earnings	(2)	—	—	—	—	1	(1)
	26	—	—	—	—	1	27
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
(millions of Canadian dollars)
Balance as at January 1, 2022	(897)	—	(166)	56	(5)	(84)	(1,096)
Other comprehensive income/(loss) retained in AOCI	384	(1)	133	(691)	—	—	(175)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1	76	—	—	—	—	—	76
Foreign exchange contracts4	(4)	—	—	—	—	—	(4)
Other contracts2	2	—	—	—	—	—	2
Amortization of pension and OPEB actuarial gain3	—	—	—	—	—	(3)	(3)
	458	(1)	133	(691)	—	(3)	(104)
Tax impact
Income tax on amounts retained in AOCI	(92)	—	—	—	—	—	(92)
Income tax on amounts reclassified to earnings	(17)	—	—	—	—	1	(16)
	(109)	—	—	—	—	1	(108)
Balance as at March 31, 2022	(548)	(1)	(33)	(635)	(5)	(86)	(1,308)

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

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

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

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

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of the Consolidated Statements of Financial Position Location and Carrying Value of Derivative Instruments

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.

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)
Other current assets
Foreign exchange contracts	—	68	54	122	(13)	109
Interest rate contracts	194	—	21	215	(11)	204
Commodity contracts	—	—	193	193	(118)	75
Other contracts	—	—	2	2	—	2
	194	68	270	532	(142)	390
Deferred amounts and other assets
Foreign exchange contracts	—	83	131	214	(108)	106
Interest rate contracts	154	—	44	198	(43)	155
Commodity contracts	—	—	67	67	(30)	37
	154	83	242	479	(181)	298
Other current liabilities
Foreign exchange contracts	—	(42)	(89)	(131)	13	(118)
Interest rate contracts	(19)	—	(1)	(20)	11	(9)
Commodity contracts	(30)	—	(218)	(248)	118	(130)
	(49)	(42)	(308)	(399)	142	(257)
Other long-term liabilities
Foreign exchange contracts	—	—	(980)	(980)	108	(872)
Interest rate contracts	(4)	—	(45)	(49)	43	(6)
Commodity contracts	(21)	—	(123)	(144)	30	(114)
	(25)	—	(1,148)	(1,173)	181	(992)
Total net derivative asset/(liability)
Foreign exchange contracts	—	109	(884)	(775)	—	(775)
Interest rate contracts	325	—	19	344	—	344
Commodity contracts	(51)	—	(81)	(132)	—	(132)
Other contracts	—	—	2	2	—	2
	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)

Schedule of the Maturity and Notional Principal or Quantity Outstanding Related to Derivative Instruments

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

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

Schedule of Effect of Cash Flow Hedges and Net Investment Hedges on Consolidated Earnings and Consolidated Comprehensive Income, Before Income Taxes

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

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	(11)	76
Unrealized gain/(loss) on hedged item	11	(87)
Realized loss on derivative	(11)	(75)
Realized gain on hedged item	—	85

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

1Reported within Transportation and other services revenues and 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.

Schedule of Unrealized Gains and Losses Associated With Changes in the Fair Value of Non-Qualifying Derivatives

The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives:

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Foreign exchange contracts1	556	433
Interest rate contracts2	10	—
Commodity contracts3	(39)	(68)
Other contracts4	(7)	4
Total unrealized derivative fair value gain/(loss), net	520	369

1For the respective three months ended periods, reported within Transportation and other services revenues (2023 - $645 million gain; 2022 - $134 million gain) and Other income (2023 - $89 million loss; 2022 - $299 million gain) in the Consolidated Statements of Earnings.

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

3For the respective three months ended periods, reported within Transportation and other services revenues (2023 - $6 million gain; 2022 - $16 million loss), Commodity sales (2023 - $69 million gain; 2022 - $16 million loss), Commodity costs (2023 - $75 million loss; 2022 - $37 million loss) and Operating and administrative expense (2023 - $39 million loss; 2022 - $1 million gain) in the Consolidated Statements of Earnings.

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

Schedule of Group Credit Concentrations and Maximum Credit Exposure, With Respect to Derivative Instruments

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

	March 31, 2023	December 31, 2022
(millions of Canadian dollars)
Canadian financial institutions	471	644
US financial institutions	115	277
European financial institutions	178	334
Asian financial institutions	97	224
Other1	88	105
	949	1,584

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

Schedule of Derivative Assets and Liabilities Measured at Fair Value

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

March 31, 2023	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	122	—	122
Interest rate contracts	—	215	—	215
Commodity contracts	46	63	84	193
Other contracts	—	2	—	2
	46	402	84	532
Long-term derivative assets
Foreign exchange contracts	—	214	—	214
Interest rate contracts	—	198	—	198
Commodity contracts	—	17	50	67
	—	429	50	479
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(131)	—	(131)
Interest rate contracts	—	(20)	—	(20)
Commodity contracts	(36)	(48)	(164)	(248)
	(36)	(199)	(164)	(399)
Long-term derivative liabilities
Foreign exchange contracts	—	(980)	—	(980)
Interest rate contracts	—	(49)	—	(49)
Commodity contracts	—	(26)	(118)	(144)
	—	(1,055)	(118)	(1,173)
Total net financial asset/(liability)
Foreign exchange contracts	—	(775)	—	(775)
Interest rate contracts	—	344	—	344
Commodity contracts	10	6	(148)	(132)
Other contracts	—	2	—	2
	10	(423)	(148)	(561)

December 31, 2022	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	46	—	46
Interest rate contracts	—	660	—	660
Commodity contracts	65	90	147	302
Other contracts	—	7	—	7
	65	803	147	1,015
Long-term derivative assets
Foreign exchange contracts	—	309	—	309
Interest rate contracts	—	254	—	254
Commodity contracts	—	17	44	61
Other contracts	—	3	—	3
	—	583	44	627
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(566)	—	(566)
Commodity contracts	(60)	(77)	(195)	(332)
	(60)	(643)	(195)	(898)
Long-term derivative liabilities
Foreign exchange contracts	—	(1,116)	—	(1,116)
Interest rate contracts	—	(4)	—	(4)
Commodity contracts	—	(38)	(132)	(170)
	—	(1,158)	(132)	(1,290)
Total net financial asset/(liability)
Foreign exchange contracts	—	(1,327)	—	(1,327)
Interest rate contracts	—	910	—	910
Commodity contracts	5	(8)	(136)	(139)
Other contracts	—	10	—	10
	5	(415)	(136)	(546)

Schedule of Significant Unobservable Inputs Used in the Fair Value Measurement of Level 3 Derivative Instruments

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

March 31, 2023	Fair Value	Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	(34)	Forward gas price	2.30	10.29	4.60	$/mmbtu2
Crude	(12)	Forward crude price	72.61	104.87	92.25	$/barrel
Power	(92)	Forward power price	25.07	214.37	70.68	$/MW/H
Commodity contracts - physical1
Natural gas	(34)	Forward gas price	0.60	8.14	3.51	$/mmbtu2
Crude	(9)	Forward crude price	74.97	116.60	91.05	$/barrel
Power	33	Forward power price	13.30	107.36	55.46	$/MW/H
	(148)

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

2One million British thermal units (mmbtu).

Schedule of Changes in Net Fair Value of Derivative Assets and Liabilities Classified as Level 3 in the Fair Value Hierarchy

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

	Three months ended March 31,
	2023	2022
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(136)	(108)
Total gain/(loss)
Included in earnings1	(44)	(52)
Included in OCI	33	4
Settlements	(1)	(24)
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.

XML

OTHER INCOME (Tables)

3 Months Ended

Mar. 31, 2023

Other Income and Expenses [Abstract]

Schedule of Other Income

	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

XML

REVENUES - Disaggregation of Revenue (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 7,213	$ 6,487
Total revenues	12,075	15,097
Mark-to-market (loss) gain from hedging program	(55)	94
Revenues from lease contracts	144	164
Revenues from products transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	30	16
Revenue from products and services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	7,183	6,471
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	4,602	4,130
Storage and other revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	258	182
Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		15
Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,287	2,098
Total revenues	2,279	2,098
Electricity revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	66	62
Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	4,783	8,325
Total revenues	4,783	8,325
Other revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	79	285
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	3,006	2,736
Liquids Pipelines | Revenues from products transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Liquids Pipelines | Revenue from products and services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	3,006	2,736
Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,479	1,293
Gas Transmission and Midstream | Revenues from products transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Gas Transmission and Midstream | Revenue from products and services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,479	1,293
Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,662	2,396
Gas Distribution and Storage | Revenues from products transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	30	16
Gas Distribution and Storage | Revenue from products and services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,632	2,380
Renewable Power Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	66	62
Renewable Power Generation | Revenues from products transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Renewable Power Generation | Revenue from products and services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	66	62
Business segments | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	3,006	2,736
Total revenues	3,165	3,055
Business segments | Liquids Pipelines | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,942	2,685
Business segments | Liquids Pipelines | Storage and other revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	64	51
Business segments | Liquids Pipelines | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		0
Business segments | Liquids Pipelines | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Liquids Pipelines | Electricity revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Liquids Pipelines | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	0	0
Business segments | Liquids Pipelines | Other revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	30	178
Business segments | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,479	1,293
Total revenues	1,491	1,300
Business segments | Gas Transmission and Midstream | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,384	1,194
Business segments | Gas Transmission and Midstream | Storage and other revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	95	84
Business segments | Gas Transmission and Midstream | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		15
Business segments | Gas Transmission and Midstream | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Gas Transmission and Midstream | Electricity revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Gas Transmission and Midstream | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	0	0
Business segments | Gas Transmission and Midstream | Other revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	11	7
Business segments | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,662	2,396
Total revenues	2,625	2,411
Business segments | Gas Distribution and Storage | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	276	251
Business segments | Gas Distribution and Storage | Storage and other revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	99	47
Business segments | Gas Distribution and Storage | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		0
Business segments | Gas Distribution and Storage | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,287	2,098
Business segments | Gas Distribution and Storage | Electricity revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Gas Distribution and Storage | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	0	0
Business segments | Gas Distribution and Storage | Other revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	(40)	4
Business segments | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	66	62
Total revenues	144	156
Business segments | Renewable Power Generation | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Renewable Power Generation | Storage and other revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Renewable Power Generation | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		0
Business segments | Renewable Power Generation | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Renewable Power Generation | Electricity revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	66	62
Business segments | Renewable Power Generation | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	0	0
Business segments | Renewable Power Generation | Other revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	78	94
Business segments | Energy Services
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Total revenues	4,801	8,337
Business segments | Energy Services | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Energy Services | Storage and other revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Energy Services | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		0
Business segments | Energy Services | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Energy Services | Electricity revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Business segments | Energy Services | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	4,783	8,325
Business segments | Energy Services | Other revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	0	2
Eliminations and Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Total revenues	(151)	(162)
Eliminations and Other | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Eliminations and Other | Storage and other revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Eliminations and Other | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		0
Eliminations and Other | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Eliminations and Other | Electricity revenue
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0	0
Eliminations and Other | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	0	0
Eliminations and Other | Other revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	0	0
Intersegment revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	(151)	(162)
Total revenues	(151)	(162)
Intersegment revenue | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	129	141
Intersegment revenue | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	1	0
Intersegment revenue | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	3	11
Intersegment revenue | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	0	0
Intersegment revenue | Energy Services
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	$ 18	$ 10

XML

REVENUES - Contract Balances (Details) - CAD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Contract Receivables	$ 3,186	$ 3,183
Contract Assets	232	230
Contract Liabilities	$ 2,328	$ 2,241

XML

REVENUES - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 CAD ($)
Revenue from Contract with Customer [Abstract]
Revenue recognized	$ 36
Increase in contract with customers, liability	124
Remaining performance obligation	60,000
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-04-01
Revenue from Contract with Customer [Abstract]
Remaining performance obligation	$ 6,000
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue from Contract with Customer [Abstract]
Remaining performance obligation	$ 6,700
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period	1 year

XML

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Segmented Information
Operating revenues	$ 12,075	$ 15,097
Commodity and gas distribution costs	(6,230)	(9,747)
Operating and administrative	(2,037)	(1,875)
Income/(loss) from equity investments	517	491
Other income/(expense)	102	458
Earnings/(loss) before interest, income taxes and depreciation and amortization	4,427	4,424
Depreciation and amortization	(1,146)	(1,055)
Interest expense	(905)	(719)
Income tax expense	(510)	(593)
Earnings	1,866	2,057
Capital expenditures	1,141	1,058
Eliminations and Other
Segmented Information
Operating revenues	(151)	(162)
Commodity and gas distribution costs	168	163
Operating and administrative	15	(37)
Income/(loss) from equity investments	(4)	0
Other income/(expense)	(22)	391
Earnings/(loss) before interest, income taxes and depreciation and amortization	6	355
Capital expenditures	25	12
Liquids Pipelines | Business segments
Segmented Information
Operating revenues	3,165	3,055
Commodity and gas distribution costs	0	(11)
Operating and administrative	(1,123)	(947)
Income/(loss) from equity investments	248	215
Other income/(expense)	73	17
Earnings/(loss) before interest, income taxes and depreciation and amortization	2,363	2,329
Capital expenditures	280	545
Gas Transmission and Midstream | Business segments
Segmented Information
Operating revenues	1,491	1,300
Commodity and gas distribution costs	0	0
Operating and administrative	(549)	(530)
Income/(loss) from equity investments	238	221
Other income/(expense)	25	23
Earnings/(loss) before interest, income taxes and depreciation and amortization	1,205	1,014
Capital expenditures	527	229
Gas Distribution and Storage | Business segments
Segmented Information
Operating revenues	2,625	2,411
Commodity and gas distribution costs	(1,612)	(1,468)
Operating and administrative	(309)	(299)
Income/(loss) from equity investments	0	0
Other income/(expense)	12	21
Earnings/(loss) before interest, income taxes and depreciation and amortization	716	665
Capital expenditures	264	266
Renewable Power Generation | Business segments
Segmented Information
Operating revenues	144	156
Commodity and gas distribution costs	(4)	(4)
Operating and administrative	(53)	(48)
Income/(loss) from equity investments	35	55
Other income/(expense)	14	3
Earnings/(loss) before interest, income taxes and depreciation and amortization	136	162
Capital expenditures	45	6
Energy Services | Business segments
Segmented Information
Operating revenues	4,801	8,337
Commodity and gas distribution costs	(4,782)	(8,427)
Operating and administrative	(18)	(14)
Income/(loss) from equity investments	0	0
Other income/(expense)	0	3
Earnings/(loss) before interest, income taxes and depreciation and amortization	1	(101)
Capital expenditures	$ 0	$ 0

XML

EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE - Diluted (Details) - $ / shares shares in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Weighted average number of common shares outstanding diluted
Weighted average shares outstanding (in shares)	2,025.0	2,026.0
Effect of dilutive options and RSUs (in shares)	3.0	3.0
Diluted weighted average shares outstanding (in shares)	2,028.0	2,029.0
Stock options
Weighted average number of common shares outstanding diluted
Antidilutive securities excluded from the diluted earnings per common share calculation (in shares)	16.7	12.9
Weighted average exercise price of antidilutive securities (in Canadian dollars per share)	$ 55.62	$ 56.09

XML

EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE - Dividends Per Share (Details)							3 Months Ended
	Jun. 01, 2023 $ / shares	Jun. 01, 2023 $ / shares	May 02, 2023 $ / shares	May 02, 2023 $ / shares	Mar. 01, 2023 $ / shares	Feb. 28, 2023 $ / shares	Mar. 31, 2023 $ / shares	Mar. 31, 2022 $ / shares
Dividends Payable [Line Items]
Common stock, dividends, per share, declared (in dollars per share)					$ 0.8875	$ 0.86
Common stock, dividends per share, paid (in dollars per share)							$ 0.888	$ 0.860
Common Stock Dividends Per Share Increase Decrease					3.20%
Preference Shares, Series L
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)					$ 0.38825	0.30625
Common shares | Forecast
Dividends Payable [Line Items]
Common stock, dividends per share, paid (in dollars per share)	$ 0.88750
Common shares | Subsequent event
Dividends Payable [Line Items]
Common stock, dividends, per share, declared (in dollars per share)			$ 0.88750
Preferred share investment | Preference Shares, Series A | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.34375
Preferred share investment | Preference Shares, Series A | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.34375
Preferred share investment | Preference Shares, Series B
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)					$ 0.33825	$ 0.27875
Preferred share investment | Preference Shares, Series B | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.32513
Preferred share investment | Preference Shares, Series B | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.32513
Preferred share investment | Preference Shares, Series D | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.33825
Preferred share investment | Preference Shares, Series D | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.33825
Preferred share investment | Preference Shares, Series F | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.29306
Preferred share investment | Preference Shares, Series F | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.29306
Preferred share investment | Preference Shares, Series H | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.27350
Preferred share investment | Preference Shares, Series H | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.27350
Preferred share investment | Preference Shares, Series L | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)		$ 0.36612
Preferred share investment | Preference Shares, Series L | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)				$ 0.36612
Preferred share investment | Preference Shares, Series N | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.31788
Preferred share investment | Preference Shares, Series N | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.31788
Preferred share investment | Preference Shares, Series P | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.27369
Preferred share investment | Preference Shares, Series P | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.27369
Preferred share investment | Preference Shares, Series R | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.25456
Preferred share investment | Preference Shares, Series R | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.25456
Preferred share investment | Preference Shares, Series 1 | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)		0.37182
Preferred share investment | Preference Shares, Series 1 | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)				0.37182
Preferred share investment | Preference Shares, Series 3 | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.23356
Preferred share investment | Preference Shares, Series 3 | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.23356
Preferred share investment | Preference Shares, Series 5 | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)		$ 0.33596
Preferred share investment | Preference Shares, Series 5 | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)				$ 0.33596
Preferred share investment | Preference Shares, Series 7 | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.27806
Preferred share investment | Preference Shares, Series 7 | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.27806
Preferred share investment | Preference Shares, Series 9 | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.25606
Preferred share investment | Preference Shares, Series 9 | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.25606
Preferred share investment | Preference Shares, Series 11 | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.24613
Preferred share investment | Preference Shares, Series 11 | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.24613
Preferred share investment | Preference Shares, Series 13 | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.19019
Preferred share investment | Preference Shares, Series 13 | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.19019
Preferred share investment | Preference Shares, Series 15 | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	0.18644
Preferred share investment | Preference Shares, Series 15 | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			0.18644
Preferred share investment | Preference Shares, Series 19 | Forecast
Dividends Payable [Line Items]
Preferred stock, dividend paid per share (dollars per share)	$ 0.38825
Preferred share investment | Preference Shares, Series 19 | Subsequent event
Dividends Payable [Line Items]
Preferred stock, dividend declared per share (dollars per share)			$ 0.38825

XML

DEBT - Credit Facilities (Details) - Committed credit facilities $ in Millions	3 Months Ended
	Mar. 31, 2023 CAD ($)
CREDIT FACILITIES
Total Facilities	$ 22,717
Draws	11,071
Available	$ 11,646
Term out option period	1 year
Enbridge (U.S.) Inc.
CREDIT FACILITIES
Total Facilities	$ 8,594
Draws	1,702
Available	6,892
Enbridge Pipelines Inc.
CREDIT FACILITIES
Total Facilities	2,000
Draws	876
Available	1,124
Enbridge Gas Inc.
CREDIT FACILITIES
Total Facilities	2,500
Draws	1,440
Available	1,060
Enbridge Inc.
CREDIT FACILITIES
Total Facilities	9,623
Draws	7,053
Available	$ 2,570

XML

DEBT - Narrative (Details) $ in Millions		3 Months Ended
	Apr. 15, 2023 USD ($)	Mar. 31, 2023 CAD ($)	Feb. 28, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Line of Credit Facility [Line Items]
Commitment fee percentage		0.10%
Long-term debt		$ 71,740,000,000		$ 72,939,000,000
Long-term debt, fair value adjustment		588,000,000		608,000,000
Amortization of fair value adjustment		11,000,000
Commercial paper and credit facility draws
Line of Credit Facility [Line Items]
Long-term debt		9,000,000,000		10,500,000,000
Fixed-to-floating subordinated term notes | Subordinated term notes
Line of Credit Facility [Line Items]
Subordinated debt		10,300,000,000
Five-year Callable Fixed To Floating Rate Subordinated Notes | Subsequent event | Long-Term Debt
Line of Credit Facility [Line Items]
Long-term debt, amount outstanding	$ 600
Interest rate (as a percent)	6.38%
Revolving credit facility | 364-day extendible credit facility
Line of Credit Facility [Line Items]
Amount of credit facility		2,500,000,000	$ 2,000,000,000
Uncommitted demand credit facilities
Line of Credit Facility [Line Items]
Amount of credit facility		1,300,000,000		1,300,000,000
Unutilized amount of facility		$ 720,000,000		$ 689,000,000

XML

DEBT - Long Term Debt Issuance (Details) - Enbridge Inc. $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($)
Debt Instrument [Line Items]
Principal amount of debt	$ 3,000
5.70% sustainability-linked senior notes due March 2033
Debt Instrument [Line Items]
Interest rate (as a percent)	5.70%
Principal amount of debt	$ 2,300
5.70% sustainability-linked senior notes due March 2033 | Debt Instrument Interest Rate Terms Period One
Debt Instrument [Line Items]
Interest rate (as a percent)	35.00%
5.70% sustainability-linked senior notes due March 2033 | Debt Instrument Interest Rate Terms Period Two
Debt Instrument [Line Items]
Interest rate (as a percent)	5.70%
Spread on variable rate (percent)	0.50%
5.97% senior note due March 2026
Debt Instrument [Line Items]
Interest rate (as a percent)	5.97%
Principal amount of debt	$ 700
Term of fixed rate	3 years
Debt instrument maturity period (in year)	1 year

XML

DEBT - Long Term Debt Repayments (Details) $ in Millions, $ in Millions	1 Months Ended			3 Months Ended
	Feb. 28, 2023 USD ($)	Jan. 31, 2023 USD ($)	Jan. 31, 2023 CAD ($)	Mar. 31, 2023 USD ($)	Mar. 31, 2023 CAD ($)
Long-Term Debt
DEBT
Principal Amount				$ 513	$ 275
10.00% Senior notes | Tri Global Energy, LLC
DEBT
Interest rate (as a percent)		10.00%	10.00%
Principal Amount		$ 4
14.00% Senior notes | Tri Global Energy, LLC
DEBT
Interest rate (as a percent)		14.00%	14.00%
Principal Amount		$ 9
Enbridge Inc. | 3.94% medium-term notes
DEBT
Interest rate (as a percent)		3.94%	3.94%
Principal Amount			$ 275
Enbridge Inc. | Floating rate notes
DEBT
Principal Amount	$ 500
Enbridge Inc. | Floating rate notes | London Interbank Offered Rate
DEBT
Spread on variable rate (percent)				0.40%	0.40%

XML

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Changes in AOCI
Balance at the beginning of the period	$ 63,398
Other comprehensive income/(loss) retained in AOCI	(125)	$ (175)
Total before tax impact	(121)	(104)
Income tax on amounts retained in AOCI	28	(92)
Income tax on amounts reclassified to earnings	(1)	(16)
Tax impact	27	(108)
Balance at the end of the period	65,025	64,273
Interest rate contracts
Changes in AOCI
Other comprehensive loss/(income) reclassified to earnings	8	76
Foreign exchange contracts
Changes in AOCI
Other comprehensive loss/(income) reclassified to earnings		(4)
Other contracts
Changes in AOCI
Other comprehensive loss/(income) reclassified to earnings	1	2
Total
Changes in AOCI
Balance at the beginning of the period	3,520	(1,096)
Balance at the end of the period	3,426	(1,308)
Cash Flow Hedges
Changes in AOCI
Balance at the beginning of the period	121	(897)
Other comprehensive income/(loss) retained in AOCI	(90)	384
Total before tax impact	(81)	458
Income tax on amounts retained in AOCI	28	(92)
Income tax on amounts reclassified to earnings	(2)	(17)
Tax impact	26	(109)
Balance at the end of the period	66	(548)
Cash Flow Hedges | Interest rate contracts
Changes in AOCI
Other comprehensive loss/(income) reclassified to earnings	8	76
Cash Flow Hedges | Foreign exchange contracts
Changes in AOCI
Other comprehensive loss/(income) reclassified to earnings		(4)
Cash Flow Hedges | Other contracts
Changes in AOCI
Other comprehensive loss/(income) reclassified to earnings	1	2
Excluded Components of Fair Value Hedges
Changes in AOCI
Balance at the beginning of the period	(35)	0
Other comprehensive income/(loss) retained in AOCI	7	(1)
Total before tax impact	7	(1)
Tax impact	0	0
Balance at the end of the period	(28)	(1)
Net Investment Hedges
Changes in AOCI
Balance at the beginning of the period	(1,137)	(166)
Other comprehensive income/(loss) retained in AOCI	15	133
Total before tax impact	15	133
Income tax on amounts retained in AOCI		0
Tax impact	0	0
Balance at the end of the period	(1,122)	(33)
Cumulative Translation Adjustment
Changes in AOCI
Balance at the beginning of the period	4,348	56
Other comprehensive income/(loss) retained in AOCI	(57)	(691)
Total before tax impact	(57)	(691)
Tax impact	0	0
Balance at the end of the period	4,291	(635)
Equity Investees
Changes in AOCI
Balance at the beginning of the period	5	(5)
Other comprehensive income/(loss) retained in AOCI	0	0
Total before tax impact	0	0
Income tax on amounts retained in AOCI	0	0
Tax impact	0	0
Balance at the end of the period	5	(5)
Pension and OPEB Adjustment
Changes in AOCI
Balance at the beginning of the period	218	(84)
Other comprehensive loss/(income) reclassified to earnings	(5)	(3)
Total before tax impact	(5)	(3)
Income tax on amounts reclassified to earnings	1	1
Tax impact	1	1
Balance at the end of the period	$ 214	$ (86)

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Market Risk (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 equity_type	Mar. 08, 2023 USD ($)
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate, variable (as a percent)	2.50%
Three-Year Fixed Rate Notes | Notes Payable, Other Payables
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Principal Amount | $		$ 700
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Floating rate debt as target percentage of total debt outstanding maximum	30.00%
Average swap rate (percent)	4.10%
Derivative, fixed interest rate		6.00%
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Number of forms of stock-based compensation with equity price risk | equity_type	1

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Foreign Exchange Risk (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 CAD ($)
Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Derivatives terminated, realized loss	$ 638

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Total Derivative Instruments (Details) - CAD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	$ (561)	$ (546)
Derivative liabilities, Total Net Derivative Instruments	(561)	(546)
Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(944)	(1,476)
Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	274	816
Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	109	114
Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	532	1,015
Derivative assets, Amounts Available for Offset	(142)	(223)
Derivative assets, Total Net Derivative Instruments	390	792
Other current assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	270	366
Other current assets | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	194	649
Other current assets | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	68	0
Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	479	627
Derivative assets, Amounts Available for Offset	(181)	(163)
Derivative assets, Total Net Derivative Instruments	298	464
Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	242	216
Deferred amounts and other assets | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	154	255
Deferred amounts and other assets | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	83	156
Other current liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(399)	(898)
Derivative liabilities, Amounts Available for Offset	142	223
Derivative liabilities, Total Net Derivative Instruments	(257)	(675)
Other current liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(308)	(808)
Other current liabilities | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(49)	(48)
Other current liabilities | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(42)	(42)
Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(1,173)	(1,290)
Derivative liabilities, Amounts Available for Offset	181	163
Derivative liabilities, Total Net Derivative Instruments	(992)	(1,127)
Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(1,148)	(1,250)
Other long-term liabilities | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(25)	(40)
Other long-term liabilities | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(775)	(1,327)
Derivative liabilities, Total Net Derivative Instruments	(775)	(1,327)
Foreign exchange contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(884)	(1,441)
Foreign exchange contracts | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	0	$ 0
Derivative Liability, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Noncurrent
Foreign exchange contracts | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	109	$ 114
Foreign exchange contracts | Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	122	46
Derivative assets, Amounts Available for Offset	(13)	(41)
Derivative assets, Total Net Derivative Instruments	109	5
Foreign exchange contracts | Other current assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	54	46
Foreign exchange contracts | Other current assets | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Foreign exchange contracts | Other current assets | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	68	0
Foreign exchange contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	214	309
Derivative assets, Amounts Available for Offset	(108)	(138)
Derivative assets, Total Net Derivative Instruments	106	171
Foreign exchange contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	131	153
Foreign exchange contracts | Deferred amounts and other assets | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Foreign exchange contracts | Deferred amounts and other assets | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	83	156
Foreign exchange contracts | Other current liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(131)	(566)
Derivative liabilities, Amounts Available for Offset	13	41
Derivative liabilities, Total Net Derivative Instruments	(118)	(525)
Foreign exchange contracts | Other current liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(89)	(524)
Foreign exchange contracts | Other current liabilities | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Foreign exchange contracts | Other current liabilities | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(42)	(42)
Foreign exchange contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(980)	(1,116)
Derivative liabilities, Amounts Available for Offset	108	138
Derivative liabilities, Total Net Derivative Instruments	(872)	(978)
Foreign exchange contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(980)	(1,116)
Foreign exchange contracts | Other long-term liabilities | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Foreign exchange contracts | Other long-term liabilities | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities		(4)
Total net financial asset/(liability)	344	910
Derivative liabilities, Total Net Derivative Instruments	344	$ 910
Derivative Liability, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Noncurrent
Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities		$ (1)
Total net financial asset/(liability)	19	$ 10
Derivative Liability, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Noncurrent
Interest rate contracts | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities		$ (3)
Total net financial asset/(liability)	325	900
Interest rate contracts | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities		0
Total net financial asset/(liability)	0	$ 0
Derivative Liability, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Noncurrent
Interest rate contracts | Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	215	$ 660
Derivative assets, Amounts Available for Offset	(11)	0
Derivative assets, Total Net Derivative Instruments	204	660
Interest rate contracts | Other current assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	21	11
Interest rate contracts | Other current assets | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	194	649
Interest rate contracts | Other current assets | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Interest rate contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	198	254
Derivative assets, Amounts Available for Offset	(43)	0
Derivative assets, Total Net Derivative Instruments	155	254
Interest rate contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	44	0
Interest rate contracts | Deferred amounts and other assets | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	154	254
Interest rate contracts | Deferred amounts and other assets | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Interest rate contracts | Other current liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(20)
Derivative liabilities, Amounts Available for Offset	11
Derivative liabilities, Total Net Derivative Instruments	(9)
Interest rate contracts | Other current liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(1)
Interest rate contracts | Other current liabilities | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(19)
Interest rate contracts | Other current liabilities | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0
Interest rate contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(49)
Derivative liabilities, Amounts Available for Offset	43	0
Derivative liabilities, Total Net Derivative Instruments	(6)	(4)
Interest rate contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(45)
Interest rate contracts | Other long-term liabilities | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(4)
Interest rate contracts | Other long-term liabilities | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0
Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(132)	(139)
Derivative liabilities, Total Net Derivative Instruments	(132)	(139)
Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(81)	(54)
Commodity contracts | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(51)	(85)
Commodity contracts | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	0	0
Commodity contracts | Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	193	302
Derivative assets, Amounts Available for Offset	(118)	(182)
Derivative assets, Total Net Derivative Instruments	75	120
Commodity contracts | Other current assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	193	302
Commodity contracts | Other current assets | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Commodity contracts | Other current assets | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Commodity contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	67	61
Derivative assets, Amounts Available for Offset	(30)	(25)
Derivative assets, Total Net Derivative Instruments	37	36
Commodity contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	67	61
Commodity contracts | Deferred amounts and other assets | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Commodity contracts | Deferred amounts and other assets | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Commodity contracts | Other current liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(248)	(332)
Derivative liabilities, Amounts Available for Offset	118	182
Derivative liabilities, Total Net Derivative Instruments	(130)	(150)
Commodity contracts | Other current liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(218)	(284)
Commodity contracts | Other current liabilities | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(30)	(48)
Commodity contracts | Other current liabilities | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Commodity contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(144)	(170)
Derivative liabilities, Amounts Available for Offset	30	25
Derivative liabilities, Total Net Derivative Instruments	(114)	(145)
Commodity contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(123)	(133)
Commodity contracts | Other long-term liabilities | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(21)	(37)
Commodity contracts | Other long-term liabilities | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Other contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	2
Total net financial asset/(liability)	2	10
Derivative assets, Amounts Available for Offset	0
Derivative assets, Total Net Derivative Instruments	2
Derivative liabilities, Total Net Derivative Instruments	2	10
Other contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	2
Total net financial asset/(liability)	2	9
Other contracts | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0
Total net financial asset/(liability)	0	1
Other contracts | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0
Total net financial asset/(liability)	$ 0	0
Other contracts | Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets		7
Derivative assets, Amounts Available for Offset		0
Derivative assets, Total Net Derivative Instruments		7
Other contracts | Other current assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets		7
Other contracts | Other current assets | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets		0
Other contracts | Other current assets | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets		0
Other contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets		3
Derivative assets, Amounts Available for Offset		0
Derivative assets, Total Net Derivative Instruments		3
Other contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets		2
Other contracts | Deferred amounts and other assets | Derivative Instruments Used as Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets		1
Other contracts | Deferred amounts and other assets | Derivative Instruments Used as Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets		$ 0

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional Principal or Quantity Information (Details) - Mar. 31, 2023 € in Millions, ¥ in Millions, £ in Millions, $ in Millions, $ in Millions	USD ($)	GBP (£)	EUR (€)	JPY (¥)	CAD ($)	Bcf	MMBbls	MWh
Foreign exchange contracts - forwards - purchase
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Derivative Notional Amount Outstanding	$ 2,332			¥ 84,800
Foreign exchange contracts - forwards - purchase | United States dollar
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023	832
2024	1,000
2025	500
2026	0
2027	0
Thereafter	0
Foreign exchange contracts - forwards - purchase | Japanese yen
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023 | ¥				0
2024 | ¥				0
2025 | ¥				84,800
2026 | ¥				0
2027 | ¥				0
Thereafter | ¥				¥ 0
Foreign exchange contracts - forwards - sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Derivative Notional Amount Outstanding	22,891	£ 141	€ 674
Foreign exchange contracts - forwards - sell | United States dollar
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023	4,566
2024	4,708
2025	4,763
2026	4,157
2027	2,969
Thereafter	$ 1,728
Foreign exchange contracts - forwards - sell | GBP
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023 | £		21
2024 | £		30
2025 | £		30
2026 | £		28
2027 | £		32
Thereafter | £		£ 0
Foreign exchange contracts - forwards - sell | Euro
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023 | €			69
2024 | €			91
2025 | €			86
2026 | €			85
2027 | €			81
Thereafter | €			€ 262
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023					$ 7,821
2024					1,929
2025					80
2026					26
2027					25
Thereafter					39
Derivative Notional Amount Outstanding					9,920
Interest rate contracts - short-term debt receive
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023					711
2024					947
2025					947
2026					179
2027					0
Thereafter					0
Derivative Notional Amount Outstanding					2,784
Interest rate contracts - long-term debt pay fixed rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023					4,153
2024					1,494
2025					588
2026					0
2027					0
Thereafter					0
Derivative Notional Amount Outstanding					6,235
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023					0
2024					32
2025					12
2026					0
2027					0
Thereafter					0
Derivative Notional Amount Outstanding					$ 44
Commodity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Derivative Nonmonetary Notional Amount Outstanding						93,000,000	11,000,000
Commodity contracts | Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023 (bcf / mmbbls) | Bcf						34,000,000
2024 (bcf / mmbbls) | Bcf						25,000,000
2025 (bcf / mmbbls) | Bcf						23,000,000
2026 (bcf / mmbbls) | Bcf						8,000,000
2027 (bcf / mmbbls) | Bcf						3,000,000
Thereafter (bcf / mmbbls) | Bcf						0
Commodity contracts | Crude
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023 (bcf / mmbbls) | MMBbls							11,000,000
2024 (bcf / mmbbls) | MMBbls							0
2025 (bcf / mmbbls) | MMBbls							0
2026 (bcf / mmbbls) | MMBbls							0
2027 (bcf / mmbbls) | MMBbls							0
Thereafter (bcf / mmbbls) | MMBbls							0
Net sell | Commodity contracts | Power
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023 (MWH) | MWh								19,000,000
2024 (MWH) | MWh								(31,000,000)
2025 (MWH) | MWh								(46,000,000)
2026 (MWH) | MWh								0
2027 (MWH) | MWh								0
Thereafter (MWH) | MWh								0
Total (MWH) | MWh								(17)

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value Derivatives (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Foreign Currency Fair Value Hedge Derivative [Line Items]
Realized loss on derivative	$ (55)	$ 94
Fair value hedges | Interest rate contracts
Foreign Currency Fair Value Hedge Derivative [Line Items]
Unrealized gain/(loss) on derivative	(11)	76
Unrealized gain/(loss) on hedged item	11	(87)
Realized loss on derivative	(11)	(75)
Realized gain on hedged item	$ 0	$ 85

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Earnings and Comprehensive Income (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	$ (66)	$ 385
Amount of loss reclassified from AOCI to earnings	9	91
Estimated gain (loss) of AOCI related to cash flow hedges reclassified to earnings in the next 12 months	$ 20
Maximum term of hedging exposures to variability of cash flows	33 months
Unrealized gain (loss) on derivatives	$ 520	369
Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	520	369
Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of loss reclassified from AOCI to earnings	0	13
Foreign exchange contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	556	433
Foreign exchange contracts | Gas distribution sales revenues | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(645)	134
Foreign exchange contracts | Other income/(expense) | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(89)	(299)
Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of loss reclassified from AOCI to earnings	8	76
Interest rate contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	10	0
Commodity contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(39)	(68)
Commodity contracts | Gas distribution sales revenues | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	6	(16)
Commodity contracts | Commodity sales | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	69	(16)
Commodity contracts | Commodity costs | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(75)	(37)
Commodity contracts | Operating and administrative expense | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	39	1
Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of loss reclassified from AOCI to earnings	1	2
Other contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(7)	4
Cash flow hedges | Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	0	2
Cash flow hedges | Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(105)	377
Cash flow hedges | Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	34	4
Cash flow hedges | Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(2)	3
Fair value hedges | Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	$ 7	$ (1)

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Liquidity and Credit Risk (Details) - CAD ($)	3 Months Ended	6 Months Ended
	Mar. 31, 2023	Jun. 30, 2022	Dec. 31, 2022
LIQUIDITY RISK AND CREDIT RISK
Rolling time period over which the Company forecasts cash requirements	12 months
Period of anticipated requirements for which the Company maintains sufficient liquidity through committed credit facilities	1 year
Derivative instruments
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 949,000,000	$ 1,584,000,000
Cash collateral on asset exposure	0		$ 0
Derivative instruments | Canadian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	471,000,000	644,000,000
Derivative instruments | US financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	115,000,000	277,000,000
Derivative instruments | European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	178,000,000	334,000,000
Derivative instruments | Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	97,000,000	224,000,000
Derivative instruments | Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 88,000,000	$ 105,000,000

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Derivatives (Details) - CAD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Fair Value of Derivatives
Total net financial asset/(liability)	$ (561)	$ (546)
Fair Value
Fair Value of Derivatives
Current derivative assets	532	1,015
Long-term derivative assets	479	627
Current derivative liabilities	(399)	(898)
Long-term derivative liabilities	(1,173)	(1,290)
Total net financial asset/(liability)	(561)	(546)
Foreign exchange contracts
Fair Value of Derivatives
Total net financial asset/(liability)	(775)	(1,327)
Foreign exchange contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	122	46
Long-term derivative assets	214	309
Current derivative liabilities	(131)	(566)
Long-term derivative liabilities	(980)	(1,116)
Total net financial asset/(liability)	(775)	(1,327)
Interest rate contracts
Fair Value of Derivatives
Total net financial asset/(liability)	344	910
Interest rate contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	215	660
Long-term derivative assets	198	254
Current derivative liabilities	(20)
Long-term derivative liabilities	(49)	(4)
Total net financial asset/(liability)	344	910
Commodity contracts
Fair Value of Derivatives
Total net financial asset/(liability)	(132)	(139)
Commodity contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	193	302
Long-term derivative assets	67	61
Current derivative liabilities	(248)	(332)
Long-term derivative liabilities	(144)	(170)
Total net financial asset/(liability)	(132)	(139)
Other contracts
Fair Value of Derivatives
Total net financial asset/(liability)	2	10
Other contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	2	7
Long-term derivative assets		3
Total net financial asset/(liability)	2	10
Level 1 | Fair Value
Fair Value of Derivatives
Current derivative assets	46	65
Long-term derivative assets	0	0
Current derivative liabilities	(36)	(60)
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	10	5
Level 1 | Foreign exchange contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	0	0
Level 1 | Interest rate contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	0	0
Level 1 | Commodity contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	46	65
Long-term derivative assets	0	0
Current derivative liabilities	(36)	(60)
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	10	5
Level 1 | Other contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets		0
Total net financial asset/(liability)	0	0
Level 2 | Fair Value
Fair Value of Derivatives
Current derivative assets	402	803
Long-term derivative assets	429	583
Current derivative liabilities	(199)	(643)
Long-term derivative liabilities	(1,055)	(1,158)
Total net financial asset/(liability)	(423)	(415)
Level 2 | Foreign exchange contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	122	46
Long-term derivative assets	214	309
Current derivative liabilities	(131)	(566)
Long-term derivative liabilities	(980)	(1,116)
Total net financial asset/(liability)	(775)	(1,327)
Level 2 | Interest rate contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	215	660
Long-term derivative assets	198	254
Current derivative liabilities	(20)
Long-term derivative liabilities	(49)	(4)
Total net financial asset/(liability)	344	910
Level 2 | Commodity contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	63	90
Long-term derivative assets	17	17
Current derivative liabilities	(48)	(77)
Long-term derivative liabilities	(26)	(38)
Total net financial asset/(liability)	6	(8)
Level 2 | Other contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	2	7
Long-term derivative assets		3
Total net financial asset/(liability)	2	10
Level 3
Fair Value of Derivatives
Total net financial asset/(liability)	(148)
Level 3 | Fair Value
Fair Value of Derivatives
Current derivative assets	84	147
Long-term derivative assets	50	44
Current derivative liabilities	(164)	(195)
Long-term derivative liabilities	(118)	(132)
Total net financial asset/(liability)	(148)	(136)
Level 3 | Foreign exchange contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	0	0
Level 3 | Interest rate contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	0	0
Level 3 | Commodity contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	84	147
Long-term derivative assets	50	44
Current derivative liabilities	(164)	(195)
Long-term derivative liabilities	(118)	(132)
Total net financial asset/(liability)	(148)	(136)
Level 3 | Other contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets		0
Total net financial asset/(liability)	$ 0	$ 0

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Level 3 Inputs (Details) $ in Millions	Mar. 31, 2023 CAD ($) $ / MWh $ / bbl $ / MillionsofBTU-MMBTU	Dec. 31, 2022 CAD ($)
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (561)	$ (546)
Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(561)	(546)
Level 3
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(148)
Level 3 | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(148)	$ (136)
Market approach valuation technique | Level 3 | Commodity contracts - financial | Natural gas | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (34)
Market approach valuation technique | Level 3 | Commodity contracts - financial | Natural gas | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MillionsofBTU-MMBTU	2.30
Market approach valuation technique | Level 3 | Commodity contracts - financial | Natural gas | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MillionsofBTU-MMBTU	10.29
Market approach valuation technique | Level 3 | Commodity contracts - financial | Natural gas | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MillionsofBTU-MMBTU	4.60
Market approach valuation technique | Level 3 | Commodity contracts - financial | Crude | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (12)
Market approach valuation technique | Level 3 | Commodity contracts - financial | Crude | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / bbl	72.61
Market approach valuation technique | Level 3 | Commodity contracts - financial | Crude | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / bbl	104.87
Market approach valuation technique | Level 3 | Commodity contracts - financial | Crude | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / bbl	92.25
Market approach valuation technique | Level 3 | Commodity contracts - financial | Power | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (92)
Market approach valuation technique | Level 3 | Commodity contracts - financial | Power | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MWh	25.07
Market approach valuation technique | Level 3 | Commodity contracts - financial | Power | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MWh	214.37
Market approach valuation technique | Level 3 | Commodity contracts - financial | Power | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MWh	70.68
Market approach valuation technique | Level 3 | Commodity contracts - physical | Natural gas | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (34)
Market approach valuation technique | Level 3 | Commodity contracts - physical | Natural gas | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MillionsofBTU-MMBTU	0.60
Market approach valuation technique | Level 3 | Commodity contracts - physical | Natural gas | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MillionsofBTU-MMBTU	8.14
Market approach valuation technique | Level 3 | Commodity contracts - physical | Natural gas | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MillionsofBTU-MMBTU	3.51
Market approach valuation technique | Level 3 | Commodity contracts - physical | Crude | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (9)
Market approach valuation technique | Level 3 | Commodity contracts - physical | Crude | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / bbl	74.97
Market approach valuation technique | Level 3 | Commodity contracts - physical | Crude | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / bbl	116.60
Market approach valuation technique | Level 3 | Commodity contracts - physical | Crude | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / bbl	91.05
Market approach valuation technique | Level 3 | Commodity contracts - physical | Power | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ 33
Market approach valuation technique | Level 3 | Commodity contracts - physical | Power | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MWh	13.30
Market approach valuation technique | Level 3 | Commodity contracts - physical | Power | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MWh	107.36
Market approach valuation technique | Level 3 | Commodity contracts - physical | Power | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price ($ / mmbtu, barrel, gallon, MW/H) | $ / MWh	55.46

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Changes in Level 3 (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Changes in net fair value of derivative assets and liabilities classified as Level 3
Level 3 net derivative liability at beginning of period	$ (136)	$ (108)
Total gain/(loss)
Included in earnings	(44)	(52)
Included in OCI	33	4
Settlements	(1)	(24)
Level 3 net derivative liability at end of period	$ (148)	$ (180)

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Other Financial Instruments (Details) - CAD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Fair Value of Other Financial Instruments
Unrealized gain or losses on the change in fair value of foreign exchange foreign contracts	$ 0	$ 0
Realized gain (loss) recognized in OCI associated with settlement of foreign exchange forward contracts	0	0
FMVA investments	209,000		$ 102,000
Restricted long-term investments	646,000		593,000
Long-term debt, carrying value	79,500,000		79,300,000
Long-term debt	74,900,000		73,500,000
Debt Securities
Fair Value of Other Financial Instruments
Debt securities, available-for-sale, amortized cost	303,000		295,000
Equity Funds And Debt Securities
Fair Value of Other Financial Instruments
Unrealized gain (loss) on lnvestments	15,000	(8,000)
Net investment hedges
Fair Value of Other Financial Instruments
Unrealized foreign exchange gain (loss) on translation of United States dollar denominated debt	59,000	133,000
Realized loss associated with the settlement of foreign exchange forward contracts	44,000	0
Level 1
Fair Value of Other Financial Instruments
Restricted long-term investments	249,000		236,000
Level 1 | Debt Securities
Fair Value of Other Financial Instruments
Fair value of investments	351,000		335,000
Level 2
Fair Value of Other Financial Instruments
Restricted long-term investments	397,000		357,000
Restricted long-term investments, cost basis	451,000		437,000
Level 2 | Debt Securities
Fair Value of Other Financial Instruments
Fair value of investments	309,000		298,000
Fair Value
Fair Value of Other Financial Instruments
Restricted long-term investments	646,000		593,000
Unrealized holding gains (losses)	34,000	$ (60,000)
Fair value note receivable	691,000		752,000
Carrying value
Fair Value of Other Financial Instruments
Non-current notes receivable	$ 691,000		$ 752,000

XML

INCOME TAXES (Details)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Income Tax Disclosure [Abstract]
Effective income tax rate (as a percent)	21.50%	22.40%

XML

OTHER INCOME (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Other Income and Expenses [Abstract]
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
Total	$ 102	$ 458

XML

SUBSEQUENT EVENT (Details) $ in Millions	Apr. 03, 2023 USD ($)
Subsequent event | Tres Palacios Holdings LLC
Subsequent Event [Line Items]
Cash	$ 335