Enbridge (ENB) 10-K 10 Feb 23 2022 FY Annual report Financial data

Cover

Cover - CAD ($) $ in Billions	12 Months Ended
	Dec. 31, 2022	Feb. 03, 2023	Jun. 30, 2022
Entity Listings [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
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
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
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
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 85.6
Entity Common Stock, Shares Outstanding		2,024,907,965
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE: Not applicable.
Entity Central Index Key	0000895728
Document Fiscal Year Focus	2022
Amendment Flag	false
Document Fiscal Period Focus	FY
Common Shares
Entity Listings [Line Items]
Title of 12(b) Security	Common Shares
Trading Symbol	ENB
Security Exchange Name	NYSE
6.375% Fixed-to-Floating Rate Subordinated Notes Series 2018-B due 2078
Entity Listings [Line Items]
Title of 12(b) Security	6.375% Fixed-to-Floating Rate Subordinated Notes Series 2018-B due 2078
Trading Symbol	ENBA
Security Exchange Name	NYSE

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Firm ID	271
Auditor Location	Calgary, Canada

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) $ / shares	Dec. 31, 2021 CAD ($) $ / shares	Dec. 31, 2020 CAD ($) $ / shares
Operating revenues
Total operating revenues (Note 4)	$ 53,309	$ 47,071	$ 39,087
Operating expenses
Operating and administrative	8,219	6,712	6,749
Depreciation and amortization	4,317	3,852	3,712
Impairment of long-lived assets	541	0	0
Impairment of goodwill (Note 16)	2,465	0	0
Total operating expenses	48,131	39,266	31,130
Operating income	5,178	7,805	7,957
Income from equity investments (Note 13)	2,056	1,711	1,136
Impairment of equity investments (Note 13)	0	(111)	(2,351)
Gain on joint venture merger transaction (Note 13)	1,076	0	0
Other income/(expense) (Note 28)	(589)	979	238
Interest expense (Note 18)	(3,179)	(2,655)	(2,790)
Earnings before income taxes	4,542	7,729	4,190
Income tax expense (Note 25)	(1,604)	(1,415)	(774)
Earnings	2,938	6,314	3,416
(Earnings)/loss attributable to noncontrolling interests	65	(125)	(53)
Earnings attributable to controlling interests	3,003	6,189	3,363
Preference share dividends	(414)	(373)	(380)
Earnings attributable to common shareholders	$ 2,589	$ 5,816	$ 2,983
Earnings per common share attributable to common shareholders (in CAD per share) | $ / shares	$ 1.28	$ 2.87	$ 1.48
Diluted earnings per common share attributable to common shareholders (in CAD per share) | $ / shares	$ 1.28	$ 2.87	$ 1.48
Commodity sales
Operating revenues
Total operating revenues (Note 4)	$ 29,150	$ 26,873	$ 19,259
Operating expenses
Commodity costs and Gas distribution costs	28,942	26,608	18,890
Gas distribution revenue
Operating revenues
Total operating revenues (Note 4)	5,653	4,026	3,663
Operating expenses
Commodity costs and Gas distribution costs	3,647	2,094	1,779
Transportation and other services
Operating revenues
Total operating revenues (Note 4)	$ 18,506	$ 16,172	$ 16,165

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Earnings	$ 2,938	$ 6,314	$ 3,416
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	847	162	(457)
Change in unrealized gain/(loss) on net investment hedges	(971)	49	102
Other comprehensive loss from equity investees	(6)	(12)	(1)
Excluded components of fair value hedges	(35)	(5)	5
Reclassification to earnings of loss on cash flow hedges	143	235	198
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(10)	21	13
Reclassification to earnings of (gain)/loss on equity investees	16	(62)	0
Actuarial gain/(loss) on pension and OPEB	312	394	(167)
Foreign currency translation adjustments	4,406	(507)	(853)
Other comprehensive income/(loss), net of tax	4,702	275	(1,160)
Comprehensive income	7,640	6,589	2,256
Comprehensive income attributable to noncontrolling interests	(21)	(95)	(22)
Comprehensive income attributable to controlling interests	7,619	6,494	2,234
Preference share dividends	(414)	(373)	(380)
Comprehensive income attributable to common shareholders	$ 7,205	$ 6,121	$ 1,854

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - CAD ($) $ in Millions	Total	Preference shares (Note 21)	Common shares (Note 21)	Additional paid-in capital	Deficit	Deficit Modified Retrospective Adoption Of ASC	Accumulated other comprehensive income/(loss) (Note 23)	Reciprocal shareholding	Total Enbridge Inc. shareholders’ equity	Noncontrolling interests (Note 20)
Balance at beginning of year at Dec. 31, 2019		$ 7,747	$ 64,746	$ 187	$ (6,314)		$ (272)	$ (51)		$ 3,364
Increase (Decrease) in Stockholders' Equity
Redemption of preference shares		0
Shares issued on exercise of stock options			22	(21)
Share purchases at stated value	$ 0		0
Other			0		(3)					(1)
Stock-based compensation				30
Purchase of noncontrolling interest				0
Change in reciprocal interest				76				22
Other	0			5
Earnings/(loss) attributable to controlling interests	$ 3,363				3,363
Preference share dividends					(380)
Common share dividends declared					(6,612)
Dividends paid to reciprocal shareholder					17
Accounting Standards Update [Extensible List]	Accounting Standards Update 2016-13 [Member]
Share purchases in excess of stated value					0
Other comprehensive income/(loss) attributable to common shareholders, net of tax							(1,129)
Earnings/(loss) attributable to noncontrolling interests										53
Change in unrealized loss on cash flow hedges										(6)
Foreign currency translation adjustments										(25)
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax										(31)
Comprehensive income attributable to noncontrolling interests	$ (22)									22
Distributions										(300)
Contributions										23
Redemption of noncontrolling interests										(112)
Purchase of noncontrolling interest										0
Balance at end of year at Dec. 31, 2020	$ 64,363	7,747	64,768	277	(9,995)	$ (66)	(1,401)	(29)	$ 61,367	2,996
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in CAD per share)	$ 3.24
Redemption of preference shares		0
Shares issued on exercise of stock options			31	(23)
Share purchases at stated value	$ 0		0
Other			0		0					0
Stock-based compensation				28
Purchase of noncontrolling interest				0
Change in reciprocal interest				98				29
Other	0			(15)
Earnings/(loss) attributable to controlling interests	6,189				6,189
Preference share dividends					(373)
Common share dividends declared					(6,818)
Dividends paid to reciprocal shareholder					8
Share purchases in excess of stated value					0
Other comprehensive income/(loss) attributable to common shareholders, net of tax							305
Earnings/(loss) attributable to noncontrolling interests										125
Change in unrealized loss on cash flow hedges										(15)
Foreign currency translation adjustments										(15)
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax										(30)
Comprehensive income attributable to noncontrolling interests	(95)									95
Distributions										(271)
Contributions										15
Redemption of noncontrolling interests										(293)
Purchase of noncontrolling interest										0
Balance at end of year at Dec. 31, 2021	$ 63,368	7,747	64,799	365	(10,989)	$ 0	(1,096)	0	60,826	2,542
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in CAD per share)	$ 3.34
Redemption of preference shares		(929)
Shares issued on exercise of stock options			53	(50)
Share purchases at stated value	$ (88)		(88)
Other			(4)		0					47
Stock-based compensation				36
Purchase of noncontrolling interest				(43)
Change in reciprocal interest				0				0
Other	(4)			(33)
Earnings/(loss) attributable to controlling interests	3,003				3,003
Preference share dividends					(414)
Common share dividends declared					(7,023)
Dividends paid to reciprocal shareholder					0
Share purchases in excess of stated value					(63)
Other comprehensive income/(loss) attributable to common shareholders, net of tax							4,616
Earnings/(loss) attributable to noncontrolling interests										(65)
Change in unrealized loss on cash flow hedges										(28)
Foreign currency translation adjustments										114
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax										86
Comprehensive income attributable to noncontrolling interests	(21)									21
Distributions										(259)
Contributions										1,105
Redemption of noncontrolling interests										0
Purchase of noncontrolling interest										55
Balance at end of year at Dec. 31, 2022	$ 63,398	$ 6,818	$ 64,760	$ 275	$ (15,486)		$ 3,520	$ 0	$ 59,887	$ 3,511
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in CAD per share)	$ 3.44

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)
Operating activities
Earnings	$ 2,938	$ 6,314	$ 3,416
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	4,317	3,852	3,712
Deferred income tax expense (Note 25)	957	1,091	447
Unrealized derivative fair value (gain)/loss, net (Note 24)	1,280	(173)	(756)
Income from equity investments (Note 13)	(2,056)	(1,711)	(1,136)
Distributions from equity investments	1,827	1,630	1,392
Impairment of long-lived assets	541	0	0
Impairment of equity investments (Note 13)	0	111	2,351
Impairment of goodwill (Note 16)	2,465	0	0
Gain on joint venture merger transaction (Note 13)	(1,076)	0	0
(Gain)/loss on dispositions	12	(319)	(6)
Other	37	(73)	268
Changes in operating assets and liabilities (Note 29)	(12)	(1,466)	93
Net cash provided by operating activities	11,230	9,256	9,781
Investing activities
Capital expenditures	(4,647)	(7,818)	(5,405)
Long-term investments and restricted long-term investments	(1,041)	(640)	(487)
Distributions from equity investments in excess of cumulative earnings	763	533	705
Additions to intangible assets	(174)	(275)	(215)
Acquisitions	(828)	(3,785)	(24)
Proceeds from joint venture merger transaction (Note 13)	522	0	0
Proceeds from dispositions	0	1,263	265
Affiliate loans, net	135	65	(16)
Net cash used in investing activities	(5,270)	(10,657)	(5,177)
Financing activities
Net change in short-term borrowings	481	394	223
Net change in commercial paper and credit facility draws	(1,333)	2,960	1,542
Debenture and term note issues, net of issue costs	7,547	8,032	5,230
Debenture and term note repayments	(4,198)	(2,264)	(4,463)
Sale of noncontrolling interest in subsidiary (Note 8)	1,092	0	0
Contributions from noncontrolling interests	13	15	23
Distributions to noncontrolling interests	(259)	(271)	(300)
Common shares issued	3	5	5
Common shares repurchased	(151)	0	0
Preference share dividends	(338)	(367)	(380)
Common share dividends	(6,968)	(6,766)	(6,560)
Redemption of preference shares	(1,003)	0	0
Redemption of preferred shares held by subsidiary	0	(415)	0
Other	(314)	(87)	(90)
Net cash provided by/(used in) financing activities	(5,428)	1,236	(4,770)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	55	(5)	(20)
Net change in cash and cash equivalents and restricted cash	587	(170)	(186)
Cash and cash equivalents and restricted cash at beginning of year	320	490	676
Cash and cash equivalents and restricted cash at end of year	907	320	490
Supplementary cash flow information
Cash paid for income taxes	495	489	524
Cash paid for interest, net of amount capitalized	2,920	2,427	2,538
Property, plant and equipment and intangible assets non-cash accruals	$ 937	$ 831	$ 801

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 861	$ 286
Restricted cash	46	34
Accounts receivable and other (Note 9)	8,871	6,862
Accounts receivable from affiliates	114	107
Inventory (Note 10)	2,255	1,670
Current assets	12,147	8,959
Property, plant and equipment, net (Note 11)	104,460	100,067
Long-term investments (Note 13)	15,936	13,324
Restricted long-term investments (Note 14)	593	630
Deferred amounts and other assets	9,542	8,613
Intangible assets, net (Note 15)	4,018	4,008
Goodwill (Note 16)	32,440	32,775
Deferred income taxes (Note 25)	472	488
Total assets	179,608	168,864
Current liabilities
Short-term borrowings (Note 18)	1,996	1,515
Accounts payable and other (Note 17)	11,392	9,767
Accounts payable to affiliates	105	90
Interest payable	763	693
Current portion of long-term debt (Note 18)	6,045	6,164
Current liabilities	20,301	18,229
Long-term debt (Note 18)	72,939	67,961
Other long-term liabilities	9,189	7,617
Deferred income taxes (Note 25)	13,781	11,689
Liabilities	116,210	105,496
Commitments and contingencies (Note 31)
Share capital
Preference shares	6,818	7,747
Common shares (2,025 and 2,026 outstanding at December 31, 2022 and 2021, respectively)	64,760	64,799
Additional paid-in capital	275	365
Deficit	(15,486)	(10,989)
Accumulated other comprehensive income/(loss) (Note 23)	3,520	(1,096)
Total Enbridge Inc. shareholders’ equity	59,887	60,826
Noncontrolling interests (Note 20)	3,511	2,542
Equity	63,398	63,368
Total liabilities and equity	$ 179,608	$ 168,864

CONSOLIDATED STATEMENTS OF FI_2

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	2,025	2,026

BUSINESS OVERVIEW

BUSINESS OVERVIEW	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BUSINESS OVERVIEW	BUSINESS OVERVIEW 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. Enbridge is a publicly traded energy transportation and distribution company. We conduct our business through five business segments: Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation, and Energy Services. These reporting segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance. LIQUIDS PIPELINES Liquids Pipelines consists of pipelines and terminals in Canada and the United States (US) that transport and export various grades of crude oil and other liquid hydrocarbons, including the Mainline System, Regional Oil Sands System, Gulf Coast and Mid-Continent, and Other. This segment also includes Moda Midstream Operating, LLC (Moda), which was acquired on October 12, 2021 (Note 8) and is a component of Gulf Coast and Mid-Continent. GAS TRANSMISSION AND MIDSTREAM Gas Transmission and Midstream consists of our investments in natural gas pipelines and gathering and processing facilities in Canada and the US, including US Gas Transmission, Canadian Gas Transmission, US Midstream, and Other. GAS DISTRIBUTION AND STORAGE Gas Distribution and Storage consists of our natural gas utility operations, the core of which is Enbridge Gas Inc. (Enbridge Gas), which serves residential, commercial and industrial customers throughout Ontario. This business segment also includes natural gas distribution activities in Québec. We sold our investment in Noverco Inc. (Noverco), previously reported in the Gas Distribution and Storage segment, to Trencap L.P. on December 30, 2021 (Note 13) . RENEWABLE POWER GENERATION Renewable Power Generation consists primarily of investments in wind and solar assets, as well as geothermal, waste heat recovery, and transmission assets. In North America, assets are primarily located in the provinces of Alberta, Saskatchewan, Ontario and Québec, and in the states of Colorado, Texas, Indiana and West Virginia. We also have offshore wind assets in operation and under development in the United Kingdom, Germany and France. This segment also includes Tri Global Energy, LLC (TGE) which was acquired on September 27, 2022 (Note 8). ENERGY SERVICES Our Energy Services businesses in Canada and the US undertake physical commodity marketing activity and logistical services to manage our volume commitments on various pipeline systems. Energy Services also provides energy marketing services to North American refiners, producers and other customers. ELIMINATIONS AND OTHER In addition to the segments described above, Eliminations and Other includes operating and administrative costs that are not allocated to business segments, the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. The principal activity of our captive insurance subsidiaries is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. Eliminations and Other also includes new business development activities and corporate investments.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
SIGNIFICANT ACCOUNTING POLICIES	SIGNIFICANT ACCOUNTING POLICIES These consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (US GAAP). Amounts are stated in Canadian dollars unless otherwise noted. As a Securities and Exchange Commission (SEC) registrant, we are permitted to use US GAAP for the purposes of meeting both our Canadian and US continuous disclosure requirements. BASIS OF PRESENTATION AND USE OF ESTIMATES The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: variable consideration included in revenue (Note 4) ; carrying values of regulatory assets and liabilities (Note 7) ; purchase price allocations (Note 8) ; unbilled revenues; expected credit losses; depreciation rates and carrying value of property, plant and equipment (Note 11) ; amortization rates and carrying value of intangible assets (Note 15) ; measurement of goodwill (Note 16) ; fair value of asset retirement obligations (ARO) (Note 19) ; valuation of stock-based compensation (Note 22) ; fair value of financial instruments (Note 24) ; provisions for income taxes (Note 25) ; assumptions used to measure retirement benefits and OPEB (Note 26) ; commitments and contingencies (Note 31) ; and estimates of losses related to environmental remediation obligations (Note 31) . Actual results could differ from these estimates. Certain comparative figures in our consolidated financial statements have been reclassified to conform to the current year's presentation. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include our accounts and the accounts of our subsidiaries and VIEs for which we are the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. Where we conclude that we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are the primary beneficiary. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. We assess the primary beneficiary determination for a VIE on an ongoing basis if there are changes in the facts and circumstances related to a VIE. If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity. The consolidated financial statements also include the accounts of any limited partnerships where we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses. All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method. REGULATION Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the Canada Energy Regulator (CER), the Federal Energy Regulatory Commission (FERC), the Alberta Energy Regulator, the Ontario Energy Board (OEB) and la Régie de l’energie du Québec. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under US GAAP for non-rate-regulated entities. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or to be paid to cover future abandonment costs in relation to the CER’s Land Matters Consultation Initiative (LMCI). Regulatory assets are assessed for impairment if we identify an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. We believe that the recovery of our regulatory assets as at December 31, 2022 is probable over the periods described in Note 7 - Regulatory Matters . Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. The corresponding impact on earnings is included in Interest expense for the interest component and Other income/(expense) for the equity component. In the absence of rate regulation, we would capitalize interest using a capitalization rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation relating to the equity component would not be recognized. The equity component of AFUDC is included as a non-cash reconciling item to earnings within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows. Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains and losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified. With the approval of regulators, certain operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred . For certain regulated operations to which US GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with US GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with US GAAP and no regulatory asset is recorded. REVENUE RECOGNITION For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer creditworthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from our liquids and natural gas pipeline businesses are recognized under the terms of committed delivery contracts, rather than the cash tolls received. Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts ratably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry. We recognize revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote. We also have long-term contracts where the revenue profile does not align with the cash receipt schedule, resulting in the recognition of deferred revenue. Certain offshore pipeline transportation contracts require us to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay us a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received. For the years ended December 31, 2022, 2021 and 2020, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $238 million, $127 million and $292 million, respectively. For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Natural gas utility revenues are recorded based on regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in our distribution franchise areas. Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded on a gross basis as the related contracts are not held for trading purposes and we are acting as the principal in the transactions. No non-affiliated customer exceeded 10.0% of our third-party revenues for the year ended December 31, 2022. Our largest non-affiliated customer accounted for approximately 13.5% and 13.6% of our third-party revenues for the years ended December 31, 2021 and 2020, respectively. DERIVATIVE INSTRUMENTS AND HEDGING Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Commodity sales, Transportation and other services revenue, Commodity costs, Operating and administrative expense, Other income/(expense) and Interest expense. Derivatives in Qualifying Hedging Relationships We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires us to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges. Cash Flow Hedges We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. The change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income/(loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings. If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized in earnings concurrently with the related transaction. If an anticipated hedged transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. Fair Value Hedges We may use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged risk of the asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged risk of the asset or liability ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. Net Investment Hedges Gains and losses arising from the translation of our net investment in foreign operations from their functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA), a component of OCI. We currently have designated a portion of our US dollar-denominated debt, as well as a portfolio of foreign exchange forward contracts in prior periods, as a hedge of our net investment in US dollar-denominated investments and subsidiaries. As a result, the change in fair value of the foreign currency derivatives, as well as the translation of US dollar-denominated debt, are reflected in OCI. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from the disposal of a foreign operation. Classification of Derivatives We recognize the fair value of derivative instruments in the Consolidated Statements of Financial Position as current and non-current assets or liabilities depending on the timing of settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows. Balance Sheet Offset Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when we have the legal right and intention to settle them on a net basis. Transaction Costs Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and account for these costs as a reduction to Long-term debt in the Consolidated Statements of Financial Position. These costs are amortized using the effective interest rate method over the term of the related debt instrument and are recorded in Interest expense. EQUITY INVESTMENTS Equity investments over which we exercise significant influence, but do not have controlling financial interests, are accounted for using the equity method. These investments are initially measured at cost and are adjusted for our proportionate share of undistributed equity earnings or loss. Our equity investments are increased for contributions made to, and decreased for distributions received from, the investee. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, we capitalize interest costs associated with the investment during such period. RESTRICTED LONG-TERM INVESTMENTS Long-term investments that are restricted as to withdrawal or usage for the purposes of the CER’s LMCI are presented as Restricted long-term investments in the Consolidated Statements of Financial Position. OTHER INVESTMENTS Generally, we classify equity investments in entities over which we do not exercise significant influence and that do not have readily determinable fair values as other investments measured using the fair value measurement alternative (FVMA). These investments are recorded at cost less impairment, if any, and adjusted for the impact of observable price changes occurring in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the FVMA are reviewed for impairment each reporting period and written down to their fair value if objective evidence of impairment is identified. Equity investments with readily determinable fair values are measured at fair value through earnings. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established. Investments in debt securities are classified as available-for-sale and measured at fair value through OCI. NONCONTROLLING INTERESTS Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us in such entities is reflected as Noncontrolling interests within the equity section of the Consolidated Statements of Financial Position. INCOME TAXES Income taxes are accounted for using the liability method. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, to the extent that taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income tax expense. FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated to the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the exchange rate in effect as at the balance sheet date. Exchange gains and losses resulting from the translation of monetary assets and liabilities are included in earnings in the period in which they arise. Gains and losses arising from the translation of foreign operations' functional currencies to our Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect as at the balance sheet date, while revenues and expenses are translated using monthly average exchange rates. CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased. RESTRICTED CASH Cash and cash equivalents that are restricted as to withdrawal or usage for the purposes of the CER’s LMCI or in accordance with specific commercial arrangements are presented as Restricted cash in the Consolidated Statements of Financial Position. LOANS AND RECEIVABLES Long-term notes receivable from affiliates are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. Interest income is recognized in earnings as it is earned with the passage of time. CURRENT EXPECTED CREDIT LOSSES For accounts receivable, a loss allowance matrix is utilized to measure lifetime expected credit losses. The matrix contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations. Other loan receivables and applicable off-balance sheet commitments utilize a discounted cash flow methodology which calculates the current expected credit losses based on historical default probability rates associated with the credit rating of the counterparty and the related term of the loan or commitment, adjusted for forward-looking information and management expectations. NATURAL GAS IMBALANCES The Consolidated Statements of Financial Position include balances as a result of differences in gas volumes received from, and delivered for, customers. As settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates. INVENTORY Inventory is comprised of natural gas held in storage by Enbridge Gas, crude oil and natural gas held primarily by businesses in the Energy Services segment and materials and supplies. Natural gas held in storage by Enbridge Gas is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of gas purchased is deferred as a liability for future refund, or as an asset for collection, as approved by the OEB. Other inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs in the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value. Materials and supplies inventory is recorded at the lower of average cost or net realizable value. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. We capitalize interest incurred during construction for non-rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation. LEASES We recognize an arrangement as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We recognize right-of-use (ROU) assets and the related lease liabilities in the Consolidated Statements of Financial Position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach applied for other long-lived assets. Lease liabilities and ROU assets require the use of judgment and estimates which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing. DEFERRED AMOUNTS AND OTHER ASSETS Deferred amounts and other assets primarily consists of costs that regulatory authorities have permitted, or are expected to permit, to be recovered through future rates, including: deferred income taxes; the fair value adjustment to long-term debt; actual cost of removal of previously retired or decommissioned plant assets; the difference between the actual cost and approved cost of natural gas reflected in rates; and actuarial gains and losses arising from defined benefit pension plans. INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects . Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due. GOODWILL Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1. We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components, and whether the economic and regulatory characteristics are similar. Our reporting units are Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation. The Renewable Power Generation reporting unit had goodwill beginning in the third quarter of 2022. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, the assessment of macroeconomic trends, changes to regulatory environments, capital accessibility, operating income trends and changes to industry conditions. Based on our assessment of qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment assessment is performed. The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. The fair value of our reporting units is estimated using a combination of discounted cash flow and earnings multiples techniques. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, expected future capital expenditures and working capital levels, as well as terminal value growth rates for the Liquids Pipelines, Gas Transmission and Renewable Power Generation reporting units, and projected regulatory rate base and rate base multiple for the Gas Distribution and Storage reporting unit. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multiples for reporting units. The allocation of goodwill to held-for-sale and disposed businesses is based on the relative fair value of businesses included in the relevant reporting unit. On April 1, 2022, we performed our annual goodwill impairment assessment which consisted of a qualitative assessment for the Liquids Pipelines, Gas Transmission and Gas Distribution and Storage reporting units and did not identify impairment indicators. Due to changes in the macroeconomic environment that have led to a rise in interest rates, we performed a quantitative assessment for the Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation reporting units as at December 1, 2022, which resulted in the recognition of an impairment loss for Gas Transmission (Note 16) . Goodwill impairments were not identified in relation to the Liquids Pipelines, Gas Distribution and Storage or Renewable Power Generation reporting units. Also, we did not identify any indicators of goodwill impairment during the remainder of 2022. IMPAIRMENT We review the carrying values of our long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds its expected undiscounted cash flows, we will calculate fair value based on the discounted cash flows and write the asset down to the extent that the carrying value exceeds the fair value. With respect to investments in debt securities and equity investments, we assess at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we value the expected discounted cash flows using observable market inputs. We determine whether the decline below carrying value is other-than-temporary for equity method investments or is due to a credit loss for investments in debt securities. If the decline is determined to be other-than-temporary for equity method investments or is due to a credit loss for investments in debt securities, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset. ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilitie

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2022
Accounting Standards Update and Change in Accounting Principle [Abstract]
CHANGES IN ACCOUNTING POLICIES	CHANGES IN ACCOUNTING POLICIES CHANGES IN ACCOUNTING POLICIES There were no changes in accounting policies during the year ended December 31, 2022. ADOPTION OF NEW ACCOUNTING STANDARDS Disclosures About Government Assistance Effective January 1, 2022, we adopted Accounting Standards Update (ASU) 2021-10 on a prospective basis. The new standard was issued in November 2021 to increase the transparency of government assistance to business entities. The ASU adds new disclosure requirements for transactions with governments that are accounted for using a grant or contribution accounting model by analogy. The required disclosures include information about the nature of transactions, accounting policy applied, impacted financial statement line items and significant terms and conditions. The adoption of this ASU did not have a material impact on our consolidated financial statements. Accounting for Certain Lessor Leases with Variable Lease Payments Effective January 1, 2022, we adopted ASU 2021-05 on a prospective basis. The new standard was issued in July 2021 to amend lessor accounting for certain leases with variable lease payments that do not depend on a reference index or a rate and would have resulted in the recognition of a loss at lease commencement if classified as a sales-type or a direct financing lease. The ASU amends the classification requirements of such leases for lessors to result in an operating lease classification. The adoption of this ASU did not have a material impact on our consolidated financial statements. Accounting for Modifications or Exchanges of Certain Equity-Classified Contracts Effective January 1, 2022, we adopted ASU 2021-04 on a prospective basis. The new standard was issued in May 2021 to clarify issuer accounting for modifications or exchanges of freestanding equity-classified written call options that remain equity classified after modification or exchange. The ASU requires an issuer to determine the accounting for the modification or exchange based on the economic substance of the modification or exchange. The adoption of this ASU did not have a material impact on our consolidated financial statements. Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity Effective January 1, 2022, we adopted ASU 2020-06 on a modified retrospective basis. The new standard was issued in August 2020 to simplify accounting for certain financial instruments. The ASU eliminates the current models that require separation of beneficial conversion and cash conversion features from convertible instruments and simplifies the derivative scope exception guidance pertaining to equity classification of contracts in an entity’s own equity. The ASU also introduces additional disclosures for convertible debt and freestanding instruments that are indexed to and settled in an entity’s own equity. The ASU amends the diluted earnings per share guidance, including the requirement to use if-converted method for all convertible instruments and an update for instruments that can be settled in either cash or shares. The adoption of this ASU did not have a material impact on our consolidated financial statements.

REVENUE

REVENUE	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE REVENUE FROM CONTRACTS WITH CUSTOMERS Major Products and Services Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2022 (millions of Canadian dollars) Transportation revenue 11,283 5,012 782 — — — 17,077 Storage and other revenue 235 350 308 — — — 893 Gas gathering and processing revenue — 22 — — — — 22 Gas distribution revenue — — 5,643 — — — 5,643 Electricity and transmission revenue — — — 281 — — 281 Total revenue from contracts with customers 11,518 5,384 6,733 281 — — 23,916 Commodity sales — — — — 29,150 — 29,150 Other revenue 1,2 (81) 39 (20) 305 — — 243 Intersegment revenue 615 3 16 (4) 25 (655) — Total revenue 12,052 5,426 6,729 582 29,175 (655) 53,309 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2021 (millions of Canadian dollars) Transportation revenue 9,492 4,364 676 — — — 14,532 Storage and other revenue 147 255 246 — — — 648 Gas gathering and processing revenue — 49 — — — — 49 Gas distribution revenue — — 4,026 — — — 4,026 Electricity and transmission revenue — — — 177 — — 177 Total revenue from contracts with customers 9,639 4,668 4,948 177 — — 19,432 Commodity sales — — — — 26,873 — 26,873 Other revenue 1,2 375 42 13 336 — — 766 Intersegment revenue 567 1 19 (1) 44 (630) — Total revenue 10,581 4,711 4,980 512 26,917 (630) 47,071 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2020 (millions of Canadian dollars) Transportation revenue 9,161 4,523 674 — — — 14,358 Storage and other revenue 94 274 203 — — — 571 Gas gathering and processing revenue — 27 — — — — 27 Gas distribution revenue — — 3,663 — — — 3,663 Electricity and transmission revenue — — — 198 — — 198 Total revenue from contracts with customers 9,255 4,824 4,540 198 — — 18,817 Commodity sales — — — — 19,259 — 19,259 Other revenue 1,2 584 44 17 389 — (23) 1,011 Intersegment revenue 584 2 12 — 24 (622) — Total revenue 10,423 4,870 4,569 587 19,283 (645) 39,087 1 Includes mark-to-market losses from our hedging program 2 Includes revenues from lease contracts. Refer to Note 27 - Leases . 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 December 31, 2022 3,183 230 2,241 Balance as at December 31, 2021 2,369 213 1,898 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 year ended December 31, 2022 included in contract liabilities at the beginning of the year is $166 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2022, were $453 million. Performance Obligations Segment Nature of Performance Obligation Liquids Pipelines • Transportation and storage of crude oil and natural gas liquids (NGL) Gas Transmission and Midstream • Transportation, storage, gathering, compression and treating of natural gas • Transportation of NGL • Sale of crude oil, natural gas and NGL Gas Distribution and Storage • Supply and delivery of natural gas • Transportation of natural gas • Storage of natural gas Renewable Power Generation • Generation and transmission of electricity • Delivery of electricity from renewable energy generation facilities There was no material revenue recognized during the year ended December 31, 2022 from performance obligations satisfied in previous periods. Payment Terms Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution and Storage customers are received on a continuous basis based on established billing cycles. Certain contracts in our US offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period that is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs are recorded as contract liabilities. The FMPs are not considered to be a financing arrangement as payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives. Revenue to be Recognized from Unfulfilled Performance Obligations Total revenue from performance obligations expected to be fulfilled in future periods is $58.6 billion, of which $7.6 billion is expected to be recognized during the year ending December 31, 2023. 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 of 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. SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE Long-Term Transportation Agreements For long-term transportation agreements, significant judgments pertain to the period over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed. Variable Consideration Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes are sold or transported and actual tolls and prices are determined. During the year ended December 31, 2022, revenue for the Canadian Mainline has been recognized in accordance with the terms of the Competitive Toll Settlement (CTS), 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 CER decision and potential customer negotiations, interim toll revenue recognized during the year ended December 31, 2022 is considered variable consideration. Recognition and Measurement of Revenue Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2022 (millions of Canadian dollars) Revenue from products transferred at a point in time — — 127 — 127 Revenue from products and services transferred over time 1 11,518 5,384 6,606 281 23,789 Total revenue from contracts with customers 11,518 5,384 6,733 281 23,916 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2021 (millions of Canadian dollars) Revenue from products transferred at a point in time — — 70 — 70 Revenue from products and services transferred over time 1 9,639 4,668 4,878 177 19,362 Total revenue from contracts with customers 9,639 4,668 4,948 177 19,432 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2020 (millions of Canadian dollars) Revenue from products transferred at a point in time — — 60 — 60 Revenue from products and services transferred over time 1 9,255 4,824 4,480 198 18,757 Total revenue from contracts with customers 9,255 4,824 4,540 198 18,817 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. Performance Obligations Satisfied Over Time For arrangements involving the transportation and sale of petroleum products and natural gas where the transportation services or commodities are simultaneously received and consumed by the shipper or customer, we recognize revenue over time using an output method based on volumes of commodities delivered or transported. The measurement of the volumes transported or delivered corresponds directly to the benefits received by the shippers or customers during that period. Determination of Transaction Prices Prices for transportation and gas processing services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services, plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation. Prices for commodities sold are determined by reference to market price indices, plus or minus a negotiated differential and in certain cases a marketing fee. Prices for natural gas sold and distribution services provided by regulated natural gas distribution operations are prescribed by regulation.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION Segmented information for the years ended December 31, 2022, 2021 and 2020 is as follows: Year ended December 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) Revenues (Note 4) 12,052 5,426 6,729 582 29,175 (655) 53,309 Commodity and gas distribution costs — — (3,693) (16) (29,525) 645 (32,589) Operating and administrative (4,287) (2,254) (1,289) (255) (49) (85) (8,219) Impairment of long-lived assets (245) — — (235) (13) (48) (541) Impairment of goodwill (Note 16) — (2,465) — — — — (2,465) Income/(loss) from equity investments (Note 13) 785 1,133 1 141 — (4) 2,056 Gain on joint venture merger transaction (Note 13) — 1,076 — — — — 1,076 Other income/(expense) (Note 28) 59 210 79 45 (5) (977) (589) Earnings/(loss) before interest, income taxes and depreciation and amortization 8,364 3,126 1,827 262 (417) (1,124) 12,038 Depreciation and amortization (4,317) Interest expense (Note 18) (3,179) Income tax expense (Note 25) (1,604) Earnings 2,938 Capital expenditures 1 1,418 1,690 1,499 50 — 33 4,690 Total property, plant and equipment, net (Note 11) 53,567 29,666 17,857 3,082 6 282 104,460 Year ended December 31, 2021 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues (Note 4) 10,581 4,711 4,980 512 26,917 (630) 47,071 Commodity and gas distribution costs (25) — (2,147) — (27,174) 644 (28,702) Operating and administrative (3,431) (1,877) (1,143) (180) (48) (33) (6,712) Income/(loss) from equity investments (Note 13) 759 813 42 101 — (4) 1,711 Impairment of equity investments (Note 13) — (111) — — — — (111) Other income/(expense) (Note 28) 13 135 385 75 (8) 379 979 Earnings/(loss) before interest, income taxes and depreciation and amortization 7,897 3,671 2,117 508 (313) 356 14,236 Depreciation and amortization (3,852) Interest expense (Note 18) (2,655) Income tax expense (Note 25) (1,415) Earnings 6,314 Capital expenditures 1 4,051 2,420 1,343 16 1 54 7,885 Total property, plant and equipment, net (Note 11) 52,530 27,028 16,904 3,315 23 267 100,067 Year ended December 31, 2020 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues (Note 4) 10,423 4,870 4,569 587 19,283 (645) 39,087 Commodity and gas distribution costs (20) — (1,810) (2) (19,450) 613 (20,669) Operating and administrative (3,331) (1,859) (1,091) (191) (67) (210) (6,749) Income/(loss) from equity investments (Note 13) 558 479 9 94 (3) (1) 1,136 Impairment of equity investments (Note 13) — (2,351) — — — — (2,351) Other income/(expense) (Note 28) 53 (52) 71 35 1 130 238 Earnings/(loss) before interest, income taxes and depreciation and amortization 7,683 1,087 1,748 523 (236) (113) 10,692 Depreciation and amortization (3,712) Interest expense (Note 18) (2,790) Income tax expense (Note 25) (774) Earnings 3,416 Capital expenditures 1 2,033 2,130 1,134 81 2 90 5,470 Total property, plant and equipment, net 48,799 25,745 16,079 3,495 24 429 94,571 1 Includes allowance for equity funds used during construction. The measurement basis for preparation of segmented information is consistent with the significant accounting policies (Note 2) . GEOGRAPHIC INFORMATION Revenues 1 Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Canada 27,498 20,474 16,453 US 25,811 26,597 22,634 53,309 47,071 39,087 1 Revenues are based on the country of origin of the product or service sold. Property, Plant and Equipment 1 December 31, 2022 2021 (millions of Canadian dollars) Canada 47,602 47,102 US 56,858 52,965 104,460 100,067 1 Amounts are based on the location where the assets are held.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
EARNINGS PER COMMON SHARE	EARNINGS PER COMMON SHARE BASIC Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. On December 30, 2021, we closed the sale of our minority ownership in Noverco. The weighted average number of common shares outstanding was reduced by our pro-rata weighted average interest in our own common shares of approximately 2 million and 5 million as at December 31, 2021 and 2020, respectively, resulting from our reciprocal investment in Noverco. 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: December 31, 2022 2021 2020 (number of shares in millions) Weighted average shares outstanding 2,025 2,023 2,020 Effect of dilutive options and RSUs 4 2 1 Diluted weighted average shares outstanding 2,029 2,025 2,021 For the years ended December 31, 2022, 2021 and 2020, 10.4 million, 18.6 million and 29.8 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $56.49, $52.89 and $51.42, respectively, were excluded from the diluted earnings per common share calculation.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2022
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS We record assets and liabilities that result from regulated ratemaking processes that would not be recorded under US GAAP for non-regulated entities. See Note 2 - Significant Accounting Policies for further discussion. Our significant regulated businesses and the related accounting impacts are described below. Under the current authorized rate structure for certain operations, income tax costs are recovered in rates based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of temporary differences that created the deferred income taxes, it is expected that rates will be adjusted to recover these taxes. Since most of these temporary differences are related to property, plant and equipment costs, this recovery is expected to occur over the life of the related assets. In the absence of rate-regulated accounting, this regulatory Deferred income taxes balance and the related earnings impact would not be recorded. LIQUIDS PIPELINES Canadian Mainline Canadian Mainline includes the Canadian portion of our mainline system and is subject to regulation by the CER. Tolls, excluding Lines 8 and 9, are governed by the 10-year CTS which expired on June 30, 2021. The tolls in place on June 30, 2021 continue on an interim basis until new tolls are finalized and approved by the CER (Note 4). The CTS established a Canadian Local Toll for all volumes shipped on the Canadian Mainline and an International Joint Tariff for all volumes shipped from western Canadian receipt points to delivery points on our Lakehead System. Under the CTS, we have recognized a regulatory asset of $2.1 billion a s at December 31, 2022 (2021 - $2.1 billion) to offset deferred income taxes, as a CER rate order governing flow-through income tax treatment permits future recovery. No other material regulatory assets or liabilities are recognized under the terms of the CTS. Southern Lights Pipeline The US and Canadian portions of the Southern Lights Pipeline are regulated by the FERC and CER, respectively. Shippers on the Southern Lights Pipeline are subject to long-term transportation contracts under a cost-of-service toll methodology. Toll adjustments are filed annually with the regulators and provide for the recovery of allowable operating and debt financing costs, plus a pre-determined after-tax return on equity (ROE) of 10%. GAS TRANSMISSION AND MIDSTREAM British Columbia (BC) Pipeline and Maritimes & Northeast (M&N) Canada are regulated by the CER. Rates are approved by the CER through negotiated toll settlement a greements based on cost-of-service. Both our BC Pipeline and M&N Canada systems currently operate under the terms of their respective 2022-2026 and 2022-2023 settlement agreements, which stipulate an allowable ROE and the continuation and establishment of certain deferral and variance accounts. US Gas Transmission Most of our US gas transmission and storage services are regulated by the FERC and may also be subject to the jurisdiction of various other federal, state and local agencies. The FERC regulates natural gas transmission in US interstate commerce including the establishment of rates for services, while rates for intrastate commerce and/or gathering services are regulated by the state agencies. Cost-of-service is the basis for the calculation of regulated tariff rates, although the FERC also allows the use of negotiated and discounted rates within contracts with shippers that may result in a rate that is above or below the FERC-regulated recourse rate for that service. GAS DISTRIBUTION AND STORAGE Enbridge Gas Enbridge Gas' distribution rates, commencing in 2019, are set under a five-year Incentive Regulation (IR) framework using a price cap mechanism. The price cap mechanism establishes new rates each year through an annual base rate escalation at inflation less a 0.3% stretch factor, annual updates for certain costs to be passed through to customers, and where applicable, the recovery of material discrete incremental capital investments beyond those that can be funded through base rates. The IR framework includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas to share equally with customers any earnings in excess of 150 basis points over the annual OEB approved ROE. FINANCIAL STATEMENT EFFECTS Accounting for rate-regulated activities has resulted in the recognition of the following regulatory assets and liabilities in the Consolidated Statements of Financial Position. December 31, 2022 2021 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Purchase gas variance 190 15 2023 Under-recovery of fuel costs 109 114 2023 Other current regulatory assets 305 130 2023 Total current regulatory assets 1 (Note 9) 604 259 Long-term regulatory assets Deferred income taxes 2 4,473 4,176 Various Long-term debt 3 378 398 2032-2046 Negative salvage 4 265 243 Various Purchase gas variance 244 215 2024 Accounting policy changes 5 219 157 Various Pension plan receivable 6 40 78 Various Other long-term regulatory assets 244 339 Various Total long-term regulatory assets 1 5,863 5,606 Total regulatory assets 6,467 5,865 Current regulatory liabilities Other current regulatory liabilities 167 106 2023 Total current regulatory liabilities 7 167 106 Long-term regulatory liabilities Future removal and site restoration reserves 8 1,615 1,543 Various Regulatory liability related to US income taxes 9 918 895 2050-2072 Pipeline future abandonment costs (Note 14) 610 649 Various Pension plan payable 6 231 — Various Other long-term regulatory liabilities 250 234 Various Total long-term regulatory liabilities 7 3,624 3,321 Total regulatory liabilities 3,791 3,427 1 Current regulatory assets are included in Accounts receivable and other, while long-term regulatory assets are included in Deferred amounts and other assets. 2 Represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in future regulator-approved rates and recovered from customers. The recovery period depends on the timing of the reversal of temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded. 3 Represents our regulatory offset to the fair value adjustment to debt acquired in our merger with Spectra Energy Corp. (Spectra Energy). The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished at an amount higher than the carrying value. 4 The negative salvage balance represents the recovery in future rates of the actual cost of removal of previously retired or decommissioned plant assets, as approved by the FERC. 5 This deferral primarily consists of unamortized accumulated actuarial gains/losses and past service costs incurred by Union Gas Limited, relating to the period up to our merger with Spectra Energy, which were previously recorded in AOCI. The amortization of this balance is recognized as a component of accrual-based pension expenses, which are included in Other income/(expense) and recovered in rates, as previously approved by the OEB. 6 Represents the regulatory offset to our pension liability to the extent that it is expected to be included in regulator-approved future rates and recovered from customers. The settlement period for this balance is not determinable. In the absence of rate-regulated accounting, this regulatory balance and the related pension expense would be recorded in earnings and OCI. 7 Current regulatory liabilities are included in Accounts payable and other , while long-term regulatory liabilities are included in Other long-term liabilities. 8 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the OEB, to fund future costs of removal and site restoration relating to property, plant and equipment. These costs are collected as part of the depreciation expense charged on property, plant and equipment that is reflected in rates. The settlement of this balance will occur over the long-term as costs are incurred. In the absence of rate-regulated accounting, depreciation rates would not include a charge for removal and site restoration and costs would be charged to earnings as incurred with recognition of revenue for amounts previously collected. 9 The regulatory liability related to US income taxes resulted from the US tax reform legislation dated December 22, 2017. These balances will be refunded to customers in accordance with the respective rate settlements approved by the FERC.

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2022
Business Combinations [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS ACQUISITIONS Tri Global Energy, LLC On September 27, 2022, through a wholly-owned US subsidiary, we acquired all of the outstanding common units in TGE for cash consideration of $295 million (US$215 million) plus potential contingent payments of up to $72 million (US$53 million) dependent on the achievement of performance milestones by TGE (the TGE Acquisition). The TGE Acquisition is subject to customary closing and working capital adjustments . TGE is an onshore renewable project developer in the US with a development portfolio of wind and solar projects. The TGE Acquisition enhances Enbridge's renewable power platform and accelerates our North American growth strategy. We accounted for the TGE Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations . In accordance with valuation methodologies described in ASC 820 Fair Value Measurements , the acquired assets and assumed liabilities are recorded at their estimated fair values as at the date of acquisition. The following table summarizes the estimated fair values that were assigned to the net assets of TGE: September 27, 2022 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 5 Property, plant and equipment 3 Long-term investments 8 Intangible assets (a) 117 Long-term assets 3 Current liabilities 61 Long-term debt (Note 18) 18 Long-term liabilities (b) 105 Goodwill (c) 392 Purchase price: Cash 295 Contingent consideration (d) 49 344 a) Intangible assets consist of compensation expected to be earned by TGE on existing development contracts once certain project development milestones are met. Fair value was determined using a discounted cash flow method which is an income-based approach to valuation that estimates the present value of future projected benefits from the contracts. The intangible assets will be amortized on a straight-line basis over an expected useful life of three and a half years. b) Long-term liabilities consist primarily of obligations payable to third parties which are contingent on the timing of milestones being met for certain projects. Fair value represents the present value of the future cash flow payments at the date of the TGE Acquisition. c) Goodwill is primarily attributable to expected future returns from new opportunities to develop wind and solar projects, as well as enhanced scale and operational diversity of our renewable projects portfolio. The goodwill balance recognized has been assigned to our Renewable Power Generation segment and is tax deductible over 15 years. d) We agreed to pay additional contingent consideration of up to US$53 million to TGE's former common unit holders if performance milestones are met on certain projects. The US$36 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition. The fair value was determined using an income-based approach. Upon completion of the TGE Acquisition, we began consolidating TGE. For the period beginning September 27, 2022 through to December 31, 2022, operating revenues and earnings attributable to common shareholders generated by TGE were immaterial. The impact to our supplemental pro forma consolidated operating revenues and earnings attributable to common shareholders for the years ended December 31, 2022 and 2021, as if the TGE Acquisition had been completed on January 1, 2021, was also immaterial. Moda Midstream Operating, LLC On October 12, 2021, through a wholly-owned US subsidiary, we acquired all of the outstanding membership interests in Moda for $3.7 billion (US$3.0 billion) of cash plus potential contingent payments of up to US$150 million dependent on performance of the assets (the Moda Acquisition). The Moda Acquisition was also subject to customary closing and working capital adjustments. Moda owns and operates a light crude export platform with very large crude carrier capability. The Moda Acquisition aligns with and advances our US Gulf Coast export strategy and enables connectivity to low-cost and long-lived reserves in the Permian and Eagle Ford basins. We accounted for the Moda Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations . In accordance with valuation methodologies described in ASC 820 Fair Value Measurements , the acquired assets and assumed liabilities were recorded at their estimated fair values as at the date of acquisition. The following table summarizes the estimated fair values that were assigned to the net assets of Moda: October 12, 2021 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 62 Property, plant and equipment (a) 1,480 Long-term investments (b) 427 Intangible assets (c) 1,781 Current liabilities 59 Long-term liabilities 17 Goodwill (d) 268 Purchase price: Cash 3,755 Contingent consideration (e) 187 3,942 a) Due to the specialized nature of Moda's property, plant and equipment, which includes groups of assets configured for use as storage facilities, pipelines and export terminals, the depreciated replacement cost approach was adopted as the primary valuation methodology. In determining replacement cost, both indirect costing using relevant inflation indices and direct costing using relevant market quotes were utilized. Adjustments were then applied for physical deterioration as well as functional and economic obsolescence. The fair value of land was determined using a market approach, which is based on rents and offerings for comparable properties. b) Long-term investments represent Moda's 20% equity interest in Cactus II Pipeline LLC (Cactus II). The fair value of Cactus II was determined using the discounted cash flow method. The discounted cash flow method is an income-based approach to valuation which estimates the present value of future projected benefits from the investment. c) Intangible assets consist primarily of customer relationships associated with long-term take-or-pay contracts. Fair value was determined using an income-based approach by estimating the present value of the after-tax earnings attributable to the contracts, including earnings associated with expected renewal terms, and will be amortized on a straight-line basis over an expected useful life of 10 years. d) Goodwill is primarily attributable to uncontracted future revenues, existing assembled assets that cannot be duplicated at the same cost by a new entrant, and enhanced scale and geographic diversity which provide greater optionality and platforms for future growth. The goodwill balance recognized has been assigned to our Liquids Pipelines segment and is tax deductible over 15 years. e) We agreed to pay additional contingent co nsideration of up to US$150 million to Moda's former membership interest holders if Moda's monthly volumes of crude oil loaded onto a vessel equal or exceed specified throughput levels. These performance requirements terminate the earlier of December 31, 2023 or the date the final contingent payment is made. The US$150 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition and was fully settled as at December 31, 2022. Acquisition-related expenses incurred were approximately $21 million for the year ended December 31, 2021 and are included in Operating and administrative expense in the Consolidated Statements of Earnings. Upon completion of the Moda Acquisition, we began consolidating Moda. For the period beginning October 12, 2021 through to December 31, 2021, Moda generated approximately $80 million in operating revenues and $9 million in earnings attributable to common shareholders. Our supplemental pro forma consolidated financial information for the years ended December 31, 2021 and 2020, including the results of operations for Moda as if the Moda Acquisition had been completed on January 1, 2020, are as follows: Year ended December 31, 2021 2020 (unaudited; millions of Canadian dollars) Operating revenues 47,339 39,435 Earnings attributable to common shareholders 1,2 5,771 2,938 1 Acquisition-related expenses of $21 million (after-tax $16 million) were excluded from earnings attributable to common shareholders for the year ended December 31, 2021 and deducted for the year ended December 31, 2020. 2 Includes the amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets of $193 million and $207 million (after-tax of $145 million and $155 million) for the years ended December 31, 2021 and 2020, respectively. DISPOSITIONS Athabasca Regional Oil Sands System On October 5, 2022, we closed the sale of an 11.6% non-operating interest in seven pipelines in the Athabasca region of northern Alberta from our Regi onal Oil Sands System to Athabasca Indigenous Investments Limited Partnership (Aii), an entity representing 23 First Nation and Métis communities, for total consideration of approximately $1.1 billion, less customary closing adjustments. No gain or loss was recognized on the sale and a noncontrolling interest was recorded in our Consolidated Statements of Financial Position as at December 31, 2022 to reflect the interest held by Aii (Note 20) . Subsequent to the sale, we maintained an 88.4% controlling interest in these assets, which are a component of our Liquids Pipelines segment, and continue to manage, operate and provide administrative services to them. Line 10 Crude Oil Pipeline In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P. owned the Canadian and US portions of Line 10, respectively, and the related assets were included in our Liquids Pipelines segment. The transaction closed on June 1, 2020. No gain or loss on disposition was recorded. Montana-Alberta Tie Line On May 1, 2020, we closed the sale of the Montana-Alberta Tie Line (MATL) transmission asset, a 345 kilometer transmission line from Great Falls, Montana to Lethbridge, Alberta, for cash proceeds of approximately $189 million. After closing adjustments, a gain on disposal of $4 million was included in Other income/(expense) in the Consolidated Statements of Earnings. MATL was included in our Renewable Power Generation segment. Ozark Gas Transmission On April 1, 2020, we closed the sale of our Ozark Gas Transmission and Ozark Gas Gathering assets (Ozark assets) for cash proceeds of approximately $63 million. After closing adjustments, a gain on disposal of $1 million was included in Other income/(expense) in the Consolidated Statements of Earnings. The Ozark assets are composed of a transmission system that extends from southeastern Oklahoma through Arkansas to southeastern Missouri, and a fee-based gathering system that accesses Fayetteville Shale and Arkoma production. These assets were included in our Gas Transmission and Midstream segment.

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER	12 Months Ended
	Dec. 31, 2022
Receivables [Abstract]
ACCOUNTS RECEIVABLE AND OTHER	ACCOUNTS RECEIVABLE AND OTHER December 31, 2022 2021 (millions of Canadian dollars) Trade receivables and unbilled revenues 1 5,616 4,957 Short-term portion of derivative assets (Note 24) 1,015 529 Regulatory assets (Note 7) 604 259 Gas imbalance 461 276 Taxes receivable 323 407 Other 852 434 8,871 6,862 1 Net of allowance for expected credit losses of $92 million and $87 million as at December 31, 2022 and 2021, respectively.

INVENTORY

INVENTORY	12 Months Ended
	Dec. 31, 2022
Inventory Disclosure [Abstract]
INVENTORY	INVENTORY December 31, 2022 2021 (millions of Canadian dollars) Natural gas 1,491 953 Crude oil 652 624 Other 112 93 2,255 1,670

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Weighted Average December 31, Depreciation Rate 2022 2021 (millions of Canadian dollars) Pipelines 2.9 % 66,528 62,997 Facilities and equipment 3.5 % 37,028 34,331 Land and right-of-way 1 2.2 % 3,637 3,320 Gas mains, services and other 2.6 % 14,491 13,606 Storage 2.3 % 3,477 3,099 Wind turbines, solar panels and other 4.1 % 4,912 4,912 Other 8.5 % 1,611 1,507 Under construction — % 2,316 2,268 Total property, plant and equipment 134,000 126,040 Total accumulated depreciation (29,540) (25,973) Property, plant and equipment, net 104,460 100,067 1 The measurement of weighted average depreciation rate excludes non-depreciable assets. Depreciation expense for the years ended December 31, 2022, 2021 and 2020 was $3.8 billion, $3.5 billion and $3.4 billion, respectively. IMPAIRMENT Magic Valley Wind Farm Magic Valley Wind Farm (Magic Valley) has commercial challenges caused by electricity transmission congestion and a negative price differential arising from higher transmission costs resulting in a lower electricity sale price. As a result, we have recognized an impairment loss of $227 million to our investment in Magic Valley, which is included in Impairment of long-lived assets in the Consolidated Statements of Earnings and is part of our Renewable Power Generation segment. Bakken Pipeline System The Bakken Pipeline System currently has long-term take-or-pay contracts that are set to expire in 2023. In connection with the upcoming expiration of the contracts, we have recognized an impairment loss of $183 million on the US and Canadian components of the interstate pipeline transportation system within the North Dakota System of our Bakken System, which is included in Impairment of long-lived assets in the Consolidated Statements of Earnings and is part of our Liquids Pipelines segment. Impairment charges were based on the amount by which the carrying value of the assets exceeded fair value, determined using expected discounted future cash flows.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES CONSOLIDATED VARIABLE INTEREST ENTITIES Our consolidated VIEs consist of legal entities where we are the primary beneficiary. We are the primary beneficiary when our variable interest(s) provide us with (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. We determine whether we are the primary beneficiary of a VIE by considering qualitative and quantitative factors, including, but not limited to: decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. The following table includes assets to be used to settle liabilities of our consolidated VIEs. The creditors of the liabilities of our consolidated VIEs do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position. December 31, 2022 1 2021 (millions of Canadian dollars) Assets Cash and cash equivalents 426 247 Restricted cash 12 4 Accounts receivable and other 199 99 Accounts receivable from affiliates 23 — Inventory 12 9 672 359 Property, plant and equipment, net 7,707 3,052 Long-term investments 14 16 Restricted long-term investments 98 101 Deferred amounts and other assets 158 2 Intangible assets, net 102 108 8,751 3,638 Liabilities Accounts payable and other 251 84 Accounts payable to affiliates 21 — 272 84 Other long-term liabilities 859 182 Deferred income taxes 5 5 1,136 271 7,615 3,367 1 Includes assets and liabilities of newly created Enbridge Athabasca Midstream Trunkline LP and Enbridge Athabasca Midstream Investor LP following the sale of a minority interest in certain Athabasca Regional Oil Sands System assets. Refer to Note 8 - Acquisitions and Dispositions . We do not have obligations to provide additional financial support to any of our consolidated VIEs. UNCONSOLIDATED VARIABLE INTEREST ENTITIES We currently hold interests in several non-consolidated VIEs where we are not the primary beneficiary as we do not have the power to direct the activities of the VIEs that most significantly impact their economic performance. These interests include investments in limited partnerships that are assessed to be VIEs due to the limited partners not having substantive kick-out rights or participating rights. The power to direct the activities of a majority of these non-consolidated limited partnership VIEs is shared amongst the partners. Each partner has representatives that make up an executive committee that makes significant decisions for the VIE, and none of the partners may make significant decisions unilaterally. The carrying amount of these VIEs and our estimated maximum exposure to loss as at December 31, 2022 and 2021 are presented below: Carrying Maximum December 31, 2022 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 91 117 EIH S.á r.l. 2 37 637 Rampion Offshore Wind Limited 3 413 468 Vector Pipeline L.P. 4 195 325 Woodfibre LNG Limited Partnership 5,6 635 2,476 Other 7 245 443 1,616 4,466 Carrying Maximum December 31, 2021 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 113 195 EIH S.á r.l. 2 38 664 Enbridge Renewable Infrastructure Investments S.á r.l. 8,9 54 2,121 Rampion Offshore Wind Limited 3 450 508 Vector Pipeline L.P. 4 189 374 Other 7 210 426 1,054 4,288 1 As at December 31, 2022 and 2021, the maximum exposure to loss includes a guarantee by us for our respective share of the VIE’s borrowing on a bank credit facility. 2 As at December 31, 2022 and 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the three French offshore wind projects for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $56 million and $73 million held by us as at December 31, 2022 and 2021, respectively. 3 As at December 31, 2022 and 2021, the maximum exposure to loss includes our parental guarantees that have been committed in project contracts in which we would be liable for in the event of default by the VIE. 4 As at December 31, 2022 and 2021, the maximum exposure to loss includes the carrying value of outstanding affiliate loans receivable for $25 million and $80 million held by us as at December 31, 2022 and 2021, respectively, and an outstanding credit facility for $105 million as at December 31, 2022 and 2021. 5 In November 2022, Enbridge acquired a 30% interest in Woodfibre LNG Limited Partnership (Woodfibre). Refer to Note 13 - Long-Term Investments . Woodfibre is a VIE due to its lack of sufficient equity at risk to finance its activities. Enbridge does not hold decision-making rights to direct Woodfibre's activities that most significantly impact its economic performance. 6 As at December 31, 2022, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE. 7 As at December 31, 2022 and 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the projects for which we would be liable in the event of default by the VIE. 8 As at December 31, 2021, the maximum exposure to loss included our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $807 million held by us as at December 31, 2021. 9 Following a reconsideration event in connection with an additional equity injection to facilitate debt and equity rebalancing of Enbridge Renewable Infrastructure Investments S.á r.l. (ERII) in the third quarter of 2022, ERII's equity is now sufficient for it to finance its activities without additional subordinated financial support. Therefore, it is no longer considered to be a VIE. We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 2022 and 2021.

LONG-TERM INVESTMENTS

LONG-TERM INVESTMENTS	12 Months Ended
	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
LONG-TERM INVESTMENTS	LONG-TERM INVESTMENTS Ownership December 31, Interest 2022 2021 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines MarEn Bakken Company LLC 1 75.0 % 1,968 1,752 DCP Midstream, LLC (Class B Units) 2 90.0 % 1,394 469 Seaway Crude Holdings LLC 50.0 % 2,744 2,634 Illinois Extension Pipeline Company, L.L.C. 3 65.0 % 622 593 Cactus II Pipeline LLC 4 30.0 % 658 434 Other 30.0% - 43.8% 76 71 Gas Transmission and Midstream Alliance Pipeline 5 50.0 % 430 504 Aux Sable 6 42.7% - 50.0% 214 238 DCP Midstream, LLC (Class A Units) 7 23.4 % 317 397 Gulfstream Natural Gas System, L.L.C. 50.0 % 1,274 1,180 Nexus Gas Transmission, LLC 50.0 % 1,813 1,724 Sabal Trail Transmission, LLC 50.0 % 1,535 1,464 Southeast Supply Header, LLC 50.0 % 86 82 Steckman Ridge, LP 50.0 % 91 88 Vector Pipeline 8 60.0 % 195 189 Woodfibre LNG Limited Partnership 30.0 % 635 — Offshore - various joint ventures 22.0% - 74.3% 314 309 Other 20.0% - 33.3% — 14 Gas Distribution and Storage Other 47.6% - 50.0% 20 20 Renewable Power Generation EIH S.à.r.l. 9 51.0 % 37 38 Enbridge Renewable Infrastructure Investments S.à.r.l. 51.0 % 163 54 Rampion Offshore Wind Limited 24.9 % 413 450 NextBridge Infrastructure LP 25.0 % 241 186 Other 15.8% - 50.0% 107 92 OTHER LONG-TERM INVESTMENTS Gas Transmission and Midstream Fairwood Peninsula Energy Corporation 22 20 Gas Distribution and Storage Oakville Enterprises Corporation 10 48 — Renewable Power Generation Emerging Technologies and Other 31 32 Eliminations and Other Other 11 488 290 15,936 13,324 1 Owns a 49.0% interest in Bakken Pipeline Investments L.L.C. Bakken Pipeline Investments L.L.C. owns 75.0% of the Bakken Pipeline System, resulting in a 27.6% effective interest in the Bakken Pipeline System by us. 2 We own 90.0% of the Class B units of DCP Midstream, LLC. These units track to a 65.0% ownership in Gray Oak Pipeline, LLC (Gray Oak), resulting in a 58.5% effective interest in Gray Oak by us. In 2021, we owned a 35.0% interest in Gray Oak Holdings LLC, which owned a 65.0% interest in Gray Oak, resulting in a 22.8% effective interest in Gray Oak by us. 3 Owns the Southern Access Extension Project. 4 On October 12, 2021, we acquired an effective 20.0% interest in Cactus II through the acquisition of Moda. Refer to Note 8 - Acquisitions and Dispositions for further discussion. On November 2, 2022, we acquired an additional 10.0% ownership in Cactus II for cash payment of $241 million (US$177 million), bringing our total non-operating ownership to 30.0%. 5 Includes Alliance Pipeline Limited Partnership in Canada and Alliance Pipeline L.P. in the US. 6 Includes Aux Sable Canada LP in Canada and Aux Sable Liquid Products LP and Aux Sable Midstream LLC in the US. 7 We own 23.4% of the Class A units of DCP Midstream, LLC. These units track to a 56.5% ownership in DCP Midstream, LP (DCP), resulting in a 13.2% effective interest in DCP by us. In 2021, we owned an effective 28.3% interest in DCP. 8 Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US. 9 On March 18, 2021, we sold 49.0% of EIH S.à.r.l., an entity that holds our 50.0% interest in Éolien Maritime France SAS (EMF), to the Canada Pension Plan Investment Board. This resulted in a 25.5% effective interest in EMF. Through our investment in EMF, we own equity interests in three French offshore wind projects, including effective interests in Saint-Nazaire (25.5%), Fécamp (17.9%) and Calvados (21.7%). 10 On August 2, 2022, we acquired a 10.0% interest in Oakville Enterprises Corporation. 11 Consists of investments in debt and equity securities held by our wholly-owned captive insurance subsidiaries. Refer to Note 24 -Risk Management and Financial Instruments. Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees' assets at the purchase date. As at December 31, 2022, this basis difference was $3.4 billion (2021 - $2.5 billion), of which $1.5 billion (2021 - $730 million) was amortizable. For the years ended December 31, 2022, 2021 and 2020, distributions received from equity investments were $2.6 billion, $2.2 billion and $2.1 billion, respectively. Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows: Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Operating revenues 27,043 20,021 14,096 Operating expenses 23,043 16,706 12,411 Earnings 4,334 3,022 2,324 Earnings attributable to Enbridge 2,056 1,711 1,136 December 31, 2022 2021 (millions of Canadian dollars) Current assets 4,196 3,639 Non-current assets 53,405 44,863 Current liabilities 4,843 3,741 Non-current liabilities 18,595 16,979 Noncontrolling interests 3,785 3,786 DCP Midstream, LLC On August 17, 2022, we completed a joint venture merger transaction with Phillips 66 (P66) resulting in a single joint venture, DCP Midstream, LLC, holding both our and P66's indirect ownership interests in Gray Oak and DCP. Our ownership in DCP Midstream, LLC consists of Class A and Class B Interests which track to our investments in DCP, included in the Gas Transmission and Midstream segment, and Gray Oak, included in the Liquids Pipelines segment, respectively. Through our investment in DCP Midstream, LLC, we increased our effective economic interest in Gray Oak to 58.5% from 22.8% and reduced our effective economic interest in DCP to 13.2% from 28.3%. As a result of the transaction, Enbridge will assume operatorship of Gray Oak in the second quarter of 2023. We determined the fair value of our decrease in economic interest in DCP based on the unadjusted quoted market price of DCP’s publicly traded common units on the transaction closing date. The fair value of our increased economic interest in Gray Oak was determined using the fair value prescribed to the change in our economic interest in DCP. As a result of the merger transaction and the realignment of our economic interests in DCP and Gray Oak, we also received cash consideration of approximately $522 million (US$404 million) and recorded an accounting gain of $1.1 billion (US$832 million) to Gain on joint venture merger transaction in the Consolidated Statements of Earnings. Both DCP and Gray Oak continue to be accounted for as equity method investments. Woodfibre LNG Limited Partnership On November 29, 2022, Enbridge acquired, for cash payment of $533 million (US$392 million), an effective 30.0% interest in Woodfibre. Woodfibre will operate a liquified natural gas export facility in BC being constructed by us and our partners. Noverco Inc. On June 7, 2021, IPL System Inc., a wholly-owned subsidiary of Enbridge, entered into a purchase and sale agreement to sell its 38.9% common share and preferred share interest in Noverco to Trencap L.P. On December 30, 2021, we closed the sale of Noverco for cash proceeds of $1.1 billion. After closing adjustments, a gain on disposal of $303 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2021. Noverco was previously included in our Gas Distribution and Storage segment. IMPAIRMENT OF EQUITY INVESTMENTS PennEast Pipeline Company, LLC PennEast Pipeline Company, LLC (PennEast) is a joint venture formed to develop a natural gas transmission pipeline to serve local distribution companies and power generators in southeastern Pennsylvania and New Jersey, is owned 20.0% by Enbridge, and is recorded as an equity method investment. In the third quarter of 2021, PennEast determined further development of the project was no longer viable and development of the project was ceased. As a result, we recorded an other-than-temporary impairment loss of $111 million on our investment for the year ended December 31, 2021 based on the estimated fair value of our share of the net assets. The carrying value of this investment as at December 31, 2022 and 2021 was nil and $12 million, respectively. Steckman Ridge, LP Steckman Ridge, LP (Steckman Ridge) is engaged in the storage of natural gas, is owned 50.0% by Enbridge, and is recorded as an equity method investment. During the year ended December 31, 2020, Steckman Ridge’s forecasted performance was adjusted for the expectation that future available capacity will be re-contracted at lower than expected rates. As a result, we recorded an other-than-temporary impairment loss of $221 million on our investment for the year ended December 31, 2020 based on a discounted cash flow analysis. The carrying value of this investment as at December 31, 2022 and 2021 was $91 million and $88 million, respectively. Southeast Supply Header, L.L.C. Southeast Supply Header, L.L.C. (SESH) provides natural gas transmission services from east Texas and northern Louisiana to the southeast markets of the Gulf Coast, is owned 50.0% by Enbridge, and is recorded as an equity method investment. The forecasted performance of SESH was revised during the year ended December 31, 2020 to reflect downward revisions to future negotiated rates as well as higher than expected available capacity levels, caused primarily by a significant contract expiry. As a result, we recorded an other-than-temporary impairment loss of $394 million on our investment for the year ended December 31, 2020 based on a discounted cash flow analysis. The carrying value of this investment as at December 31, 2022 and 2021 was $86 million and $82 million, respectively. DCP Midstream, LLC DCP Midstream, LLC, an entity of which we had a 50.0% ownership interest in prior to the joint venture merger transaction with P66, holds an equity interest in DCP. A decline in the market price of DCP's publicly traded units during the first quarter of 2020 resulted in an other-than-temporary impairment loss on our investment in DCP Midstream, LLC of $1.7 billion for the year ended December 31, 2020. In addition, we incurred losses of $324 million through our equity earnings pick up in relation to asset and goodwill impairment losses recorded by DCP. The carrying value of our investment in DCP Midstream, LLC (Class A Units) as at December 31, 2022 and 2021 was $317 million and $397 million, respectively.

RESTRICTED LONG-TERM INVESTMENT

RESTRICTED LONG-TERM INVESTMENTS	12 Months Ended
	Dec. 31, 2022
Assets Held-in-trust [Abstract]
RESTRICTED LONG-TERM INVESTMENTS	RESTRICTED LONG-TERM INVESTMENTS Effective January 1, 2015, we began collecting and setting aside funds to cover future pipeline abandonment costs for all CER regulated pipelines as a result of the CER’s regulatory requirements under LMCI. The funds collected are held in trusts in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues in the Consolidated Statements of Earnings and Restricted long-term investments in the Consolidated Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense in the Consolidated Statements of Earnings and Other long-term liabilities in the Consolidated Statements of Financial Position. We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money market securities in the US and Canada. As at December 31, 2022 and 2021, we had restricted long-term investments held in trust and classified as available-for-sale of $593 million and $630 million, respectively. We had Restricted long-term investments held in trust totaling $236 million and $217 million as at December 31, 2022 and 2021, respectively, which are classified as Level 1 in the fair value hierarchy. We also had Restricted long-term investments held in trust totaling $357 million (cost basis - $437 million) and $413 million (cost basis - $383 million) as at December 31, 2022 and 2021 , respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding losses of $122 million and $8 million on our Restricted long-term investments for the years ended December 31, 2022 and 2021, respectively . Within Other long-term liabilities we had estimated future abandonment costs related to LMCI of $610 million and $649 million as at December 31, 2022 and 2021, respectively (Note 7) .

INTANGIBLE ASSETS

INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
INTANGIBLE ASSETS	INTANGIBLE ASSETS December 31, 2022 Weighted Average Amortization Rate Cost Accumulated Amortization Net (millions of Canadian dollars) Software 10.9 % 2,019 (1,042) 977 Power purchase agreements 4.2 % 64 (23) 41 Project agreement 1 4.0 % 163 (36) 127 Customer relationships 8.6 % 2,701 (459) 2,242 Other intangible assets 5.9 % 621 (148) 473 Under development — % 158 — 158 5,726 (1,708) 4,018 December 31, 2021 Weighted Average Amortization Rate Cost Accumulated Amortization Net (millions of Canadian dollars) Software 12.0 % 2,067 (1,148) 919 Power purchase agreements 4.5 % 63 (21) 42 Project agreement 1 4.0 % 152 (27) 125 Customer relationships 8.5 % 2,532 (215) 2,317 Other intangible assets 3.9 % 475 (116) 359 Under development — % 246 — 246 5,535 (1,527) 4,008 1 Represents a project agreement acquired from the merger of Enbridge and Spectra Energy. For the years ended December 31, 2022, 2021 and 2020, our amortization expense related to intangible assets totaled $483 million, $348 million and $294 million, respectively. Our expected amortization expense associated with existing intangible assets for each of the years 2023 to 2027 is $498 million.

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL Liquids Gas Gas Renewable Power Generation Energy Consolidated (millions of Canadian dollars) Balance at January 1, 2021 7,828 19,480 5,378 — 2 32,688 Foreign exchange and other (55) (145) — — — (200) Acquisition 3 268 — 19 — — 287 Balance at December 31, 2021 1,2 8,041 19,335 5,397 — 2 32,775 Impairment — (2,465) — — — (2,465) Foreign exchange and other 506 1,236 — (4) — 1,738 Acquisition 4 — — — 392 — 392 Balance at December 31, 2022 1,2 8,547 18,106 5,397 388 2 32,440 1 Gross goodwill as at December 31, 2022 and 2021 was $36.5 billion and $34.4 billion, respectively. 2 Accumulated impairment as at December 31, 2022 and 2021 was $4.1 billion and $1.6 billion, respectively. 3 In 2021 we recorded $268 million of goodwill related to the acquisition of Moda. Refer to Note 8 - Acquisitions and Dispositions . 4 In 2022, we recorded $392 million of goodwill related to the acquisition of TGE. Refer to Note 8 - Acquisitions and Dispositions . IMPAIRMENT Gas Transmission During the year ended December 31, 2022, we recorded goodwill impairment of $2.5 billion related to our Gas Transmission reporting unit. The fair value of the reporting unit, determined using a combination of discounted cash flow and earnings multiples techniques, was impacted by a rise in cost of capital and lower projected long term growth rates for our existing assets.

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2022
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER December 31, 2022 2021 (millions of Canadian dollars) Trade payables and operating accrued liabilities 5,235 4,470 Dividends payable 1,825 1,773 Current deferred credits 1,056 853 Construction payables and contractor holdbacks 937 844 Current derivative liabilities (Note 24) 898 717 Taxes payable 683 478 Other 758 632 11,392 9,767

DEBT

DEBT	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
DEBT	DEBT December 31, Weighted Average Interest Rate 9 Maturity 2022 2021 (millions of Canadian dollars) Enbridge Inc. US dollar senior notes 3.5 % 2023 - 2051 12,060 10,992 Medium-term notes 3.8 % 2023 - 2064 8,223 8,123 Sustainability-linked bonds 2.0 % 2032 - 2033 3,355 2,363 Fixed-to-fixed subordinated term notes 1 4.1 % 2080 - 2083 3,596 1,263 Fixed-to-floating rate subordinated term notes 2 5.9 % 2077 - 2078 6,736 6,442 Floating rate notes 3 2023 - 2024 1,491 1,579 Commercial paper and credit facility draws 4.8 % 2023 - 2027 7,984 7,837 Other 4 15 5 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 4.5 % 2024 - 2027 4,199 4,845 Other 4 7 7 Enbridge Energy Partners, L.P. Senior notes 6.5 % 2025 - 2045 3,320 3,095 Enbridge Gas Inc. Medium-term notes 4.1 % 2023 - 2052 9,535 9,010 Debentures 9.1 % 2024 - 2025 210 210 Commercial paper and credit facility draws 4.5 % 2024 2,000 1,515 Other 4 1 — Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 4.0 % 2040 921 949 Enbridge Pipelines Inc. Medium-term notes 5 4.2 % 2023 - 2051 5,425 5,575 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 4.6 % 2024 312 667 Enbridge Southern Lights LP Senior notes 4.0 % 2040 222 240 Spectra Energy Capital, LLC Senior notes 7.0 % 2032 - 2038 234 218 Algonquin Gas Transmission, LLC Senior notes 3.3 % 2024 - 2029 1,152 1,074 East Tennessee Natural Gas, LLC Senior notes 3.1 % 2024 258 240 Texas Eastern Transmission, LP Senior notes 3.3 % 2028 - 2048 3,455 3,095 Spectra Energy Partners, LP Senior notes 4.3 % 2024 - 2045 4,336 4,042 Tri Global Energy, LLC Senior notes 12.7 % 2024 18 — Westcoast Energy Inc. Medium-term notes 4.9 % 2024 - 2041 1,225 1,475 Debentures 8.1 % 2025 - 2026 275 275 Fair value adjustment 608 667 Other 6 (393) (363) Total debt 7 80,980 75,640 Current maturities (6,045) (6,164) Short-term borrowings 8 (1,996) (1,515) Long-term debt 72,939 67,961 1 For an initial five or 10 years, the notes carry a fixed interest rate. Subsequently, during each reset period the interest rate will be reset to equal to the Five-Year US Treasury rate or Five-Year Government of Canada bond yield plus a margin. The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 2 For an initial five or 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal to the Canadian Dollar Offered Rate or the London Interbank Offered Rate (LIBOR) plus a margin. The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 3 The notes carry an interest rate equal to Secured Overnight Financing Rate (SOFR) plus a margin of 40 basis points and SOFR plus a margin of 63 basis points. 4 Primarily finance lease obligations. 5 Included in medium-term notes is $100 million with a maturity date of 2112. 6 Primarily unamortized discounts, premiums and debt issuance costs. 7 2022 - $38 billion and US$31 billion; 2021 - $36 billion and US$31 billion. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment. 8 Weighted average interest rates on outstanding commercial paper were 4.5% as at December 31, 2022 (2021 - 0.5%). 9 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2022. As at December 31, 2022, all outstanding debt was unsecured. CREDIT FACILITIES The following table provides details of our committed credit facilities as at December 31, 2022: Maturity 1 Total Facilities Draws 2 Available (millions of Canadian dollars) Enbridge Inc. 2023-2027 10,987 7,984 3,003 Enbridge (U.S.) Inc. 2024-2027 8,604 4,199 4,405 Enbridge Pipelines Inc. 2024 2,000 312 1,688 Enbridge Gas Inc. 2024 2,000 2,000 — Total committed credit facilities 23,591 14,495 9,096 1 Maturity date is inclusive of the one-year term out option for certain credit facilities. 2 Includes facility draws and commercial paper issuances that are back-stopped by credit facilities. On February 10, 2022, we renewed our three year $1.0 billion sustainability-linked credit facility, extending the maturity date out to July 2025. On May 17, 2022, we entered into a three year term loan with a syndicate of Japanese banks for approximately $806 million (¥84.8 billion), which will mature in May 2025 and replaces the approximately $499 million (¥52.5 billion) term loan that matured in May 2022. Additionally, on May 24, 2022, we entered into a 364-day term loan for approximately $1.9 billion, which will mature in May 2023. On June 23, 2022, we renewed approximately $5.5 billion of our 364-day extendible credit facilities to July 2024, which includes a one-year term out provision from July 2023. In July and August 2022, we renewed $12.7 billion of our credit facilities, extending the maturity dates of our 364-day credit facilities to July 2024, inclusive of a one year term out provision from July 2023, and our five year facilities out to July 2027. As a part of the renewals, we increased our credit facilities by approximately $640 million. On December 16, 2022, Enbridge (U.S.) Inc. entered into a five year delay draw term loan in support of solar self-power projects for approximately $479 million, which will mature in December 2027. In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $689 million was unutilized as at December 31, 2022. As at December 31, 2021, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $854 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 December 31, 2022 and 2021, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $10.5 billion and $11.3 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 year ended December 31, 2022, we completed the following long-term debt issuances totaling US$3.2 billion and $3.4 billion: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. January 2022 5.00% fixed-to-fixed subordinated notes due January 2082 1 $750 February 2022 Floating rate senior notes due February 2024 2 US$600 February 2022 2.15% senior notes due February 2024 US$400 February 2022 2.50% senior notes due February 2025 US$500 September 2022 7.38% fixed-to-fixed subordinated notes due January 2083 3 US$500 September 2022 7.63% fixed-to-fixed subordinated notes due January 2083 4 US$600 November 2022 5.70% medium-term notes due November 2027 $600 November 2022 6.10% sustainability-linked medium-term notes due November 2032 5 $900 November 2022 6.51% medium-term notes due November 2052 $500 Enbridge Gas Inc. August 2022 4.15% medium-term notes due August 2032 $325 August 2022 4.55% medium-term notes due August 2052 $325 Texas Eastern Transmission LP December 2022 6.20% senior notes due December 2032 US$600 1 For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 3.54%. Subsequent to year 10, every five years, the Five-Year Government of Canada bond yield is reset. At year 30, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.29%. 2 Notes carry an interest rate set to equal the SOFR plus a margin of 63 basis points. 3 For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be set to equal to the Five-Year US Treasury rate plus a margin of 3.71%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.96%. Subsequent to year 10, every five years, the Five-Year US Treasury rate is reset. At year 25, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.71%. 4 For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.42%. Subsequent to year 10, every five years, the Five-Year US Treasury rate will be reset. At year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.17%. 5 The sustainability-linked medium-term notes are subject to a sustainability performance target of 35% reduction in emissions intensity at an observation date of December 31, 2030. If the target is not met, on November 9, 2031, the interest rate will be set to equal 6.10% plus a margin of 70 basis points. LONG-TERM DEBT REPAYMENTS During the year ended December 31, 2022, we completed the following long-term debt repayments totaling $1.5 billion and US$2.0 billion, respectively: Company Repayment Date Principal Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. February 2022 Floating rate notes 1 US$750 February 2022 4.85% medium-term notes $200 July 2022 2.90% senior notes US$700 December 2022 3.19% medium-term notes $350 December 2022 3.19% medium-term notes $450 Enbridge Gas Inc. April 2022 4.85% medium-term notes $125 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2022 3.98% senior notes US$72 Enbridge Pipelines Inc. November 2022 2.93% medium-term notes $150 Enbridge Southern Lights LP June and December 2022 4.01% senior notes $18 Texas Eastern Transmission, LP October 2022 2.80% senior notes US$500 Westcoast Energy Inc. December 2022 3.12% medium-term notes $250 1 Notes carried an interest rate set to equal the Three-Month LIBOR plus a margin of 50 basis points. DEBT COVENANTS Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2022, we were in compliance with all debt covenants. INTEREST EXPENSE Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Debentures and term notes 2,910 2,806 2,873 Commercial paper and credit facility draws 388 114 163 Amortization of fair value adjustment (45) (50) (54) Capitalized interest (74) (215) (192) 3,179 2,655 2,790

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS Our ARO relate mostly to the retirement of pipelines, renewable power generation assets and obligations related to right-of way agreements and contractual leases for land use. The discount rates used to estimate the present value of the expected future cash flows for the year ended December 31, 2022 ranged from 1.5% to 9.0% (2021 - 0.9% to 9.0%). A reconciliation of movements in our ARO liabilities is as follows: December 31, 2022 2021 (millions of Canadian dollars) Obligations at beginning of year 502 496 Liabilities incurred 30 — Liabilities settled (126) (67) Change in estimate and other 51 70 Foreign currency translation adjustment 24 (3) Accretion expense 7 6 Obligations at end of year 488 502 Presented as follows: Accounts payable and other 83 160 Other long-term liabilities 405 342 488 502

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2022
Noncontrolling Interest [Abstract]
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position: December 31, 2022 2021 (millions of Canadian dollars) Algonquin Gas Transmission, LLC 400 377 Enbridge Athabasca Midstream Investor Limited Partnership 1 1,106 — Maritimes & Northeast Pipeline, L.L.C. 582 546 Renewable energy assets 1,302 1,503 Westcoast Energy Inc. 2 117 116 Other 4 — 3,511 2,542 1 On October 5, 2022, we closed the sale of an 11.6% non-operating interest in certain assets from our Regional Oil Sands System to Aii. Refer to Note 8 - Acquisitions and Dispositions . 2 During 2021, Westcoast Energy Inc. redeemed all of its remaining Cumulative Five-Year Minimum Rate Reset Redeemable First Preferred Shares.

SHARE CAPITAL

SHARE CAPITAL	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
SHARE CAPITAL	SHARE CAPITAL Our authorized share capital consists of an unlimited number of common shares with no par value and an unlimited number of preference shares. COMMON SHARES 2022 2021 2020 December 31, Number of Shares Amount Number of Shares Amount Number of Shares Amount (millions of Canadian dollars; number of shares in millions) Balance at beginning of year 2,026 64,799 2,026 64,768 2,025 64,746 Shares issued on exercise of stock options 2 53 — 31 1 22 Share purchases at stated value 1 (3) (88) — — — — Other — (4) — — — — Balance at end of year 2,025 64,760 2,026 64,799 2,026 64,768 1 Reflects the repurchase and cancellation of common shares under our normal course issuer bid. PREFERENCE SHARES 2022 2021 2020 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Preference Shares, Series A 5 125 5 125 5 125 Preference Shares, Series B 20 500 18 457 18 457 Preference Shares, Series C 1 — — 2 43 2 43 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 20 500 20 500 20 500 Preference Shares, Series H 14 350 14 350 14 350 Preference Shares, Series J 2 — — 8 199 8 199 Preference Shares, Series L 16 411 16 411 16 411 Preference Shares, Series N 18 450 18 450 18 450 Preference Shares, Series P 16 400 16 400 16 400 Preference Shares, Series R 16 400 16 400 16 400 Preference Shares, Series 1 16 411 16 411 16 411 Preference Shares, Series 3 24 600 24 600 24 600 Preference Shares, Series 5 8 206 8 206 8 206 Preference Shares, Series 7 10 250 10 250 10 250 Preference Shares, Series 9 11 275 11 275 11 275 Preference Shares, Series 11 20 500 20 500 20 500 Preference Shares, Series 13 14 350 14 350 14 350 Preference Shares, Series 15 11 275 11 275 11 275 Preference Shares, Series 17 3 — — 30 750 30 750 Preference Shares, Series 19 20 500 20 500 20 500 Issuance costs (135) (155) (155) Balance at end of year 6,818 7,747 7,747 1 On June 1, 2022, all outstanding Preference Shares, Series C were converted to Preference Shares, Series B. 2 On June 1, 2022, we redeemed our US$200 million outstanding Cumulative Redeemable Preference Shares, Series J. 3 On March 1, 2022, we redeemed our $750 million outstanding Cumulative Redeemable Minimum Rate Reset Preference Shares, Series 17. Characteristics of our outstanding preference shares are as follows: Dividend Rate Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4 (Canadian dollars unless otherwise stated) Preference Shares, Series A 5.50 % $1.37500 $25 — — Preference Shares, Series B 5 5.20 % $1.30052 $25 June 1, 2027 Series C Preference Shares, Series D 4.46 % $1.11500 $25 March 1, 2023 Series E Preference Shares, Series F 4.69 % $1.17224 $25 June 1, 2023 Series G Preference Shares, Series H 4.38 % $1.09400 $25 September 1, 2023 Series I Preference Shares, Series L 6 5.86 % US$1.46448 US$25 September 1, 2027 Series M Preference Shares, Series N 5.09 % $1.27152 $25 December 1, 2023 Series O Preference Shares, Series P 4.38 % $1.09476 $25 March 1, 2024 Series Q Preference Shares, Series R 4.07 % $1.01825 $25 June 1, 2024 Series S Preference Shares, Series 1 5.95 % US$1.48728 US$25 June 1, 2023 Series 2 Preference Shares, Series 3 3.74 % $0.93425 $25 September 1, 2024 Series 4 Preference Shares, Series 5 5.38 % US$1.34383 US$25 March 1, 2024 Series 6 Preference Shares, Series 7 4.45 % $1.11224 $25 March 1, 2024 Series 8 Preference Shares, Series 9 4.10 % $1.02424 $25 December 1, 2024 Series 10 Preference Shares, Series 11 3.94 % $0.98452 $25 March 1, 2025 Series 12 Preference Shares, Series 13 3.04 % $0.76076 $25 June 1, 2025 Series 14 Preference Shares, Series 15 2.98 % $0.74576 $25 September 1, 2025 Series 16 Preference Shares, Series 19 4.90 % $1.22500 $25 March 1, 2023 Series 20 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Preference Shares, Series A, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Preference Shares, Series 19 contain a feature where the fixed dividend rate, when reset every five years, will not be less than 4.90%. No other series of Preference Shares has this feature. 2 Preference Shares, Series A may be redeemed any time at our option. For all other series of preference shares, we may at our option, redeem all or a portion of the outstanding preference shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value. 4 With the exception of Preference Shares, Series A, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in year) x Three-Month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in year) x Three-Month US Government treasury bill rate + 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6). 5 The quarterly dividend per share paid on Preference Shares, Series B was increased to $0.32513 from $0.21340 on June 1, 2022 due to reset of the annual dividend on June 1, 2022. On June 1, 2022, all outstanding Preference Shares, Series C were converted to Preference Shares, Series B. 6 The quarterly dividend per share paid on Preference Shares, Series L was increased to US$0.36612 from US$0.30993 on September 1, 2022, due to reset of the annual dividend on September 1, 2022. SHAREHOLDER RIGHTS PLAN The Shareholder Rights Plan is designed to encourage the fair treatment of our shareholders in connection with any takeover offer. Rights issued under the plan become exercisable when a person and any related parties acquires or announces its intention to acquire 20% or more of our outstanding common shares without complying with certain provisions set out in the plan or without approval of our Board of Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase our common shares at a 50% discount to the market price at that time.

STOCK OPTION AND STOCK UNIT PLA

STOCK OPTION AND STOCK UNIT PLANS	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
STOCK OPTION AND STOCK UNIT PLANS	STOCK OPTION AND STOCK UNIT PLANS We maintain three long-term incentive compensation plans: the ISO Plan, the PSU Plan and the RSU Plan. Total stock-based compensation expense recorded for the years ended December 31, 2022, 2021 and 2020 was $260 million, $157 million and $145 million, respectively. Disclosure of activity and assumptions for material stock-based compensation plans are included below. INCENTIVE STOCK OPTIONS Certain key employees are granted ISOs to purchase common shares at the grant date market price. ISOs vest in equal annual installments over a four December 31, 2022 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (options in thousands; weighted average exercise price in Canadian dollars; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 34,017 49.28 Options granted 3,430 49.58 Options exercised 1 (8,684) 44.55 Options cancelled or expired (1,139) 51.32 Options outstanding at end of year 27,624 48.46 5.7 133 Options vested at end of year 2 17,631 49.20 4.4 84 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2022, 2021 and 2020 was $66 million, $24 million and $13 million, respectively, and cash received on exercise was $3 million, $2 million and $4 million, respectively. 2 The total fair value of ISOs exercised during the years ended December 31, 2022, 2021 and 2020 was $21 million, $25 million and $30 million, respectively. Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton option pricing model are as follows: Year ended December 31, 2022 2021 2020 Fair value per option (Canadian dollars) 1 5.07 4.10 4.01 Valuation assumptions Expected option term (years) 2 6 6 6 Expected volatility 3 21.9 % 25.5 % 18.3 % Expected dividend yield 4 6.5 % 7.6 % 5.9 % Risk-free interest rate 5 1.8 % 0.7 % 1.3 % 1 Options granted to US employees are based on the New York Stock Exchange prices. The option value and assumptions shown are based on a weighted average of the US and the Canadian options. The fair values per option for the years ended December 31, 2022, 2021 and 2020 were $4.78, $3.91 and $3.75, respectively, for Canadian employees and US$4.62, US$3.65 and US$3.62, respectively, for US employees. 2 The expected option term is six years based on historical exercise practice and five years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada’s Canadian bond yields and the US Treasury bond yields. Compensation expense recorded for the years ended December 31, 2022, 2021 and 2020 for ISOs was $15 million, $16 million and $24 million, respectively. As at December 31, 2022, unrecognized compensation expense related to non-vested stock-based compensation arrangements granted under the ISO Plan was $12 million. The expense is expected to be fully recognized over a weighted average period of approximately two years. PERFORMANCE STOCK UNITS Under PSU awards for certain key employees, cash awards are paid following a three-year performance cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by Enbridge's weighted average share price for 20 days prior to the maturity of the grant and by a performance multiplier. The performance multiplier ranges from zero, if our performance fails to meet threshold performance levels, to a maximum of 2.0 if we perform within the highest range of the performance targets. The performance multiplier is derived through a calculation of our Total Shareholder Return percentile rank, in each case relative to a specified peer group of companies and our distributable cash flow per share, adjusted for unusual, infrequent or other non-operating factors, relative to targets established at the time of grant. To calculate the 2022 expense, a multiplier of 1.25 was used for 2022 PSU grants, 1.25 for 2021 PSU grants and 2.00 for the 2020 PSU grants. December 31, 2022 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 3,429 Units granted 1,467 Units cancelled (131) Units matured 1 (1,700) Dividend reinvestment 184 Units outstanding at end of year 3,249 1.1 261 1 The total amount paid during the years ended December 31, 2022, 2021 and 2020 for PSUs was $90 million, $70 million and $14 million, respectively. Compensation expense recorded for the years ended December 31, 2022, 2021 and 2020 for PSUs was $169 million, $56 million and $76 million, respectively. As at December 31, 2022, unrecognized compensation expense related to non-vested PSUs was $72 million. The expense is expected to be fully recognized over a weighted average period of approximately two years. RESTRICTED STOCK UNITS Under RSU awards, cash awards are paid to certain of our employees vesting in equal installments on each of the first, second and third anniversaries of the grant date. Share-settled awards are given to certain senior management employees following a three year maturity period. RSU holders receive shares or cash equal to our weighted average share price for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date. December 31, 2022 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 2,705 Units granted 1,400 Units cancelled (134) Units matured 1 (602) Dividend reinvestment 196 Units outstanding at end of year 3,565 1.0 185 1 The total amount paid during the years ended December 31, 2022, 2021 and 2020 for RSUs was $32 million, $72 million and $27 million, respectively.

COMPONENTS OF ACCUMULATED OTHER

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	12 Months Ended
	Dec. 31, 2022
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 AOCI attributable to our common shareholders for the years ended December 31, 2022, 2021 and 2020 are as follows: Cash Flow Hedges Excluded Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2022 (897) — (166) 56 (5) (84) (1,096) Other comprehensive income/(loss) retained in AOCI 1,125 (35) (971) 4,292 (6) 411 4,816 Other comprehensive loss/(income) reclassified to earnings Interest rate contracts 1 186 — — — — — 186 Foreign exchange contracts 2 (4) — — — — — (4) Other contracts 3 4 — — — — — 4 Amortization of pension and OPEB actuarial gain 4 — — — — — (14) (14) Other — — — — 16 — 16 1,311 (35) (971) 4,292 10 397 5,004 Tax impact Income tax on amounts retained in AOCI (250) — — — — (99) (349) Income tax on amounts reclassified to earnings (43) — — — — 4 (39) (293) — — — — (95) (388) Balance as at December 31, 2022 121 (35) (1,137) 4,348 5 218 3,520 Cash Flow Hedges Excluded Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2021 (1,326) 5 (215) 568 66 (499) (1,401) Other comprehensive income/(loss) retained in AOCI 238 (5) 49 (492) (12) 520 298 Other comprehensive loss/(income) reclassified to earnings Interest rate contracts 1 296 — — — — — 296 Commodity contracts 5 1 — — — — — 1 Foreign exchange contracts 2 5 — — — — — 5 Other contracts 3 2 — — — — — 2 Equity investment disposal — — — — (66) — (66) Amortization of pension and OPEB actuarial loss and prior service costs 4 — — — — — 28 28 Other 17 — — (20) 3 — — 559 (5) 49 (512) (75) 548 564 Tax impact Income tax on amounts retained in AOCI (61) — — — — (126) (187) Income tax on amounts reclassified to earnings (69) — — — 4 (7) (72) (130) — — — 4 (133) (259) Balance as at December 31, 2021 (897) — (166) 56 (5) (84) (1,096) Cash Flow Hedges Excluded Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2020 (1,073) — (317) 1,396 67 (345) (272) Other comprehensive income/(loss) retained in AOCI (591) 5 115 (828) (2) (221) (1,522) Other comprehensive loss/(income) reclassified to earnings Interest rate contracts 1 253 — — — — — 253 Foreign exchange contracts 2 5 — — — — — 5 Other contracts 3 (2) — — — — — (2) Amortization of pension and OPEB actuarial loss and prior service costs 4 — — — — — 17 17 (335) 5 115 (828) (2) (204) (1,249) Tax impact Income tax on amounts retained in AOCI 140 — (13) — 1 54 182 Income tax on amounts reclassified to earnings (58) — — — — (4) (62) 82 — (13) — 1 50 120 Balance as at December 31, 2020 (1,326) 5 (215) 568 66 (499) (1,401) 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings. 3 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 4 These components are included in the computation of net periodic benefit (credit)/cost and are reported within Other income/(expense) in the Consolidated Statements of Earnings. 5 Reported within Transportation and other services revenues, Commodity sales, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS MARKET RISK Our earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risks). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk We generate certain revenues, incur expenses and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying cash flow, fair value and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in US dollar-denominated investments and subsidiaries using foreign currency derivatives and US dollar-denominated debt. Interest Rate Risk Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps. These hedges have an average fixed rate of 4.0%. We are exposed to changes in the fair value of fixed rate debt that arise as a result of changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in fair value via execution of fixed to floating interest rate swaps. As at December 31, 2022, we do not have any pay floating-receive fixed interest rate swaps outstanding. Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 2.2%. Commodity Price Risk Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk. Equity Price Risk Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk. TOTAL DERIVATIVE INSTRUMENTS We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances. The following table summarizes the 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. December 31, 2022 Derivative Instruments Used as Cash Flow Hedges Derivative Non- Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — 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 Accounts payable and other 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) December 31, 2021 Derivative Derivative Instruments Used as Fair Value Hedges Non- Total Gross Amounts Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — 259 259 (41) 218 Interest rate contracts 64 — — 64 — 64 Commodity contracts — — 204 204 (129) 75 Other contracts — — 2 2 — 2 64 — 465 529 (170) 359 Deferred amounts and other assets Foreign exchange contracts — — 240 240 (61) 179 Interest rate contracts 88 — — 88 (1) 87 Commodity contracts — — 29 29 (13) 16 Other contracts — — 3 3 — 3 88 — 272 360 (75) 285 Accounts payable and other Foreign exchange contracts (15) (112) (176) (303) 41 (262) Interest rate contracts (150) — — (150) — (150) Commodity contracts (14) — (250) (264) 129 (135) (179) (112) (426) (717) 170 (547) Other long-term liabilities Foreign exchange contracts — — (423) (423) 61 (362) Interest rate contracts (1) — (23) (24) 1 (23) Commodity contracts (17) — (67) (84) 13 (71) (18) — (513) (531) 75 (456) Total net derivative asset/(liability) Foreign exchange contracts (15) (112) (100) (227) — (227) Interest rate contracts 1 — (23) (22) — (22) Commodity contracts (31) — (84) (115) — (115) Other contracts — — 5 5 — 5 (45) (112) (202) (359) — (359) The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments. 2022 2021 As at December 31, 2023 2024 2025 2026 2027 Thereafter Total Total Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) 655 1,000 500 — — — 2,155 2,508 Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) 8,297 6,386 4,613 4,121 2,837 1,356 27,610 25,427 Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) 29 30 30 28 32 — 149 177 Foreign exchange contracts - Euro forwards - sell (millions of Euro) 92 91 86 85 81 262 697 801 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) — — 84,800 — — — 84,800 72,500 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 8,698 538 30 26 25 39 9,356 597 Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 5,496 1,766 589 — — — 7,851 5,279 Equity contracts (millions of Canadian dollars) 37 31 12 — — — 80 67 Commodity contracts - natural gas (billions of cubic feet) 52 25 15 1 — — 93 199 Commodity contracts - crude oil (millions of barrels) 16 — — — — — 16 12 Commodity contracts - power (megawatt per hour (MW/H)) 26 (25) (44) — — — (14) 1 (43) 1 1 Total is an average net purchase/(sell) of power. Fair Value Derivatives For foreign exchange derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative is included in Other income/(expense) or Interest expense in the Consolidated Statements of Earnings. The offsetting loss or gain on the hedged item attributable to the hedged risk is included in Other income/(expense) in the Consolidated Statements of Earnings. Any excluded components are included in the Consolidated Statements of Comprehensive Income. Year ended December 31, 2022 2021 (millions of Canadian dollars) Unrealized gain on derivative 262 8 Unrealized loss on hedged item (254) (15) Realized loss on derivative (110) (41) Realized gain on hedged item 85 45 The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes: 2022 2021 2020 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts 3 (29) (1) Interest rate contracts 1,151 252 (595) Commodity contracts (53) (28) 2 Other contracts (4) 1 (3) Fair value hedges Foreign exchange contracts (35) (5) 5 Net investment hedges Foreign exchange contracts — — 13 1,062 191 (579) Amount of (gain)/loss reclassified from AOCI to earnings Foreign exchange contracts 1 13 5 5 Interest rate contracts 2 186 296 253 Commodity contracts 3 — 1 — Other contracts 3 4 2 (2) 203 304 256 1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. We estimate that a gain of $67 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 36 months as at December 31, 2022. Non-Qualifying Derivatives The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Foreign exchange contracts 1 (1,344) 92 902 Interest rate contracts 2 10 2 (25) Commodity contracts 3 50 71 (114) Other contracts 4 4 8 (7) Total unrealized derivative fair value gain/(loss), net (1,280) 173 756 1 For the respective annual periods, reported within Transportation and other services revenue (2022 - $238 million loss; 2021 - $98 million gain; 2020 - $533 million gain) and Other income/(expense) (2022 - $1,106 million loss; 2021 - $6 million loss; 2020 - $369 million gain) in the Consolidated Statements of Earnings. 2 Reported as an increase within Interest expense in the Consolidated Statements of Earnings. 3 For the respective annual periods, reported within Transportation and other services revenue (2022 - $13 million gain; 2021 - $9 million gain; 2020 - $2 million loss), Commodity sales (2022 - $89 million gain; 2021 - $160 million gain; 2020 - $321 million loss), Commodity costs (2022 - $102 million loss; 2021 - $105 million loss; 2020 - $207 million gain) and Operating and administrative expense (2022 - $50 million gain; 2021 - $7 million gain; 2020 - $2 million gain) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. LIQUIDITY RISK Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. Our shelf prospectuses with securities regulators enable ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We are in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2022. 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 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: December 31, 2022 2021 (millions of Canadian dollars) Canadian financial institutions 644 424 US financial institutions 277 130 European financial institutions 334 181 Asian financial institutions 224 30 Other 1 105 122 1,584 887 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. As at December 31, 2022, we did not provide any letters of credit in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association agreements. We held no cash collateral on derivative asset exposures as at December 31, 2022 and December 31, 2021. Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates, and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation. Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within Enbridge Gas, credit risk is mitigated by the utility's large and diversified customer base and the ability to recover an estimate for expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value. FAIR VALUE MEASUREMENTS Our financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. FAIR VALUE OF FINANCIAL INSTRUMENTS We categorize our 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 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 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: 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) December 31, 2021 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 259 — 259 Interest rate contracts — 64 — 64 Commodity contracts 38 71 95 204 Other contracts — 2 — 2 38 396 95 529 Long-term derivative assets Foreign exchange contracts — 240 — 240 Interest rate contracts — 88 — 88 Commodity contracts — 21 8 29 Other contracts — 3 — 3 — 352 8 360 Financial liabilities Current derivative liabilities Foreign exchange contracts — (303) — (303) Interest rate contracts — (150) — (150) Commodity contracts (52) (66) (146) (264) (52) (519) (146) (717) Long-term derivative liabilities Foreign exchange contracts — (423) — (423) Interest rate contracts — (24) — (24) Commodity contracts — (19) (65) (84) — (466) (65) (531) Total net financial asset/(liability) Foreign exchange contracts — (227) — (227) Interest rate contracts — (22) — (22) Commodity contracts (14) 7 (108) (115) Other contracts — 5 — 5 (14) (237) (108) (359) The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2022 Fair Value Unobservable Input Minimum Price Maximum Price Weighted Average Price Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas (35) Forward gas price 4.57 34.56 6.25 $/mmbtu 2 Crude (4) Forward crude price 71.10 105.22 83.26 $/barrel Power (71) Forward power price 36.63 364.00 103.30 $/MW/H Commodity contracts - physical 1 Natural gas (41) Forward gas price 1.67 33.89 6.00 $/mmbtu 2 Crude (2) Forward crude price 64.43 116.60 86.25 $/barrel Power 17 Forward power price 30.49 183.88 72.48 $/MW/H (136) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 One million British thermal units (mmbtu). If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives. Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 31, 2022 2021 (millions of Canadian dollars) Level 3 net derivative liability at beginning of period (108) (191) Total gain/(loss) Included in earnings 1 6 (39) Included in OCI (54) (29) Settlements 20 151 Level 3 net derivative liability at end of period (136) (108) 1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. There were no transfers into or out of Level 3 as at December 31, 2022 or 2021. 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 years ended December 31, 2022 and 2021, we recognized an unrealized foreign exchange loss of $954 million and gain of $49 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 years ended December 31, 2022 and 2021. No realized gains or losses associated with the settlement of foreign exchange forward contracts were recognized in OCI during the years ended December 31, 2022 and 2021. During the years ended December 31, 2022 and 2021, we recognized a realized loss of $21 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 FVMA investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $102 million and $52 million as at December 31, 2022 and 2021, respectively. As at December 31, 2022 , the fair value of short- and long-term investment s in equity funds and debt securities held by our captive insurance subsidiaries was $145 million and $488 million, respectively ( 2021 - $14 million and $290 million, respectively). 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, and are recorded in Accounts receivable and other and Long-ter m investments, respectively, in the Consolidated Statements of Financial Position. There were unrealized holding losses in equity funds and debt securities of $26 million for the year ended December 31, 2022 (2021 - losses o f $12 million ).

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES INCOME TAX RATE RECONCILIATION Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Earnings before income taxes 4,542 7,729 4,190 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 681 1,159 629 Increase/(decrease) resulting from: Provincial and state income taxes 1 108 228 288 Foreign and other statutory rate differentials 2 295 134 (53) Effects of rate-regulated accounting 3 (122) (139) (145) Foreign allowable interest deductions — — (4) Part VI.1 tax, net of federal Part I deduction 4 76 73 76 US Minimum Tax 5 107 — 44 Non-taxable portion of gain on sale of investment 6 — (23) — Valuation allowance 6 5 (6) Accounting impairment of non-deductible goodwill 7 370 — — Noncontrolling interests 8 9 (17) (8) Other 9 74 (5) (47) Income tax expense 1,604 1,415 774 Effective income tax rate 35.3 % 18.3 % 18.5 % 1 The change in provincial and state income taxes from 2021 to 2022 reflects the decrease in earnings from Canadian operations and the effect of the reduction in the Pennsylvania corporate income tax rate in the US, partially offset by the increase in earnings from US operations before the non-deductible goodwill impairment relating to the Gas Transmission reporting unit in combination with state tax apportionment changes. Refer to Note 16 - Goodwill. 2 The change in foreign and other statutory rate differentials from 2021 to 2022 reflects the increase in earnings from US operations, before the goodwill impairment relating to the Gas Transmission reporting unit. Refer to Note 16 - Goodwill. 3 The amount in 2022 relates to the federal component of the tax impact relating to the 2022 variable consideration attributable to the Canadian Mainline. Refer to Note 4 - Revenue. 4 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada. 5 There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation. 6 The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco. 7 The amount in 2022 relates to the federal impact of the non-deductible goodwill impairment relating to the Gas Transmission reporting unit. Refer to Note 16 - Goodwill. 8 The amount in 2022 includes the federal tax impact of an impairment to Magic Valley attributable to noncontrolling interests. Refer to Note 11 - Property, Plant and Equipment. 9 The amount in 2022 includes the federal component of the tax impact relating to the 2021 variable consideration attributable to the Canadian Mainline. Refer to Note 4 - Revenue. COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Earnings before income taxes Canada 583 3,399 2,789 US 2,865 3,336 407 Other 1,094 994 994 4,542 7,729 4,190 Current income taxes Canada 360 162 165 US 201 80 64 Other 86 82 98 647 324 327 Deferred income taxes Canada (358) 344 378 US 1,309 741 66 Other 6 6 3 957 1,091 447 Income tax expense 1,604 1,415 774 COMPONENTS OF DEFERRED INCOME TAXES Deferred income tax assets and liabilities are recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and liabilities are as follows: December 31, 2022 2021 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (9,096) (8,721) Investments (7,099) (6,097) Regulatory assets (1,291) (1,245) Pension and OPEB plans (30) — Other (46) (208) Total deferred income tax liabilities (17,562) (16,271) Deferred income tax assets Financial instruments 456 315 Pension and OPEB plans — 110 Loss carryforwards 2,259 3,081 Other 1,753 1,648 Total deferred income tax assets 4,468 5,154 Less valuation allowance (215) (84) Total deferred income tax assets, net 4,253 5,070 Net deferred income tax liabilities (13,309) (11,201) Presented as follows: Total deferred income tax assets 472 488 Total deferred income tax liabilities (13,781) (11,689) Net deferred income tax liabilities (13,309) (11,201) A valuation allowance has been established for certain loss and credit carryforwards, and outside basis temporary differences on investments that reduce deferred income tax assets to an amount that will more likely than not be realized. As at December 31, 2022, we recognized the benefit of unused tax loss carryforwards of $2.1 billion (2021 - $1.9 billion) in Canada which expire in 2030 and beyond. As at December 31, 2022, we recognized the benefit of unused tax loss carryforwards of $8.1 billion (2021 - $11.0 billion) in the US. Unused tax loss carryforwards of $0.2 billion (2021 - $3.5 billion) begin to expire in 2023, and unused tax loss carryforwards of $7.9 billion (2021 - $7.5 billion) have no expiration. We have not provided for deferred income taxes on the difference between the carrying value of substantially all of our foreign subsidiaries and their corresponding tax basis as the earnings of those subsidiaries are intended to be permanently reinvested in their operations. As such, these investments are not anticipated to give rise to income taxes in the foreseeable future. The difference between the carrying values of the investments and their tax bases is largely a result of unremitted earnings and currency translation adjustments. The unremitted earnings and currency translation adjustment for which no deferred taxes have been recognized in respect of foreign subsidiaries were $8.0 billion and $4.3 billion for the periods ended December 31, 2022 and 2021, respectively. If such earnings are remitted, in the form of dividends or otherwise, we may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities applicable to such amounts is not practicable. Enbridge and certain of our subsidiaries are subject to taxation in Canada, the US and other foreign jurisdictions. The material jurisdictions in which we are subject to potential examinations include the US (Federal) and Canada (Federal, Alberta and Québec). We are open to examination by Canadian tax authorities for the 2015 to 2022 tax years and by US tax authorities for the 2019 to 2022 tax years. We are currently under examination for income tax matters in Canada for the 2016 to 2019 tax years. We are not currently under examination for income tax matters in any other material jurisdiction where we are subject to income tax. UNRECOGNIZED TAX BENEFITS Year ended December 31, 2022 2021 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 76 121 Gross increases for tax positions of current year — 1 Gross decreases for tax positions of prior year (17) (26) Change in translation of foreign currency 1 (1) Lapses of statute of limitations (5) (19) Unrecognized tax benefits at end of year 55 76 The unrecognized tax benefits as at December 31, 2022, if recognized, would impact our effective income tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on our consolidated financial statements. We recognize accrued interest and penalties related to unrecognized tax benefits as a component of income taxes. Interest and penalties included in income taxes for the years ended December 31, 2022 and 2021 were a $1 million expense and $5 million recovery, respectively. As at December 31, 2022 and 2021, interest and penalties of $13 million and $12 million, respectively, have been accrued.

PENSION AND OTHER POSTRETIREMEN

PENSION AND OTHER POSTRETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2022
Retirement Benefits [Abstract]
PENSION AND OTHER POSTRETIREMENT BENEFITS	PENSION AND OTHER POSTRETIREMENT BENEFITS PENSION PLANS We sponsor Canadian and US contributory and non-contributory registered defined benefit and defined contribution pension plans, which provide benefits covering substantially all employees. The Canadian pension plans provide defined benefit and defined contribution pension benefits to our Canadian employees. The US pension plans provide defined benefit pension benefits to our US employees. We also sponsor supplemental non-contributory defined benefit pension plans, which provide non-registered benefits for certain employees in Canada and the US. Defined Benefit Pension Plan Benefits Benefits payable from the defined benefit pension plans are based on each plan participant’s years of service and final average remuneration. Some benefits are partially inflation-indexed after a plan participant’s retirement. Our contributions are made in accordance with independent actuarial valuations. Participant contributions to contributory defined benefit pension plans are based upon each plan participant’s current eligible remuneration. Defined Contribution Pension Plan Benefits Our contributions are based on each plan participant’s current eligible remuneration. Our contributions for some defined contribution pension plans are also based on age and years of service. Our defined contribution pension benefit costs are equal to the amount of contributions required to be made by us. Benefit Obligations, Plan Assets and Funded Status The following table details the changes in the projected benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit pension plans: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 4,600 4,855 1,184 1,243 Service cost 131 139 43 44 Interest cost 127 101 24 17 Participant contributions 29 28 — — Actuarial gain 1 (1,069) (329) (201) (21) Benefits paid (187) (194) (94) (84) Foreign currency exchange rate changes — — 77 (11) Other (1) — (4) (4) Projected benefit obligation at end of year 2 3,630 4,600 1,029 1,184 Change in plan assets Fair value of plan assets at beginning of year 4,536 4,077 1,160 1,062 Actual return/(loss) on plan assets (235) 505 (64) 151 Employer contributions 3 91 120 4 43 Participant contributions 29 28 — — Benefits paid (187) (194) (94) (84) Foreign currency exchange rate changes — — 78 (8) Other — — (4) (4) Fair value of plan assets at end of year 4 4,234 4,536 1,080 1,160 Overfunded/(underfunded) status at end of year 604 (64) 51 (24) Presented as follows: Deferred amounts and other assets 764 250 141 98 Accounts payable and other (9) (9) (5) (4) Other long-term liabilities (151) (305) (85) (118) 604 (64) 51 (24) 1 Actuarial gains in 2022 and 2021 primarily due to increase in the discount rates used to measure the benefit obligations. 2 The accumulated benefit obligation for our Canadian pension plans was $3.4 billion and $4.3 billion as at December 31, 2022 and 2021, respectively. The accumulated benefit obligation for our US pension plans was $1.0 billion and $1.1 billion as at December 31, 2022 and 2021, respectively. 3 Lower employer contributions in 2022 compared to 2021 primarily due to more plans in an overfunded status. 4 Assets in the amount of $10 million (2021 - $13 million) and $58 million (2021 - $84 million), related to our Canadian and US non-registered supplemental pension plan obligations, are held in grantor trusts and rabbi trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes. Certain of our pension plans have accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the accumulated benefit obligation and fair value of plan assets were as follows: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Accumulated benefit obligation 360 440 89 115 Fair value of plan assets 218 247 — — Certain of our pension plans have projected benefit obligations in excess of the fair value of plan assets. For these plans, the projected benefit obligation and fair value of plan assets were as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Projected benefit obligation 377 1,272 90 121 Fair value of plan assets 218 1,020 — — Amount Recognized in Accumulated Other Comprehensive Income The amount of pre-tax AOCI relating to our pension plans are as follows: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Net actuarial (gain)/loss (64) 226 40 92 Prior service (credit)/cost — — 1 (1) Total amount recognized in AOCI 1 (64) 226 41 91 1 Excludes amounts related to CTA. Net Periodic Benefit Cost and Other Amounts Recognized in Comprehensive Income The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our pension plans are as follows: Canada US Year ended December 31, 2022 2021 2020 2022 2021 2020 (millions of Canadian dollars) Service cost 131 139 148 43 44 44 Interest cost 1 127 101 128 24 17 31 Expected return on plan assets 1 (295) (252) (260) (85) (73) (88) Amortization/settlement of net actuarial loss 1 8 54 42 — 11 1 Amortization/curtailment of prior service credit 1 — — — (2) — (1) Net periodic benefit (credit)/cost (29) 42 58 (20) (1) (13) Defined contribution benefit cost 10 7 6 — — — Net pension (credit)/cost recognized in Earnings (19) 49 64 (20) (1) (13) Amount recognized in OCI: Amortization/settlement of net actuarial loss (2) (25) (21) — (11) (1) Amortization/curtailment of prior service credit — — — 2 — 1 Net actuarial (gain)/loss arising during the year (288) (291) 118 (52) (99) 100 Total amount recognized in OCI (290) (316) 97 (50) (110) 100 Total amount recognized in Comprehensive income (309) (267) 161 (70) (111) 87 1 Reported within Other income/(expense) in the Consolidated Statements of Earnings. Actuarial Assumptions The weighted average assumptions made in the measurement of the projected benefit obligation and net periodic benefit cost of our pension plans are as follows: Canada US 2022 2021 2020 2022 2021 2020 Projected benefit obligation Discount rate 5.1 % 3.2 % 2.6 % 4.9 % 2.6 % 2.2 % Rate of salary increase 2.9 % 2.9 % 2.3 % 2.8 % 2.8 % 2.7 % Cash balance interest credit rate N/A N/A N/A 4.3 % 4.3 % 4.3 % Net periodic benefit cost Discount rate 3.2 % 2.6 % 3.0 % 2.6 % 2.2 % 3.0 % Rate of return on plan assets 6.6 % 6.2 % 6.8 % 7.4 % 7.3 % 7.9 % Rate of salary increase 2.9 % 2.3 % 3.2 % 2.8 % 2.7 % 2.9 % Cash balance interest credit rate N/A N/A N/A 4.3 % 4.3 % 4.5 % OTHER POSTRETIREMENT BENEFIT PLANS We sponsor funded and unfunded defined benefit OPEB Plans, which provide non-contributory supplemental health, dental, life and health spending account benefit coverage for certain qualifying retired employees. Benefit Obligations, Plan Assets and Funded Status The following table details the changes in the accumulated postretirement benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit OPEB plans: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 274 321 173 254 Service cost 4 6 1 1 Interest cost 7 7 3 3 Participant contributions — — 6 8 Actuarial gain 1 (66) (51) (37) (69) Benefits paid (8) (9) (21) (22) Foreign currency exchange rate changes — — 11 (3) Other — — — 1 Accumulated postretirement benefit obligation at end of year 211 274 136 173 Change in plan assets Fair value of plan assets at beginning of year — — 201 188 Actual return/(loss) on plan assets — — (21) 22 Employer contributions 8 9 7 6 Participant contributions — — 6 8 Benefits paid (8) (9) (21) (22) Foreign currency exchange rate changes — — 13 (3) Other — — — 2 Fair value of plan assets at end of year — — 185 201 Overfunded/(underfunded) status at end of year (211) (274) 49 28 Presented as follows: Deferred amounts and other assets — — 75 71 Accounts payable and other (12) (12) — — Other long-term liabilities (199) (262) (26) (43) (211) (274) 49 28 1 Actuarial gains in 2022 and 2021 primarily due to increase in the discount rates used to measure the benefit obligations. Certain of our OPEB plans have accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the accumulated benefit obligation and fair value of plan assets were as follows: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Accumulated benefit obligation 211 274 76 94 Fair value of plan assets — — 50 51 Amount Recognized in Accumulated Other Comprehensive Income The amount of pre-tax AOCI relating to our OPEB plans are as follows: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Net actuarial gain (101) (35) (102) (104) Prior service credit (1) (1) (30) (37) Total amount recognized in AOCI 1 (102) (36) (132) (141) 1 Excludes amounts related to CTA. Net Periodic Benefit Cost and Other Amounts Recognized in Comprehensive Income The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our OPEB plans are as follows: Canada US Year ended December 31, 2022 2021 2020 2022 2021 2020 (millions of Canadian dollars) Service cost 4 6 5 1 1 2 Interest cost 1 7 7 8 3 3 7 Expected return on plan assets 1 — — — (12) (10) (12) Amortization/settlement of net actuarial gain 1 (1) — (1) (6) (1) (1) Amortization/curtailment of prior service credit 1 — — — (7) (7) (2) Net periodic benefit (credit)/cost recognized in Earnings 10 13 12 (21) (14) (6) Amount recognized in OCI: Amortization/settlement of net actuarial gain 1 — 1 6 1 1 Amortization/curtailment of prior service credit — — — 7 7 2 Net actuarial (gain)/loss arising during the year (67) (50) 21 (4) (80) 15 Prior service credit — — — — — (33) Total amount recognized in OCI (66) (50) 22 9 (72) (15) Total amount recognized in Comprehensive income (56) (37) 34 (12) (86) (21) 1 Reported within Other income/(expense) in the Consolidated Statements of Earnings. The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligation and net periodic benefit cost of our OPEB plans are as follows: Canada US 2022 2021 2020 2022 2021 2020 Accumulated postretirement benefit obligation Discount rate 5.3 % 3.2 % 2.6 % 4.9 % 2.4 % 2.0 % Net periodic benefit cost Discount rate 3.2 % 2.6 % 3.1 % 2.4 % 2.0 % 2.8 % Rate of return on plan assets N/A N/A N/A 6.0 % 6.0 % 6.7 % Assumed Health Care Cost Trend Rates The assumed rates for the next year used to measure the expected cost of benefits are as follows: Canada US 1 2022 2021 2022 2021 Health care cost trend rate assumed for next year 4.0 % 4.0 % 4.7 % 7.0 % Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.0 % 4.0 % 3.3 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2021 - 2045 2037 1 In addition, under the Enbridge Employee Services, Inc., Health Reimbursement Account Plan, health care costs will increase by 5.0% every three years. PLAN ASSETS We manage the investment risk of our pension funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash flow requirements of the plan; (iv) our operating environment and financial situation and our ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets. The overall expected rate of return on plan assets is based on the asset allocation targets with estimates for returns based on long-term expectations. The asset allocation targets and major categories of plan assets are as follows: Canada US Target December 31, Target December 31, Asset Category Allocation 2022 2021 Allocation 2022 2021 Equity securities 43.8 % 38.2 % 46.7 % 45.0 % 38.3 % 52.5 % Fixed income securities 28.4 % 31.7 % 29.8 % 20.0 % 20.5 % 18.4 % Alternatives 1 27.8 % 30.1 % 23.5 % 35.0 % 41.2 % 29.1 % 1 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Fund values are based on the net asset value of the funds that invest directly in the aforementioned underlying investments. The values of the investments have been estimated using the capital accounts representing the plan's ownership interest in the funds. Pension Plans The following table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level: Canada US Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2022 Cash and cash equivalents 272 — — 272 13 — — 13 Equity securities Canada — 355 — 355 — — — — Global — 1,263 — 1,263 — 414 — 414 Fixed income securities Government 201 435 — 636 — 87 — 87 Corporate — 433 — 433 — 121 — 121 Alternatives 4 — — 1,291 1,291 — — 445 445 Forward currency contracts — (16) — (16) — — — — Total pension plan assets at fair value 473 2,470 1,291 4,234 13 622 445 1,080 December 31, 2021 Cash and cash equivalents 180 — — 180 10 — — 10 Equity securities Canada 198 228 — 426 — — — — US 1 — — 1 — — — — Global — 1,693 — 1,693 — 609 — 609 Fixed income securities Government 258 459 — 717 — 86 — 86 Corporate — 453 — 453 — 118 — 118 Alternatives 4 — — 1,064 1,064 — — 337 337 Forward currency contracts — 2 — 2 — — — — Total pension plan assets at fair value 637 2,835 1,064 4,536 10 813 337 1,160 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Changes in the net fair value of pension plan assets classified as Level 3 in the fair value hierarchy were as follows: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Balance at beginning of year 1,064 912 337 289 Unrealized and realized gains 155 77 78 38 Purchases and settlements, net 72 75 30 10 Balance at end of year 1,291 1,064 445 337 OPEB Plans The following table summarizes the fair value of plan assets for our US funded OPEB plans recorded at each fair value hierarchy level: Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2022 Cash and cash equivalents 2 — — 2 Equity securities US — 34 — 34 Global — 62 — 62 Fixed income securities Government 46 5 — 51 Corporate — 8 — 8 Alternatives 4 — — 28 28 Total OPEB plan assets at fair value 48 109 28 185 December 31, 2021 Cash and cash equivalents 4 — — 4 Equity securities US — 39 — 39 Global — 75 — 75 Fixed income securities Government 47 6 — 53 Corporate — 8 — 8 Alternatives 4 — — 22 22 Total OPEB plan assets at fair value 51 128 22 201 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives includes investments in private debt, private equity, infrastructure and real estate. Changes in the net fair value of US funded OPEB plan assets classified as Level 3 in the fair value hierarchy were as follows: December 31, 2022 2021 (millions of Canadian dollars) Balance at beginning of year 22 22 Unrealized and realized gains 4 2 Purchases and settlements, net 2 (2) Balance at end of year 28 22 EXPECTED BENEFIT PAYMENTS Year ending December 31, 2023 2024 2025 2026 2027 2028-2032 (millions of Canadian dollars) Pension Canada 204 210 216 221 226 1,208 US 88 87 87 88 90 424 OPEB Canada 12 12 13 13 13 68 US 16 15 14 13 12 49 EXPECTED EMPLOYER CONTRIBUTIONS In 2023, we expect to contribute approximately $29 million and $5 million to the Canadian and US pension plans, respectively, and $12 million and $6 million to the Canadian and US OPEB plans, respectively. RETIREMENT SAVINGS PLANS In addition to the pension and OPEB plans discussed above, we also have defined contribution employee savings plans available to US employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 6.0% of eligible pay per pay period. For the year ended December 31, 2022, pre-tax employer matching contribution costs were $30 million ($27 million in each of 2021 and 2020).

LEASES

LEASES	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
LEASES	LEASES LESSEE We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of 1 month to 24 years as at December 31, 2022. For the years ended December 31, 2022, 2021 and 2020, we incurred operating lease expenses of $118 million, $95 million and $107 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings. For the years ended December 31, 2022, 2021 and 2020, operating lease payments to settle lease liabilities were $123 million, $118 million and $133 million, respectively. Operating lease payments are reported under Operating activities in the Consolidated Statements of Cash Flows. Supplemental Statements of Financial Position Information December 31, 2022 December 31, 2021 (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 680 645 Operating lease liabilities - current 3 87 92 Operating lease liabilities - long-term 3 677 612 Total operating lease liabilities 764 704 Finance leases Finance lease right-of-use assets, net 4 62 49 Finance lease liabilities - current 5 17 13 Finance lease liabilities - long-term 3 39 33 Total finance lease liabilities 56 46 Weighted average remaining lease term Operating leases 12 years 12 years Finance leases 5 years 7 years Weighted average discount rate Operating leases 4.2 % 4.1 % Finance leases 4.4 % 3.8 % 1 Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2022 were $47 million (December 31, 2021 - $51 million), $5 million (December 31, 2021 - $5 million) and $43 million (December 31, 2021 - $47 million), respectively. 2 Operating lease ROU assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position. 3 Current operating lease liabilities and long-term operating and finance lease liabilities are reported under Accounts payable and other and Other long-term liabilities, respectively, in the Consolidated Statements of Financial Position. 4 Finance lease ROU assets are reported under Property, plant and equipment, net in the Consolidated Statements of Financial Position. 5 Current finance lease liabilities are reported under Current portion of long-term debt in the Consolidated Statements of Financial Position. As at December 31, 2022, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance leases (millions of Canadian dollars) 2023 109 19 2024 110 16 2025 104 8 2026 90 8 2027 82 1 Thereafter 489 10 Total undiscounted lease payments 984 62 Less imputed interest (220) (6) Total 764 56 LESSOR We receive revenues from operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our operating leases have remaining lease terms of 1 month to 29 years as at December 31, 2022. Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Operating lease income 266 263 265 Variable lease income 321 333 361 Total lease income 1 587 596 626 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings. As at December 31, 2022, our future lease payments to be received under operating lease contracts where we are the lessor are as follows: Operating leases (millions of Canadian dollars) 2023 227 2024 215 2025 204 2026 198 2027 201 Thereafter 1,832 Future lease payments 2,877
LEASES	LEASES LESSEE We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of 1 month to 24 years as at December 31, 2022. For the years ended December 31, 2022, 2021 and 2020, we incurred operating lease expenses of $118 million, $95 million and $107 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings. For the years ended December 31, 2022, 2021 and 2020, operating lease payments to settle lease liabilities were $123 million, $118 million and $133 million, respectively. Operating lease payments are reported under Operating activities in the Consolidated Statements of Cash Flows. Supplemental Statements of Financial Position Information December 31, 2022 December 31, 2021 (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 680 645 Operating lease liabilities - current 3 87 92 Operating lease liabilities - long-term 3 677 612 Total operating lease liabilities 764 704 Finance leases Finance lease right-of-use assets, net 4 62 49 Finance lease liabilities - current 5 17 13 Finance lease liabilities - long-term 3 39 33 Total finance lease liabilities 56 46 Weighted average remaining lease term Operating leases 12 years 12 years Finance leases 5 years 7 years Weighted average discount rate Operating leases 4.2 % 4.1 % Finance leases 4.4 % 3.8 % 1 Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2022 were $47 million (December 31, 2021 - $51 million), $5 million (December 31, 2021 - $5 million) and $43 million (December 31, 2021 - $47 million), respectively. 2 Operating lease ROU assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position. 3 Current operating lease liabilities and long-term operating and finance lease liabilities are reported under Accounts payable and other and Other long-term liabilities, respectively, in the Consolidated Statements of Financial Position. 4 Finance lease ROU assets are reported under Property, plant and equipment, net in the Consolidated Statements of Financial Position. 5 Current finance lease liabilities are reported under Current portion of long-term debt in the Consolidated Statements of Financial Position. As at December 31, 2022, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance leases (millions of Canadian dollars) 2023 109 19 2024 110 16 2025 104 8 2026 90 8 2027 82 1 Thereafter 489 10 Total undiscounted lease payments 984 62 Less imputed interest (220) (6) Total 764 56 LESSOR We receive revenues from operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our operating leases have remaining lease terms of 1 month to 29 years as at December 31, 2022. Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Operating lease income 266 263 265 Variable lease income 321 333 361 Total lease income 1 587 596 626 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings. As at December 31, 2022, our future lease payments to be received under operating lease contracts where we are the lessor are as follows: Operating leases (millions of Canadian dollars) 2023 227 2024 215 2025 204 2026 198 2027 201 Thereafter 1,832 Future lease payments 2,877

OTHER INCOME_(EXPENSE)

OTHER INCOME/(EXPENSE)	12 Months Ended
	Dec. 31, 2022
Other Income and Expenses [Abstract]
OTHER INCOME/(EXPENSE)	OTHER INCOME/(EXPENSE) Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Gain/(loss) on dispositions (12) 319 (17) Realized foreign currency gain/(loss) 92 126 (10) Unrealized foreign currency gain/(loss) (1,094) 160 191 Net defined pension and OPEB credit 239 150 148 Other 186 224 (74) (589) 979 238

CHANGES IN OPERATING ASSETS AND

CHANGES IN OPERATING ASSETS AND LIABILITIES	12 Months Ended
	Dec. 31, 2022
CHANGES IN OPERATING ASSETS AND LIABILITIES
CHANGES IN OPERATING ASSETS AND LIABILITIES	CHANGES IN OPERATING ASSETS AND LIABILITIES Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Accounts receivable and other (967) (1,228) 1,546 Accounts receivable from affiliates 17 (38) 8 Inventory (599) (118) (254) Deferred amounts and other assets 1 (195) (586) Accounts payable and other 1,100 87 (770) Accounts payable to affiliates 16 52 1 Interest payable 58 43 31 Other long-term liabilities 362 (69) 117 (12) (1,466) 93

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS Related party transactions are conducted in the normal course of business and, unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. We provide transportation services to several significantly influenced investees which we record as transportation and other servic es revenue. We also purchase and sell natural gas and crude oil with several of our significantly influenced investees. Thes e revenues and costs are recorded as commodity sales and commodity costs. We contract for firm transportation services to meet our annual natural gas supply requirements which we record as gas distribution costs. Our transactions with significantly influenced investees are as follows: Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Transportation and other revenues 185 237 219 Commodity sales 51 20 21 Operating and administrative 1 503 380 338 Commodity costs 2 778 790 518 Gas distribution costs 136 131 135 1 During the years ended December 31, 2022, 2021 and 2020, we had Operating and administrative costs from the Seaway Crude Pipeline System of $495 million, $389 million and $342 million, respectively. These costs are a result of an operational contract where we utilize capacity on Seaway Crude Pipeline System assets for use in our Liquids Pipelines business. 2 During the years ended December 31, 2022, 2021 and 2020, we had Commodity costs from Aux Sable Canada LP of $571 million, $447 million and $91 million, respectively. LONG-TERM NOTES RECEIVABLE FROM AFFILIATES As at December 31, 2022, amounts receivable from affiliates include a series of loans totaling $752 million (2021 - $954 million), which require quarterly or semi-annual interest payments at annual interest rates ranging from 3% to 8%. Interest income recognized from these notes totaled $30 million, $39 million and $44 million for the years ended December 31, 2022, 2021 and 2020, respectively. The amounts receivable from affiliates are included in Deferred amounts and other assets in the Consolidated Statements of Financial position.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS As at December 31, 2022, we have commitments as detailed below: Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Annual debt maturities 1 78,742 6,024 8,220 6,051 3,730 10,344 44,373 Purchase of services, pipe and other materials, including transportation 2 10,661 3,553 1,513 1,070 1,001 767 2,757 Maintenance agreements 3 536 53 53 53 53 55 269 Right-of-ways commitments 1,474 45 45 46 46 46 1,246 Total 91,413 9,675 9,831 7,220 4,830 11,212 48,645 1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discounts, debt issuance costs, finance lease obligations and fair value adjustment. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. 2 Includes capital and operating commitments. Consists primarily of firm capacity payments that provide us with uninterrupted firm access to natural gas and crude oil transportation and storage contracts; contractual obligations to purchase physical quantities of natural gas; and power commitments. 3 Consists primarily of maintenance service contracts for our wind and solar assets. ENVIRONMENTAL We are subject to various Canadian and US federal, provincial/state and local laws relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us. Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and Enbridge and its affiliates are, at times, subject to environmental remediation obligations at various sites where we operate. We manage this environmental risk through appropriate environmental policies, programs and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of costs arising from environmental incidents associated with our operating activities. AUX SABLE On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. On November 27, 2019, the counterparty filed an amended amended claim providing further particulars of its claim against Aux Sable, increasing its damages claimed, and adding defendants Aux Sable Liquid Products Inc. and Aux Sable Extraction LLC (general partners of the previously existing defendants). Aux Sable filed an amended Statement of Defence responding to the amended amended claim on January 31, 2020. While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on our consolidated financial position or results of operations. OTHER LITIGATION We and our subsidiaries are subject to 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. 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.

GUARANTEES

GUARANTEES	12 Months Ended
	Dec. 31, 2022
Guarantees [Abstract]
GUARANTEES	GUARANTEES In the normal course of conducting business, we may enter into agreements which indemnify third parties and affiliates. We may also be a party to agreements with subsidiaries, jointly owned entities, unconsolidated entities such as equity method investees, or entities with other ownership arrangements that require us to provide financial and performance guarantees. Financial guarantees include stand-by letters of credit, debt guarantees, surety bonds and indemnifications. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included in our Consolidated Statements of Financial Position. Performance guarantees require us to make payments to a third party if the guaranteed entity does not perform on its contractual obligations, such as debt agreements, purchase or sale agreements, and construction contracts and leases. We typically enter into these arrangements to facilitate commercial transactions with third parties. Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in matters such as breaches of representations, warranties or covenants, loss or damages to property, environmental liabilities, and litigation and contingent liabilities. We may indemnify third parties for certain liabilities relating to environmental matters arising from operations prior to the purchase or transfer of certain assets and interests. Similarly, we may indemnify the purchaser of assets for certain tax liabilities incurred while we owned the assets, a misrepresentation related to taxes that result in a loss to the purchaser or other certain tax liabilities related to those assets.

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2022
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA (UNAUDITED)	QUARTERLY FINANCIAL DATA (UNAUDITED) Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2022 Operating revenues 15,097 13,215 11,573 13,424 53,309 Operating income/(loss) 2,420 1,520 1,778 (540) 5,178 Earnings/(loss) 2,057 607 1,383 (1,109) 2,938 Earnings/(loss) attributable to controlling interests 2,029 595 1,362 (983) 3,003 Earnings/(loss) attributable to common shareholders 1,927 450 1,279 (1,067) 2,589 Earnings/(loss) per common share Basic 0.95 0.22 0.63 (0.53) 1.28 Diluted 0.95 0.22 0.63 (0.53) 1.28 2021 Operating revenues 12,187 10,948 11,466 12,470 47,071 Operating income 2,548 1,816 1,388 2,053 7,805 Earnings 2,014 1,521 814 1,965 6,314 Earnings attributable to controlling interests 1,992 1,484 780 1,933 6,189 Earnings attributable to common shareholders 1,900 1,394 682 1,840 5,816 Earnings per common share Basic 0.94 0.69 0.34 0.91 2.87 Diluted 0.94 0.69 0.34 0.91 2.87

SIGNIFICANT ACCOUNTING POLICI_2

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
BASIS OF PRESENTATION AND USE OF ESTIMATES	BASIS OF PRESENTATION AND USE OF ESTIMATES The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: variable consideration included in revenue (Note 4) ; carrying values of regulatory assets and liabilities (Note 7) ; purchase price allocations (Note 8) ; unbilled revenues; expected credit losses; depreciation rates and carrying value of property, plant and equipment (Note 11) ; amortization rates and carrying value of intangible assets (Note 15) ; measurement of goodwill (Note 16) ; fair value of asset retirement obligations (ARO) (Note 19) ; valuation of stock-based compensation (Note 22) ; fair value of financial instruments (Note 24) ; provisions for income taxes (Note 25) ; assumptions used to measure retirement benefits and OPEB (Note 26) ; commitments and contingencies (Note 31) ; and estimates of losses related to environmental remediation obligations (Note 31) . Actual results could differ from these estimates.
RECLASSIFICATION	Certain comparative figures in our consolidated financial statements have been reclassified to conform to the current year's presentation.
PRINCIPLES OF CONSOLIDATION	PRINCIPLES OF CONSOLIDATION The consolidated financial statements include our accounts and the accounts of our subsidiaries and VIEs for which we are the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. Where we conclude that we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are the primary beneficiary. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. We assess the primary beneficiary determination for a VIE on an ongoing basis if there are changes in the facts and circumstances related to a VIE. If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity. The consolidated financial statements also include the accounts of any limited partnerships where we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses. All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method.
REGULATION	REGULATION Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the Canada Energy Regulator (CER), the Federal Energy Regulatory Commission (FERC), the Alberta Energy Regulator, the Ontario Energy Board (OEB) and la Régie de l’energie du Québec. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under US GAAP for non-rate-regulated entities. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or to be paid to cover future abandonment costs in relation to the CER’s Land Matters Consultation Initiative (LMCI). Regulatory assets are assessed for impairment if we identify an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. We believe that the recovery of our regulatory assets as at December 31, 2022 is probable over the periods described in Note 7 - Regulatory Matters . Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. The corresponding impact on earnings is included in Interest expense for the interest component and Other income/(expense) for the equity component. In the absence of rate regulation, we would capitalize interest using a capitalization rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation relating to the equity component would not be recognized. The equity component of AFUDC is included as a non-cash reconciling item to earnings within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows. Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains and losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified. With the approval of regulators, certain operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred . For certain regulated operations to which US GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with US GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with US GAAP and no regulatory asset is recorded.
REVENUE RECOGNITION/NATURAL GAS IMBALANCES	REVENUE RECOGNITION For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer creditworthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from our liquids and natural gas pipeline businesses are recognized under the terms of committed delivery contracts, rather than the cash tolls received. Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts ratably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry. We recognize revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote. We also have long-term contracts where the revenue profile does not align with the cash receipt schedule, resulting in the recognition of deferred revenue. Certain offshore pipeline transportation contracts require us to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay us a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received. For the years ended December 31, 2022, 2021 and 2020, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $238 million, $127 million and $292 million, respectively. For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Natural gas utility revenues are recorded based on regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in our distribution franchise areas. Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded on a gross basis as the related contracts are not held for trading purposes and we are acting as the principal in the transactions. NATURAL GAS IMBALANCES The Consolidated Statements of Financial Position include balances as a result of differences in gas volumes received from, and delivered for, customers. As settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates.
DERIVATIVE INSTRUMENTS AND HEDGING	DERIVATIVE INSTRUMENTS AND HEDGING Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Commodity sales, Transportation and other services revenue, Commodity costs, Operating and administrative expense, Other income/(expense) and Interest expense. Derivatives in Qualifying Hedging Relationships We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires us to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges. Cash Flow Hedges We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. The change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income/(loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings. If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized in earnings concurrently with the related transaction. If an anticipated hedged transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. Fair Value Hedges We may use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged risk of the asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged risk of the asset or liability ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. Net Investment Hedges Gains and losses arising from the translation of our net investment in foreign operations from their functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA), a component of OCI. We currently have designated a portion of our US dollar-denominated debt, as well as a portfolio of foreign exchange forward contracts in prior periods, as a hedge of our net investment in US dollar-denominated investments and subsidiaries. As a result, the change in fair value of the foreign currency derivatives, as well as the translation of US dollar-denominated debt, are reflected in OCI. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from the disposal of a foreign operation. Classification of Derivatives We recognize the fair value of derivative instruments in the Consolidated Statements of Financial Position as current and non-current assets or liabilities depending on the timing of settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows. Balance Sheet Offset Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when we have the legal right and intention to settle them on a net basis. Transaction Costs Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and account for these costs as a reduction to Long-term debt in the Consolidated Statements of Financial Position. These costs are amortized using the effective interest rate method over the term of the related debt instrument and are recorded in Interest expense.
EQUITY INVESTMENTS	EQUITY INVESTMENTS Equity investments over which we exercise significant influence, but do not have controlling financial interests, are accounted for using the equity method. These investments are initially measured at cost and are adjusted for our proportionate share of undistributed equity earnings or loss. Our equity investments are increased for contributions made to, and decreased for distributions received from, the investee. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, we capitalize interest costs associated with the investment during such period.
RESTRICTED LONG-TERM INVESTMENTS	RESTRICTED LONG-TERM INVESTMENTS Long-term investments that are restricted as to withdrawal or usage for the purposes of the CER’s LMCI are presented as Restricted long-term investments in the Consolidated Statements of Financial Position.
OTHER INVESTMENTS	OTHER INVESTMENTS Generally, we classify equity investments in entities over which we do not exercise significant influence and that do not have readily determinable fair values as other investments measured using the fair value measurement alternative (FVMA). These investments are recorded at cost less impairment, if any, and adjusted for the impact of observable price changes occurring in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the FVMA are reviewed for impairment each reporting period and written down to their fair value if objective evidence of impairment is identified. Equity investments with readily determinable fair values are measured at fair value through earnings. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established. Investments in debt securities are classified as available-for-sale and measured at fair value through OCI.
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us in such entities is reflected as Noncontrolling interests within the equity section of the Consolidated Statements of Financial Position.
INCOME TAXES	INCOME TAXES Income taxes are accounted for using the liability method. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, to the extent that taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income tax expense.
FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION	FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated to the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the exchange rate in effect as at the balance sheet date. Exchange gains and losses resulting from the translation of monetary assets and liabilities are included in earnings in the period in which they arise.
CASH AND CASH EQUIVALENTS	CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased.
RESTRICTED CASH	RESTRICTED CASH Cash and cash equivalents that are restricted as to withdrawal or usage for the purposes of the CER’s LMCI or in accordance with specific commercial arrangements are presented as Restricted cash in the Consolidated Statements of Financial Position.
LOANS AND RECEIVABLES	LOANS AND RECEIVABLES Long-term notes receivable from affiliates are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. Interest income is recognized in earnings as it is earned with the passage of time.
CURRENT EXPECTED CREDIT LOSSES	CURRENT EXPECTED CREDIT LOSSES For accounts receivable, a loss allowance matrix is utilized to measure lifetime expected credit losses. The matrix contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations. Other loan receivables and applicable off-balance sheet commitments utilize a discounted cash flow methodology which calculates the current expected credit losses based on historical default probability rates associated with the credit rating of the counterparty and the related term of the loan or commitment, adjusted for forward-looking information and management expectations.
INVENTORY	INVENTORY Inventory is comprised of natural gas held in storage by Enbridge Gas, crude oil and natural gas held primarily by businesses in the Energy Services segment and materials and supplies. Natural gas held in storage by Enbridge Gas is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of gas purchased is deferred as a liability for future refund, or as an asset for collection, as approved by the OEB. Other inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs in the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value. Materials and supplies inventory is recorded at the lower of average cost or net realizable value.
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. We capitalize interest incurred during construction for non-rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation.
LEASES	LEASES We recognize an arrangement as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We recognize right-of-use (ROU) assets and the related lease liabilities in the Consolidated Statements of Financial Position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach applied for other long-lived assets. Lease liabilities and ROU assets require the use of judgment and estimates which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing.
DEFERRED AMOUNTS AND OTHER ASSETS	DEFERRED AMOUNTS AND OTHER ASSETS Deferred amounts and other assets primarily consists of costs that regulatory authorities have permitted, or are expected to permit, to be recovered through future rates, including: deferred income taxes; the fair value adjustment to long-term debt; actual cost of removal of previously retired or decommissioned plant assets; the difference between the actual cost and approved cost of natural gas reflected in rates; and actuarial gains and losses arising from defined benefit pension plans.
INTANGIBLE ASSETS	INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects . Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due.
GOODWILL	GOODWILL Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1. We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components, and whether the economic and regulatory characteristics are similar. Our reporting units are Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation. The Renewable Power Generation reporting unit had goodwill beginning in the third quarter of 2022. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, the assessment of macroeconomic trends, changes to regulatory environments, capital accessibility, operating income trends and changes to industry conditions. Based on our assessment of qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment assessment is performed. The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. The fair value of our reporting units is estimated using a combination of discounted cash flow and earnings multiples techniques. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, expected future capital expenditures and working capital levels, as well as terminal value growth rates for the Liquids Pipelines, Gas Transmission and Renewable Power Generation reporting units, and projected regulatory rate base and rate base multiple for the Gas Distribution and Storage reporting unit. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multiples for reporting units. The allocation of goodwill to held-for-sale and disposed businesses is based on the relative fair value of businesses included in the relevant reporting unit. On April 1, 2022, we performed our annual goodwill impairment assessment which consisted of a qualitative assessment for the Liquids Pipelines, Gas Transmission and Gas Distribution and Storage reporting units and did not identify impairment indicators. Due to changes in the macroeconomic environment that have led to a rise in interest rates, we performed a quantitative assessment for the Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation reporting units as at December 1, 2022, which resulted in the recognition of an impairment loss for Gas Transmission (Note 16) . Goodwill impairments were not identified in relation to the Liquids Pipelines, Gas Distribution and Storage or Renewable Power Generation reporting units. Also, we did not identify any indicators of goodwill impairment during the remainder of 2022.
IMPAIRMENT	IMPAIRMENT We review the carrying values of our long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds its expected undiscounted cash flows, we will calculate fair value based on the discounted cash flows and write the asset down to the extent that the carrying value exceeds the fair value.
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. Fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, it is not possible to make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements.
PENSION AND OTHER POSTRETIREMENT BENEFITS	PENSION AND OTHER POSTRETIREMENT BENEFITS We sponsor defined benefit and defined contribution pension plans, as well as defined benefit OPEB plans. Obligations and net periodic benefit costs for defined benefit pension and OPEB plans are estimated using the projected unit credit method, which is based on years of service, as well as our best estimates of actuarial assumptions such as discount rates, future salary levels, other cost escalations, employees' retirement ages, and mortality. We determine discount rates using market yields of high-quality corporate bonds with maturities that approximate the estimated timing of future benefit payments. Plan assets are measured at fair value. The expected return on plan assets is determined using the long-term target asset mixes in our investment policies and long-term market expectations. Actuarial gains and losses arise from the difference between the actual and expected return on plan assets, and changes in actuarial assumptions such as discount rates. Periodic net actuarial gains and losses and prior service costs are accumulated and presented as follows in the Consolidated Statements of Financial Position: • as a component of AOCI, for our non-utilities' defined benefit pension plans and all defined benefit OPEB plans; and • as a component of Deferred amounts and other assets and/or Other long-term liabilities, for our utilities' defined benefit pension plans, to the extent that the net actuarial gains and losses and prior service costs have been permitted or are expected to be permitted by the regulators, to be recovered through future rates. Net periodic benefit cost is recognized in earnings and includes: • current service cost; • interest cost; • expected return on plan assets; • amortization of prior service costs over the expected average remaining service life of the plans' active employee group; and • amortization of net actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the fair value of plan assets, over the expected average remaining service life of the plans' active employee group. Our utility operations also record regulatory adjustments for the difference between net periodic benefit costs for accounting versus ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent net periodic benefit costs are expected to be recovered from or refunded to customers, respectively, in future rates. In the absence of rate regulation, regulatory assets or liabilities would not be recorded and net periodic benefit costs would be charged to earnings and OCI on an accrual basis. For defined contribution plans, our contributions are expensed when the contribution occurs.
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION Incentive Stock Options (ISO) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the ISO granted as calculated by the Black-Scholes-Merton model and is recognized on a straight-line basis over the shorter of the vesting period or the period to early retirement eligibility, with a corresponding credit to Additional paid-in capital. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised. Performance Stock Units (PSU) and Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured each reporting period. PSUs vest at the completion of a three-year term and RSUs vest one-third annually from the grant date. During the vesting term, compensation expense is recorded based on the number of units outstanding and the current market price of Enbridge’s common shares with an offset to Accounts payable and other or Other long-term liabilities. The value of the PSUs is also dependent on our performance relative to performance targets set out under the plan. We also award share settled RSUs which vest at the completion of a three-year term. During the vesting term, compensation expense is recorded based on the number of units granted and the market price of Enbridge's common shares on the day immediately preceding the grant date, with an offset to Additional paid-in capital.
COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES	COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in Accounts payable and other and Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in the Consolidated Statements of Financial Position. Liabilities for other commitments and contingencies are recognized when, after fully analyzing available information, we determine it is either probable that an asset has been impaired or that a liability has been incurred, and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we recognize the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. We expense legal costs associated with loss contingencies as such costs are incurred.
CHANGES IN ACCOUNTING POLICIES	CHANGES IN ACCOUNTING POLICIES There were no changes in accounting policies during the year ended December 31, 2022. ADOPTION OF NEW ACCOUNTING STANDARDS

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
	Dec. 31, 2022
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 Year ended December 31, 2022 (millions of Canadian dollars) Transportation revenue 11,283 5,012 782 — — — 17,077 Storage and other revenue 235 350 308 — — — 893 Gas gathering and processing revenue — 22 — — — — 22 Gas distribution revenue — — 5,643 — — — 5,643 Electricity and transmission revenue — — — 281 — — 281 Total revenue from contracts with customers 11,518 5,384 6,733 281 — — 23,916 Commodity sales — — — — 29,150 — 29,150 Other revenue 1,2 (81) 39 (20) 305 — — 243 Intersegment revenue 615 3 16 (4) 25 (655) — Total revenue 12,052 5,426 6,729 582 29,175 (655) 53,309 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2021 (millions of Canadian dollars) Transportation revenue 9,492 4,364 676 — — — 14,532 Storage and other revenue 147 255 246 — — — 648 Gas gathering and processing revenue — 49 — — — — 49 Gas distribution revenue — — 4,026 — — — 4,026 Electricity and transmission revenue — — — 177 — — 177 Total revenue from contracts with customers 9,639 4,668 4,948 177 — — 19,432 Commodity sales — — — — 26,873 — 26,873 Other revenue 1,2 375 42 13 336 — — 766 Intersegment revenue 567 1 19 (1) 44 (630) — Total revenue 10,581 4,711 4,980 512 26,917 (630) 47,071 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2020 (millions of Canadian dollars) Transportation revenue 9,161 4,523 674 — — — 14,358 Storage and other revenue 94 274 203 — — — 571 Gas gathering and processing revenue — 27 — — — — 27 Gas distribution revenue — — 3,663 — — — 3,663 Electricity and transmission revenue — — — 198 — — 198 Total revenue from contracts with customers 9,255 4,824 4,540 198 — — 18,817 Commodity sales — — — — 19,259 — 19,259 Other revenue 1,2 584 44 17 389 — (23) 1,011 Intersegment revenue 584 2 12 — 24 (622) — Total revenue 10,423 4,870 4,569 587 19,283 (645) 39,087 1 Includes mark-to-market losses from our hedging program 2 Includes revenues from lease contracts. Refer to Note 27 - Leases .
Schedule Of Contract with Customer, Asset And Liability	Contract Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at December 31, 2022 3,183 230 2,241 Balance as at December 31, 2021 2,369 213 1,898
Schedule Of Performance Obligations	Performance Obligations Segment Nature of Performance Obligation Liquids Pipelines • Transportation and storage of crude oil and natural gas liquids (NGL) Gas Transmission and Midstream • Transportation, storage, gathering, compression and treating of natural gas • Transportation of NGL • Sale of crude oil, natural gas and NGL Gas Distribution and Storage • Supply and delivery of natural gas • Transportation of natural gas • Storage of natural gas Renewable Power Generation • Generation and transmission of electricity • Delivery of electricity from renewable energy generation facilities
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	Recognition and Measurement of Revenue Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2022 (millions of Canadian dollars) Revenue from products transferred at a point in time — — 127 — 127 Revenue from products and services transferred over time 1 11,518 5,384 6,606 281 23,789 Total revenue from contracts with customers 11,518 5,384 6,733 281 23,916 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2021 (millions of Canadian dollars) Revenue from products transferred at a point in time — — 70 — 70 Revenue from products and services transferred over time 1 9,639 4,668 4,878 177 19,362 Total revenue from contracts with customers 9,639 4,668 4,948 177 19,432 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2020 (millions of Canadian dollars) Revenue from products transferred at a point in time — — 60 — 60 Revenue from products and services transferred over time 1 9,255 4,824 4,480 198 18,757 Total revenue from contracts with customers 9,255 4,824 4,540 198 18,817 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.

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
Schedule of Reporting Information by Segment	Segmented information for the years ended December 31, 2022, 2021 and 2020 is as follows: Year ended December 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) Revenues (Note 4) 12,052 5,426 6,729 582 29,175 (655) 53,309 Commodity and gas distribution costs — — (3,693) (16) (29,525) 645 (32,589) Operating and administrative (4,287) (2,254) (1,289) (255) (49) (85) (8,219) Impairment of long-lived assets (245) — — (235) (13) (48) (541) Impairment of goodwill (Note 16) — (2,465) — — — — (2,465) Income/(loss) from equity investments (Note 13) 785 1,133 1 141 — (4) 2,056 Gain on joint venture merger transaction (Note 13) — 1,076 — — — — 1,076 Other income/(expense) (Note 28) 59 210 79 45 (5) (977) (589) Earnings/(loss) before interest, income taxes and depreciation and amortization 8,364 3,126 1,827 262 (417) (1,124) 12,038 Depreciation and amortization (4,317) Interest expense (Note 18) (3,179) Income tax expense (Note 25) (1,604) Earnings 2,938 Capital expenditures 1 1,418 1,690 1,499 50 — 33 4,690 Total property, plant and equipment, net (Note 11) 53,567 29,666 17,857 3,082 6 282 104,460 Year ended December 31, 2021 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues (Note 4) 10,581 4,711 4,980 512 26,917 (630) 47,071 Commodity and gas distribution costs (25) — (2,147) — (27,174) 644 (28,702) Operating and administrative (3,431) (1,877) (1,143) (180) (48) (33) (6,712) Income/(loss) from equity investments (Note 13) 759 813 42 101 — (4) 1,711 Impairment of equity investments (Note 13) — (111) — — — — (111) Other income/(expense) (Note 28) 13 135 385 75 (8) 379 979 Earnings/(loss) before interest, income taxes and depreciation and amortization 7,897 3,671 2,117 508 (313) 356 14,236 Depreciation and amortization (3,852) Interest expense (Note 18) (2,655) Income tax expense (Note 25) (1,415) Earnings 6,314 Capital expenditures 1 4,051 2,420 1,343 16 1 54 7,885 Total property, plant and equipment, net (Note 11) 52,530 27,028 16,904 3,315 23 267 100,067 Year ended December 31, 2020 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues (Note 4) 10,423 4,870 4,569 587 19,283 (645) 39,087 Commodity and gas distribution costs (20) — (1,810) (2) (19,450) 613 (20,669) Operating and administrative (3,331) (1,859) (1,091) (191) (67) (210) (6,749) Income/(loss) from equity investments (Note 13) 558 479 9 94 (3) (1) 1,136 Impairment of equity investments (Note 13) — (2,351) — — — — (2,351) Other income/(expense) (Note 28) 53 (52) 71 35 1 130 238 Earnings/(loss) before interest, income taxes and depreciation and amortization 7,683 1,087 1,748 523 (236) (113) 10,692 Depreciation and amortization (3,712) Interest expense (Note 18) (2,790) Income tax expense (Note 25) (774) Earnings 3,416 Capital expenditures 1 2,033 2,130 1,134 81 2 90 5,470 Total property, plant and equipment, net 48,799 25,745 16,079 3,495 24 429 94,571 1 Includes allowance for equity funds used during construction.
Schedule of Revenues by Geographical Segments	Revenues 1 Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Canada 27,498 20,474 16,453 US 25,811 26,597 22,634 53,309 47,071 39,087 1 Revenues are based on the country of origin of the product or service sold.
Schedule of Property, Plant And Equipment By Geographical Segments	Property, Plant and Equipment 1 December 31, 2022 2021 (millions of Canadian dollars) Canada 47,602 47,102 US 56,858 52,965 104,460 100,067 1 Amounts are based on the location where the assets are held.

EARNINGS PER COMMON SHARE (Tabl

EARNINGS PER COMMON SHARE (Tables)	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
Schedule of Weighted Average Shares Outstanding Used to Calculate Basic and Diluted Earnings Per Share	Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows: December 31, 2022 2021 2020 (number of shares in millions) Weighted average shares outstanding 2,025 2,023 2,020 Effect of dilutive options and RSUs 4 2 1 Diluted weighted average shares outstanding 2,029 2,025 2,021

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2022
Regulated Operations [Abstract]
Schedule of Regulatory Assets	December 31, 2022 2021 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Purchase gas variance 190 15 2023 Under-recovery of fuel costs 109 114 2023 Other current regulatory assets 305 130 2023 Total current regulatory assets 1 (Note 9) 604 259 Long-term regulatory assets Deferred income taxes 2 4,473 4,176 Various Long-term debt 3 378 398 2032-2046 Negative salvage 4 265 243 Various Purchase gas variance 244 215 2024 Accounting policy changes 5 219 157 Various Pension plan receivable 6 40 78 Various Other long-term regulatory assets 244 339 Various Total long-term regulatory assets 1 5,863 5,606 Total regulatory assets 6,467 5,865 Current regulatory liabilities Other current regulatory liabilities 167 106 2023 Total current regulatory liabilities 7 167 106 Long-term regulatory liabilities Future removal and site restoration reserves 8 1,615 1,543 Various Regulatory liability related to US income taxes 9 918 895 2050-2072 Pipeline future abandonment costs (Note 14) 610 649 Various Pension plan payable 6 231 — Various Other long-term regulatory liabilities 250 234 Various Total long-term regulatory liabilities 7 3,624 3,321 Total regulatory liabilities 3,791 3,427 1 Current regulatory assets are included in Accounts receivable and other, while long-term regulatory assets are included in Deferred amounts and other assets. 2 Represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in future regulator-approved rates and recovered from customers. The recovery period depends on the timing of the reversal of temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded. 3 Represents our regulatory offset to the fair value adjustment to debt acquired in our merger with Spectra Energy Corp. (Spectra Energy). The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished at an amount higher than the carrying value. 4 The negative salvage balance represents the recovery in future rates of the actual cost of removal of previously retired or decommissioned plant assets, as approved by the FERC. 5 This deferral primarily consists of unamortized accumulated actuarial gains/losses and past service costs incurred by Union Gas Limited, relating to the period up to our merger with Spectra Energy, which were previously recorded in AOCI. The amortization of this balance is recognized as a component of accrual-based pension expenses, which are included in Other income/(expense) and recovered in rates, as previously approved by the OEB. 6 Represents the regulatory offset to our pension liability to the extent that it is expected to be included in regulator-approved future rates and recovered from customers. The settlement period for this balance is not determinable. In the absence of rate-regulated accounting, this regulatory balance and the related pension expense would be recorded in earnings and OCI. 7 Current regulatory liabilities are included in Accounts payable and other , while long-term regulatory liabilities are included in Other long-term liabilities. 8 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the OEB, to fund future costs of removal and site restoration relating to property, plant and equipment. These costs are collected as part of the depreciation expense charged on property, plant and equipment that is reflected in rates. The settlement of this balance will occur over the long-term as costs are incurred. In the absence of rate-regulated accounting, depreciation rates would not include a charge for removal and site restoration and costs would be charged to earnings as incurred with recognition of revenue for amounts previously collected. 9 The regulatory liability related to US income taxes resulted from the US tax reform legislation dated December 22, 2017. These balances will be refunded to customers in accordance with the respective rate settlements approved by the FERC.
Schedule of Regulatory Liabilities	December 31, 2022 2021 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Purchase gas variance 190 15 2023 Under-recovery of fuel costs 109 114 2023 Other current regulatory assets 305 130 2023 Total current regulatory assets 1 (Note 9) 604 259 Long-term regulatory assets Deferred income taxes 2 4,473 4,176 Various Long-term debt 3 378 398 2032-2046 Negative salvage 4 265 243 Various Purchase gas variance 244 215 2024 Accounting policy changes 5 219 157 Various Pension plan receivable 6 40 78 Various Other long-term regulatory assets 244 339 Various Total long-term regulatory assets 1 5,863 5,606 Total regulatory assets 6,467 5,865 Current regulatory liabilities Other current regulatory liabilities 167 106 2023 Total current regulatory liabilities 7 167 106 Long-term regulatory liabilities Future removal and site restoration reserves 8 1,615 1,543 Various Regulatory liability related to US income taxes 9 918 895 2050-2072 Pipeline future abandonment costs (Note 14) 610 649 Various Pension plan payable 6 231 — Various Other long-term regulatory liabilities 250 234 Various Total long-term regulatory liabilities 7 3,624 3,321 Total regulatory liabilities 3,791 3,427 1 Current regulatory assets are included in Accounts receivable and other, while long-term regulatory assets are included in Deferred amounts and other assets. 2 Represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in future regulator-approved rates and recovered from customers. The recovery period depends on the timing of the reversal of temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded. 3 Represents our regulatory offset to the fair value adjustment to debt acquired in our merger with Spectra Energy Corp. (Spectra Energy). The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished at an amount higher than the carrying value. 4 The negative salvage balance represents the recovery in future rates of the actual cost of removal of previously retired or decommissioned plant assets, as approved by the FERC. 5 This deferral primarily consists of unamortized accumulated actuarial gains/losses and past service costs incurred by Union Gas Limited, relating to the period up to our merger with Spectra Energy, which were previously recorded in AOCI. The amortization of this balance is recognized as a component of accrual-based pension expenses, which are included in Other income/(expense) and recovered in rates, as previously approved by the OEB. 6 Represents the regulatory offset to our pension liability to the extent that it is expected to be included in regulator-approved future rates and recovered from customers. The settlement period for this balance is not determinable. In the absence of rate-regulated accounting, this regulatory balance and the related pension expense would be recorded in earnings and OCI. 7 Current regulatory liabilities are included in Accounts payable and other , while long-term regulatory liabilities are included in Other long-term liabilities. 8 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the OEB, to fund future costs of removal and site restoration relating to property, plant and equipment. These costs are collected as part of the depreciation expense charged on property, plant and equipment that is reflected in rates. The settlement of this balance will occur over the long-term as costs are incurred. In the absence of rate-regulated accounting, depreciation rates would not include a charge for removal and site restoration and costs would be charged to earnings as incurred with recognition of revenue for amounts previously collected. 9 The regulatory liability related to US income taxes resulted from the US tax reform legislation dated December 22, 2017. These balances will be refunded to customers in accordance with the respective rate settlements approved by the FERC.

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Tables)	12 Months Ended
	Dec. 31, 2022
Business Combinations [Abstract]
Summary of Estimated Fair Values Assigned to Net Assets and Final Purchase Price Allocation	The following table summarizes the estimated fair values that were assigned to the net assets of TGE: September 27, 2022 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 5 Property, plant and equipment 3 Long-term investments 8 Intangible assets (a) 117 Long-term assets 3 Current liabilities 61 Long-term debt (Note 18) 18 Long-term liabilities (b) 105 Goodwill (c) 392 Purchase price: Cash 295 Contingent consideration (d) 49 344 a) Intangible assets consist of compensation expected to be earned by TGE on existing development contracts once certain project development milestones are met. Fair value was determined using a discounted cash flow method which is an income-based approach to valuation that estimates the present value of future projected benefits from the contracts. The intangible assets will be amortized on a straight-line basis over an expected useful life of three and a half years. b) Long-term liabilities consist primarily of obligations payable to third parties which are contingent on the timing of milestones being met for certain projects. Fair value represents the present value of the future cash flow payments at the date of the TGE Acquisition. c) Goodwill is primarily attributable to expected future returns from new opportunities to develop wind and solar projects, as well as enhanced scale and operational diversity of our renewable projects portfolio. The goodwill balance recognized has been assigned to our Renewable Power Generation segment and is tax deductible over 15 years. d) We agreed to pay additional contingent consideration of up to US$53 million to TGE's former common unit holders if performance milestones are met on certain projects. The US$36 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition. The fair value was determined using an income-based approach. The following table summarizes the estimated fair values that were assigned to the net assets of Moda: October 12, 2021 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 62 Property, plant and equipment (a) 1,480 Long-term investments (b) 427 Intangible assets (c) 1,781 Current liabilities 59 Long-term liabilities 17 Goodwill (d) 268 Purchase price: Cash 3,755 Contingent consideration (e) 187 3,942 a) Due to the specialized nature of Moda's property, plant and equipment, which includes groups of assets configured for use as storage facilities, pipelines and export terminals, the depreciated replacement cost approach was adopted as the primary valuation methodology. In determining replacement cost, both indirect costing using relevant inflation indices and direct costing using relevant market quotes were utilized. Adjustments were then applied for physical deterioration as well as functional and economic obsolescence. The fair value of land was determined using a market approach, which is based on rents and offerings for comparable properties. b) Long-term investments represent Moda's 20% equity interest in Cactus II Pipeline LLC (Cactus II). The fair value of Cactus II was determined using the discounted cash flow method. The discounted cash flow method is an income-based approach to valuation which estimates the present value of future projected benefits from the investment. c) Intangible assets consist primarily of customer relationships associated with long-term take-or-pay contracts. Fair value was determined using an income-based approach by estimating the present value of the after-tax earnings attributable to the contracts, including earnings associated with expected renewal terms, and will be amortized on a straight-line basis over an expected useful life of 10 years. d) Goodwill is primarily attributable to uncontracted future revenues, existing assembled assets that cannot be duplicated at the same cost by a new entrant, and enhanced scale and geographic diversity which provide greater optionality and platforms for future growth. The goodwill balance recognized has been assigned to our Liquids Pipelines segment and is tax deductible over 15 years. e) We agreed to pay additional contingent co nsideration of up to US$150 million to Moda's former membership interest holders if Moda's monthly volumes of crude oil loaded onto a vessel equal or exceed specified throughput levels. These performance requirements terminate the earlier of December 31, 2023 or the date the final contingent payment is made. The US$150 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition and was fully settled as at December 31, 2022.
Schedule of Supplemental Pro Forma Consolidated Financial Information	Our supplemental pro forma consolidated financial information for the years ended December 31, 2021 and 2020, including the results of operations for Moda as if the Moda Acquisition had been completed on January 1, 2020, are as follows: Year ended December 31, 2021 2020 (unaudited; millions of Canadian dollars) Operating revenues 47,339 39,435 Earnings attributable to common shareholders 1,2 5,771 2,938 1 Acquisition-related expenses of $21 million (after-tax $16 million) were excluded from earnings attributable to common shareholders for the year ended December 31, 2021 and deducted for the year ended December 31, 2020. 2 Includes the amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets of $193 million and $207 million (after-tax of $145 million and $155 million) for the years ended December 31, 2021 and 2020, respectively.

ACCOUNTS RECEIVABLE AND OTHER (

ACCOUNTS RECEIVABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2022
Receivables [Abstract]
Schedule of Accounts Receivable And Other	December 31, 2022 2021 (millions of Canadian dollars) Trade receivables and unbilled revenues 1 5,616 4,957 Short-term portion of derivative assets (Note 24) 1,015 529 Regulatory assets (Note 7) 604 259 Gas imbalance 461 276 Taxes receivable 323 407 Other 852 434 8,871 6,862 1 Net of allowance for expected credit losses of $92 million and $87 million as at December 31, 2022 and 2021, respectively.

INVENTORY (Tables)

INVENTORY (Tables)	12 Months Ended
	Dec. 31, 2022
Inventory Disclosure [Abstract]
Schedule Of Inventory	December 31, 2022 2021 (millions of Canadian dollars) Natural gas 1,491 953 Crude oil 652 624 Other 112 93 2,255 1,670

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant And Equipment	Weighted Average December 31, Depreciation Rate 2022 2021 (millions of Canadian dollars) Pipelines 2.9 % 66,528 62,997 Facilities and equipment 3.5 % 37,028 34,331 Land and right-of-way 1 2.2 % 3,637 3,320 Gas mains, services and other 2.6 % 14,491 13,606 Storage 2.3 % 3,477 3,099 Wind turbines, solar panels and other 4.1 % 4,912 4,912 Other 8.5 % 1,611 1,507 Under construction — % 2,316 2,268 Total property, plant and equipment 134,000 126,040 Total accumulated depreciation (29,540) (25,973) Property, plant and equipment, net 104,460 100,067 1 The measurement of weighted average depreciation rate excludes non-depreciable assets.

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Assets and Liabilities of Consolidated VIEs	The following table includes assets to be used to settle liabilities of our consolidated VIEs. The creditors of the liabilities of our consolidated VIEs do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position. December 31, 2022 1 2021 (millions of Canadian dollars) Assets Cash and cash equivalents 426 247 Restricted cash 12 4 Accounts receivable and other 199 99 Accounts receivable from affiliates 23 — Inventory 12 9 672 359 Property, plant and equipment, net 7,707 3,052 Long-term investments 14 16 Restricted long-term investments 98 101 Deferred amounts and other assets 158 2 Intangible assets, net 102 108 8,751 3,638 Liabilities Accounts payable and other 251 84 Accounts payable to affiliates 21 — 272 84 Other long-term liabilities 859 182 Deferred income taxes 5 5 1,136 271 7,615 3,367 1 Includes assets and liabilities of newly created Enbridge Athabasca Midstream Trunkline LP and Enbridge Athabasca Midstream Investor LP following the sale of a minority interest in certain Athabasca Regional Oil Sands System assets. Refer to Note 8 - Acquisitions and Dispositions .
Schedule of the Carrying Amount of Interest in VIEs	The carrying amount of these VIEs and our estimated maximum exposure to loss as at December 31, 2022 and 2021 are presented below: Carrying Maximum December 31, 2022 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 91 117 EIH S.á r.l. 2 37 637 Rampion Offshore Wind Limited 3 413 468 Vector Pipeline L.P. 4 195 325 Woodfibre LNG Limited Partnership 5,6 635 2,476 Other 7 245 443 1,616 4,466 Carrying Maximum December 31, 2021 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 113 195 EIH S.á r.l. 2 38 664 Enbridge Renewable Infrastructure Investments S.á r.l. 8,9 54 2,121 Rampion Offshore Wind Limited 3 450 508 Vector Pipeline L.P. 4 189 374 Other 7 210 426 1,054 4,288 1 As at December 31, 2022 and 2021, the maximum exposure to loss includes a guarantee by us for our respective share of the VIE’s borrowing on a bank credit facility. 2 As at December 31, 2022 and 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the three French offshore wind projects for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $56 million and $73 million held by us as at December 31, 2022 and 2021, respectively. 3 As at December 31, 2022 and 2021, the maximum exposure to loss includes our parental guarantees that have been committed in project contracts in which we would be liable for in the event of default by the VIE. 4 As at December 31, 2022 and 2021, the maximum exposure to loss includes the carrying value of outstanding affiliate loans receivable for $25 million and $80 million held by us as at December 31, 2022 and 2021, respectively, and an outstanding credit facility for $105 million as at December 31, 2022 and 2021. 5 In November 2022, Enbridge acquired a 30% interest in Woodfibre LNG Limited Partnership (Woodfibre). Refer to Note 13 - Long-Term Investments . Woodfibre is a VIE due to its lack of sufficient equity at risk to finance its activities. Enbridge does not hold decision-making rights to direct Woodfibre's activities that most significantly impact its economic performance. 6 As at December 31, 2022, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE. 7 As at December 31, 2022 and 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the projects for which we would be liable in the event of default by the VIE. 8 As at December 31, 2021, the maximum exposure to loss included our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $807 million held by us as at December 31, 2021. 9 Following a reconsideration event in connection with an additional equity injection to facilitate debt and equity rebalancing of Enbridge Renewable Infrastructure Investments S.á r.l. (ERII) in the third quarter of 2022, ERII's equity is now sufficient for it to finance its activities without additional subordinated financial support. Therefore, it is no longer considered to be a VIE.

LONG-TERM INVESTMENTS (Tables)

LONG-TERM INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Long-Term Investments	Ownership December 31, Interest 2022 2021 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines MarEn Bakken Company LLC 1 75.0 % 1,968 1,752 DCP Midstream, LLC (Class B Units) 2 90.0 % 1,394 469 Seaway Crude Holdings LLC 50.0 % 2,744 2,634 Illinois Extension Pipeline Company, L.L.C. 3 65.0 % 622 593 Cactus II Pipeline LLC 4 30.0 % 658 434 Other 30.0% - 43.8% 76 71 Gas Transmission and Midstream Alliance Pipeline 5 50.0 % 430 504 Aux Sable 6 42.7% - 50.0% 214 238 DCP Midstream, LLC (Class A Units) 7 23.4 % 317 397 Gulfstream Natural Gas System, L.L.C. 50.0 % 1,274 1,180 Nexus Gas Transmission, LLC 50.0 % 1,813 1,724 Sabal Trail Transmission, LLC 50.0 % 1,535 1,464 Southeast Supply Header, LLC 50.0 % 86 82 Steckman Ridge, LP 50.0 % 91 88 Vector Pipeline 8 60.0 % 195 189 Woodfibre LNG Limited Partnership 30.0 % 635 — Offshore - various joint ventures 22.0% - 74.3% 314 309 Other 20.0% - 33.3% — 14 Gas Distribution and Storage Other 47.6% - 50.0% 20 20 Renewable Power Generation EIH S.à.r.l. 9 51.0 % 37 38 Enbridge Renewable Infrastructure Investments S.à.r.l. 51.0 % 163 54 Rampion Offshore Wind Limited 24.9 % 413 450 NextBridge Infrastructure LP 25.0 % 241 186 Other 15.8% - 50.0% 107 92 OTHER LONG-TERM INVESTMENTS Gas Transmission and Midstream Fairwood Peninsula Energy Corporation 22 20 Gas Distribution and Storage Oakville Enterprises Corporation 10 48 — Renewable Power Generation Emerging Technologies and Other 31 32 Eliminations and Other Other 11 488 290 15,936 13,324 1 Owns a 49.0% interest in Bakken Pipeline Investments L.L.C. Bakken Pipeline Investments L.L.C. owns 75.0% of the Bakken Pipeline System, resulting in a 27.6% effective interest in the Bakken Pipeline System by us. 2 We own 90.0% of the Class B units of DCP Midstream, LLC. These units track to a 65.0% ownership in Gray Oak Pipeline, LLC (Gray Oak), resulting in a 58.5% effective interest in Gray Oak by us. In 2021, we owned a 35.0% interest in Gray Oak Holdings LLC, which owned a 65.0% interest in Gray Oak, resulting in a 22.8% effective interest in Gray Oak by us. 3 Owns the Southern Access Extension Project. 4 On October 12, 2021, we acquired an effective 20.0% interest in Cactus II through the acquisition of Moda. Refer to Note 8 - Acquisitions and Dispositions for further discussion. On November 2, 2022, we acquired an additional 10.0% ownership in Cactus II for cash payment of $241 million (US$177 million), bringing our total non-operating ownership to 30.0%. 5 Includes Alliance Pipeline Limited Partnership in Canada and Alliance Pipeline L.P. in the US. 6 Includes Aux Sable Canada LP in Canada and Aux Sable Liquid Products LP and Aux Sable Midstream LLC in the US. 7 We own 23.4% of the Class A units of DCP Midstream, LLC. These units track to a 56.5% ownership in DCP Midstream, LP (DCP), resulting in a 13.2% effective interest in DCP by us. In 2021, we owned an effective 28.3% interest in DCP. 8 Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US. 9 On March 18, 2021, we sold 49.0% of EIH S.à.r.l., an entity that holds our 50.0% interest in Éolien Maritime France SAS (EMF), to the Canada Pension Plan Investment Board. This resulted in a 25.5% effective interest in EMF. Through our investment in EMF, we own equity interests in three French offshore wind projects, including effective interests in Saint-Nazaire (25.5%), Fécamp (17.9%) and Calvados (21.7%). 10 On August 2, 2022, we acquired a 10.0% interest in Oakville Enterprises Corporation. 11 Consists of investments in debt and equity securities held by our wholly-owned captive insurance subsidiaries. Refer to Note 24 -Risk Management and Financial Instruments.
Schedule of Combined Financial Information	Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows: Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Operating revenues 27,043 20,021 14,096 Operating expenses 23,043 16,706 12,411 Earnings 4,334 3,022 2,324 Earnings attributable to Enbridge 2,056 1,711 1,136 December 31, 2022 2021 (millions of Canadian dollars) Current assets 4,196 3,639 Non-current assets 53,405 44,863 Current liabilities 4,843 3,741 Non-current liabilities 18,595 16,979 Noncontrolling interests 3,785 3,786

INTANGIBLE ASSETS (Tables)

INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Intangible Assets	December 31, 2022 Weighted Average Amortization Rate Cost Accumulated Amortization Net (millions of Canadian dollars) Software 10.9 % 2,019 (1,042) 977 Power purchase agreements 4.2 % 64 (23) 41 Project agreement 1 4.0 % 163 (36) 127 Customer relationships 8.6 % 2,701 (459) 2,242 Other intangible assets 5.9 % 621 (148) 473 Under development — % 158 — 158 5,726 (1,708) 4,018 December 31, 2021 Weighted Average Amortization Rate Cost Accumulated Amortization Net (millions of Canadian dollars) Software 12.0 % 2,067 (1,148) 919 Power purchase agreements 4.5 % 63 (21) 42 Project agreement 1 4.0 % 152 (27) 125 Customer relationships 8.5 % 2,532 (215) 2,317 Other intangible assets 3.9 % 475 (116) 359 Under development — % 246 — 246 5,535 (1,527) 4,008 1 Represents a project agreement acquired from the merger of Enbridge and Spectra Energy.

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Liquids Gas Gas Renewable Power Generation Energy Consolidated (millions of Canadian dollars) Balance at January 1, 2021 7,828 19,480 5,378 — 2 32,688 Foreign exchange and other (55) (145) — — — (200) Acquisition 3 268 — 19 — — 287 Balance at December 31, 2021 1,2 8,041 19,335 5,397 — 2 32,775 Impairment — (2,465) — — — (2,465) Foreign exchange and other 506 1,236 — (4) — 1,738 Acquisition 4 — — — 392 — 392 Balance at December 31, 2022 1,2 8,547 18,106 5,397 388 2 32,440 1 Gross goodwill as at December 31, 2022 and 2021 was $36.5 billion and $34.4 billion, respectively. 2 Accumulated impairment as at December 31, 2022 and 2021 was $4.1 billion and $1.6 billion, respectively. 3 In 2021 we recorded $268 million of goodwill related to the acquisition of Moda. Refer to Note 8 - Acquisitions and Dispositions . 4 In 2022, we recorded $392 million of goodwill related to the acquisition of TGE. Refer to Note 8 - Acquisitions and Dispositions . IMPAIRMENT Gas Transmission During the year ended December 31, 2022, we recorded goodwill impairment of $2.5 billion related to our Gas Transmission reporting unit. The fair value of the reporting unit, determined using a combination of discounted cash flow and earnings multiples techniques, was impacted by a rise in cost of capital and lower projected long term growth rates for our existing assets.

ACCOUNTS PAYABLE AND OTHER (Tab

ACCOUNTS PAYABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2022
Payables and Accruals [Abstract]
Schedule of Accounts Payable And Other	December 31, 2022 2021 (millions of Canadian dollars) Trade payables and operating accrued liabilities 5,235 4,470 Dividends payable 1,825 1,773 Current deferred credits 1,056 853 Construction payables and contractor holdbacks 937 844 Current derivative liabilities (Note 24) 898 717 Taxes payable 683 478 Other 758 632 11,392 9,767

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Debt	December 31, Weighted Average Interest Rate 9 Maturity 2022 2021 (millions of Canadian dollars) Enbridge Inc. US dollar senior notes 3.5 % 2023 - 2051 12,060 10,992 Medium-term notes 3.8 % 2023 - 2064 8,223 8,123 Sustainability-linked bonds 2.0 % 2032 - 2033 3,355 2,363 Fixed-to-fixed subordinated term notes 1 4.1 % 2080 - 2083 3,596 1,263 Fixed-to-floating rate subordinated term notes 2 5.9 % 2077 - 2078 6,736 6,442 Floating rate notes 3 2023 - 2024 1,491 1,579 Commercial paper and credit facility draws 4.8 % 2023 - 2027 7,984 7,837 Other 4 15 5 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 4.5 % 2024 - 2027 4,199 4,845 Other 4 7 7 Enbridge Energy Partners, L.P. Senior notes 6.5 % 2025 - 2045 3,320 3,095 Enbridge Gas Inc. Medium-term notes 4.1 % 2023 - 2052 9,535 9,010 Debentures 9.1 % 2024 - 2025 210 210 Commercial paper and credit facility draws 4.5 % 2024 2,000 1,515 Other 4 1 — Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 4.0 % 2040 921 949 Enbridge Pipelines Inc. Medium-term notes 5 4.2 % 2023 - 2051 5,425 5,575 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 4.6 % 2024 312 667 Enbridge Southern Lights LP Senior notes 4.0 % 2040 222 240 Spectra Energy Capital, LLC Senior notes 7.0 % 2032 - 2038 234 218 Algonquin Gas Transmission, LLC Senior notes 3.3 % 2024 - 2029 1,152 1,074 East Tennessee Natural Gas, LLC Senior notes 3.1 % 2024 258 240 Texas Eastern Transmission, LP Senior notes 3.3 % 2028 - 2048 3,455 3,095 Spectra Energy Partners, LP Senior notes 4.3 % 2024 - 2045 4,336 4,042 Tri Global Energy, LLC Senior notes 12.7 % 2024 18 — Westcoast Energy Inc. Medium-term notes 4.9 % 2024 - 2041 1,225 1,475 Debentures 8.1 % 2025 - 2026 275 275 Fair value adjustment 608 667 Other 6 (393) (363) Total debt 7 80,980 75,640 Current maturities (6,045) (6,164) Short-term borrowings 8 (1,996) (1,515) Long-term debt 72,939 67,961 1 For an initial five or 10 years, the notes carry a fixed interest rate. Subsequently, during each reset period the interest rate will be reset to equal to the Five-Year US Treasury rate or Five-Year Government of Canada bond yield plus a margin. The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 2 For an initial five or 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal to the Canadian Dollar Offered Rate or the London Interbank Offered Rate (LIBOR) plus a margin. The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 3 The notes carry an interest rate equal to Secured Overnight Financing Rate (SOFR) plus a margin of 40 basis points and SOFR plus a margin of 63 basis points. 4 Primarily finance lease obligations. 5 Included in medium-term notes is $100 million with a maturity date of 2112. 6 Primarily unamortized discounts, premiums and debt issuance costs. 7 2022 - $38 billion and US$31 billion; 2021 - $36 billion and US$31 billion. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment. 8 Weighted average interest rates on outstanding commercial paper were 4.5% as at December 31, 2022 (2021 - 0.5%). 9 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2022.
Schedule of Committed Credit Facilities	The following table provides details of our committed credit facilities as at December 31, 2022: Maturity 1 Total Facilities Draws 2 Available (millions of Canadian dollars) Enbridge Inc. 2023-2027 10,987 7,984 3,003 Enbridge (U.S.) Inc. 2024-2027 8,604 4,199 4,405 Enbridge Pipelines Inc. 2024 2,000 312 1,688 Enbridge Gas Inc. 2024 2,000 2,000 — Total committed credit facilities 23,591 14,495 9,096 1 Maturity date is inclusive of the one-year term out option for certain credit facilities. 2 Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
Schedule of Long-term Debt Issuances	LONG-TERM DEBT ISSUANCES During the year ended December 31, 2022, we completed the following long-term debt issuances totaling US$3.2 billion and $3.4 billion: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. January 2022 5.00% fixed-to-fixed subordinated notes due January 2082 1 $750 February 2022 Floating rate senior notes due February 2024 2 US$600 February 2022 2.15% senior notes due February 2024 US$400 February 2022 2.50% senior notes due February 2025 US$500 September 2022 7.38% fixed-to-fixed subordinated notes due January 2083 3 US$500 September 2022 7.63% fixed-to-fixed subordinated notes due January 2083 4 US$600 November 2022 5.70% medium-term notes due November 2027 $600 November 2022 6.10% sustainability-linked medium-term notes due November 2032 5 $900 November 2022 6.51% medium-term notes due November 2052 $500 Enbridge Gas Inc. August 2022 4.15% medium-term notes due August 2032 $325 August 2022 4.55% medium-term notes due August 2052 $325 Texas Eastern Transmission LP December 2022 6.20% senior notes due December 2032 US$600 1 For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 3.54%. Subsequent to year 10, every five years, the Five-Year Government of Canada bond yield is reset. At year 30, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.29%. 2 Notes carry an interest rate set to equal the SOFR plus a margin of 63 basis points. 3 For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be set to equal to the Five-Year US Treasury rate plus a margin of 3.71%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.96%. Subsequent to year 10, every five years, the Five-Year US Treasury rate is reset. At year 25, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.71%. 4 For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.42%. Subsequent to year 10, every five years, the Five-Year US Treasury rate will be reset. At year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.17%. 5 The sustainability-linked medium-term notes are subject to a sustainability performance target of 35% reduction in emissions intensity at an observation date of December 31, 2030. If the target is not met, on November 9, 2031, the interest rate will be set to equal 6.10% plus a margin of 70 basis points.
Schedule of Long-Term Debt Repayments	During the year ended December 31, 2022, we completed the following long-term debt repayments totaling $1.5 billion and US$2.0 billion, respectively: Company Repayment Date Principal Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. February 2022 Floating rate notes 1 US$750 February 2022 4.85% medium-term notes $200 July 2022 2.90% senior notes US$700 December 2022 3.19% medium-term notes $350 December 2022 3.19% medium-term notes $450 Enbridge Gas Inc. April 2022 4.85% medium-term notes $125 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2022 3.98% senior notes US$72 Enbridge Pipelines Inc. November 2022 2.93% medium-term notes $150 Enbridge Southern Lights LP June and December 2022 4.01% senior notes $18 Texas Eastern Transmission, LP October 2022 2.80% senior notes US$500 Westcoast Energy Inc. December 2022 3.12% medium-term notes $250 1 Notes carried an interest rate set to equal the Three-Month LIBOR plus a margin of 50 basis points.
Schedule of Interest Expense	INTEREST EXPENSE Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Debentures and term notes 2,910 2,806 2,873 Commercial paper and credit facility draws 388 114 163 Amortization of fair value adjustment (45) (50) (54) Capitalized interest (74) (215) (192) 3,179 2,655 2,790

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Reconciliation of Movements in The Company's ARO	A reconciliation of movements in our ARO liabilities is as follows: December 31, 2022 2021 (millions of Canadian dollars) Obligations at beginning of year 502 496 Liabilities incurred 30 — Liabilities settled (126) (67) Change in estimate and other 51 70 Foreign currency translation adjustment 24 (3) Accretion expense 7 6 Obligations at end of year 488 502 Presented as follows: Accounts payable and other 83 160 Other long-term liabilities 405 342 488 502

NONCONTROLLING INTERESTS (Table

NONCONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2022
Noncontrolling Interest [Abstract]
Schedule of Noncontrolling Interests	The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position: December 31, 2022 2021 (millions of Canadian dollars) Algonquin Gas Transmission, LLC 400 377 Enbridge Athabasca Midstream Investor Limited Partnership 1 1,106 — Maritimes & Northeast Pipeline, L.L.C. 582 546 Renewable energy assets 1,302 1,503 Westcoast Energy Inc. 2 117 116 Other 4 — 3,511 2,542 1 On October 5, 2022, we closed the sale of an 11.6% non-operating interest in certain assets from our Regional Oil Sands System to Aii. Refer to Note 8 - Acquisitions and Dispositions . 2 During 2021, Westcoast Energy Inc. redeemed all of its remaining Cumulative Five-Year Minimum Rate Reset Redeemable First Preferred Shares.

SHARE CAPITAL (Tables)

SHARE CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
Schedule of Common Shares	COMMON SHARES 2022 2021 2020 December 31, Number of Shares Amount Number of Shares Amount Number of Shares Amount (millions of Canadian dollars; number of shares in millions) Balance at beginning of year 2,026 64,799 2,026 64,768 2,025 64,746 Shares issued on exercise of stock options 2 53 — 31 1 22 Share purchases at stated value 1 (3) (88) — — — — Other — (4) — — — — Balance at end of year 2,025 64,760 2,026 64,799 2,026 64,768 1 Reflects the repurchase and cancellation of common shares under our normal course issuer bid.
Schedule of Preference Shares and Characteristics of Preference Shares	PREFERENCE SHARES 2022 2021 2020 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Preference Shares, Series A 5 125 5 125 5 125 Preference Shares, Series B 20 500 18 457 18 457 Preference Shares, Series C 1 — — 2 43 2 43 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 20 500 20 500 20 500 Preference Shares, Series H 14 350 14 350 14 350 Preference Shares, Series J 2 — — 8 199 8 199 Preference Shares, Series L 16 411 16 411 16 411 Preference Shares, Series N 18 450 18 450 18 450 Preference Shares, Series P 16 400 16 400 16 400 Preference Shares, Series R 16 400 16 400 16 400 Preference Shares, Series 1 16 411 16 411 16 411 Preference Shares, Series 3 24 600 24 600 24 600 Preference Shares, Series 5 8 206 8 206 8 206 Preference Shares, Series 7 10 250 10 250 10 250 Preference Shares, Series 9 11 275 11 275 11 275 Preference Shares, Series 11 20 500 20 500 20 500 Preference Shares, Series 13 14 350 14 350 14 350 Preference Shares, Series 15 11 275 11 275 11 275 Preference Shares, Series 17 3 — — 30 750 30 750 Preference Shares, Series 19 20 500 20 500 20 500 Issuance costs (135) (155) (155) Balance at end of year 6,818 7,747 7,747 1 On June 1, 2022, all outstanding Preference Shares, Series C were converted to Preference Shares, Series B. 2 On June 1, 2022, we redeemed our US$200 million outstanding Cumulative Redeemable Preference Shares, Series J. 3 On March 1, 2022, we redeemed our $750 million outstanding Cumulative Redeemable Minimum Rate Reset Preference Shares, Series 17. Characteristics of our outstanding preference shares are as follows: Dividend Rate Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4 (Canadian dollars unless otherwise stated) Preference Shares, Series A 5.50 % $1.37500 $25 — — Preference Shares, Series B 5 5.20 % $1.30052 $25 June 1, 2027 Series C Preference Shares, Series D 4.46 % $1.11500 $25 March 1, 2023 Series E Preference Shares, Series F 4.69 % $1.17224 $25 June 1, 2023 Series G Preference Shares, Series H 4.38 % $1.09400 $25 September 1, 2023 Series I Preference Shares, Series L 6 5.86 % US$1.46448 US$25 September 1, 2027 Series M Preference Shares, Series N 5.09 % $1.27152 $25 December 1, 2023 Series O Preference Shares, Series P 4.38 % $1.09476 $25 March 1, 2024 Series Q Preference Shares, Series R 4.07 % $1.01825 $25 June 1, 2024 Series S Preference Shares, Series 1 5.95 % US$1.48728 US$25 June 1, 2023 Series 2 Preference Shares, Series 3 3.74 % $0.93425 $25 September 1, 2024 Series 4 Preference Shares, Series 5 5.38 % US$1.34383 US$25 March 1, 2024 Series 6 Preference Shares, Series 7 4.45 % $1.11224 $25 March 1, 2024 Series 8 Preference Shares, Series 9 4.10 % $1.02424 $25 December 1, 2024 Series 10 Preference Shares, Series 11 3.94 % $0.98452 $25 March 1, 2025 Series 12 Preference Shares, Series 13 3.04 % $0.76076 $25 June 1, 2025 Series 14 Preference Shares, Series 15 2.98 % $0.74576 $25 September 1, 2025 Series 16 Preference Shares, Series 19 4.90 % $1.22500 $25 March 1, 2023 Series 20 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Preference Shares, Series A, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Preference Shares, Series 19 contain a feature where the fixed dividend rate, when reset every five years, will not be less than 4.90%. No other series of Preference Shares has this feature. 2 Preference Shares, Series A may be redeemed any time at our option. For all other series of preference shares, we may at our option, redeem all or a portion of the outstanding preference shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value. 4 With the exception of Preference Shares, Series A, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in year) x Three-Month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in year) x Three-Month US Government treasury bill rate + 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6). 5 The quarterly dividend per share paid on Preference Shares, Series B was increased to $0.32513 from $0.21340 on June 1, 2022 due to reset of the annual dividend on June 1, 2022. On June 1, 2022, all outstanding Preference Shares, Series C were converted to Preference Shares, Series B. 6 The quarterly dividend per share paid on Preference Shares, Series L was increased to US$0.36612 from US$0.30993 on September 1, 2022, due to reset of the annual dividend on September 1, 2022.

STOCK OPTION AND STOCK UNIT P_2

STOCK OPTION AND STOCK UNIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Schedule of Outstanding Stock Options	December 31, 2022 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (options in thousands; weighted average exercise price in Canadian dollars; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 34,017 49.28 Options granted 3,430 49.58 Options exercised 1 (8,684) 44.55 Options cancelled or expired (1,139) 51.32 Options outstanding at end of year 27,624 48.46 5.7 133 Options vested at end of year 2 17,631 49.20 4.4 84 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2022, 2021 and 2020 was $66 million, $24 million and $13 million, respectively, and cash received on exercise was $3 million, $2 million and $4 million, respectively. 2 The total fair value of ISOs exercised during the years ended December 31, 2022, 2021 and 2020 was $21 million, $25 million and $30 million, respectively.
Schedule of Weighted Average Assumptions Used to Determine the Fair Value of Stock Options Granted	Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton option pricing model are as follows: Year ended December 31, 2022 2021 2020 Fair value per option (Canadian dollars) 1 5.07 4.10 4.01 Valuation assumptions Expected option term (years) 2 6 6 6 Expected volatility 3 21.9 % 25.5 % 18.3 % Expected dividend yield 4 6.5 % 7.6 % 5.9 % Risk-free interest rate 5 1.8 % 0.7 % 1.3 % 1 Options granted to US employees are based on the New York Stock Exchange prices. The option value and assumptions shown are based on a weighted average of the US and the Canadian options. The fair values per option for the years ended December 31, 2022, 2021 and 2020 were $4.78, $3.91 and $3.75, respectively, for Canadian employees and US$4.62, US$3.65 and US$3.62, respectively, for US employees. 2 The expected option term is six years based on historical exercise practice and five years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada’s Canadian bond yields and the US Treasury bond yields.
Share-Based Payment Arrangement, Performance Shares, Activity	December 31, 2022 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 3,429 Units granted 1,467 Units cancelled (131) Units matured 1 (1,700) Dividend reinvestment 184 Units outstanding at end of year 3,249 1.1 261 1 The total amount paid during the years ended December 31, 2022, 2021 and 2020 for PSUs was $90 million, $70 million and $14 million, respectively.
Schedule of Outstanding Stock Units	December 31, 2022 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 2,705 Units granted 1,400 Units cancelled (134) Units matured 1 (602) Dividend reinvestment 196 Units outstanding at end of year 3,565 1.0 185 1 The total amount paid during the years ended December 31, 2022, 2021 and 2020 for RSUs was $32 million, $72 million and $27 million, respectively.

COMPONENTS OF ACCUMULATED OTH_2

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Tables)	12 Months Ended
	Dec. 31, 2022
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Schedule of Changes in AOCI Attributable to Enbridge Common Shareholders	Changes in AOCI attributable to our common shareholders for the years ended December 31, 2022, 2021 and 2020 are as follows: Cash Flow Hedges Excluded Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2022 (897) — (166) 56 (5) (84) (1,096) Other comprehensive income/(loss) retained in AOCI 1,125 (35) (971) 4,292 (6) 411 4,816 Other comprehensive loss/(income) reclassified to earnings Interest rate contracts 1 186 — — — — — 186 Foreign exchange contracts 2 (4) — — — — — (4) Other contracts 3 4 — — — — — 4 Amortization of pension and OPEB actuarial gain 4 — — — — — (14) (14) Other — — — — 16 — 16 1,311 (35) (971) 4,292 10 397 5,004 Tax impact Income tax on amounts retained in AOCI (250) — — — — (99) (349) Income tax on amounts reclassified to earnings (43) — — — — 4 (39) (293) — — — — (95) (388) Balance as at December 31, 2022 121 (35) (1,137) 4,348 5 218 3,520 Cash Flow Hedges Excluded Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2021 (1,326) 5 (215) 568 66 (499) (1,401) Other comprehensive income/(loss) retained in AOCI 238 (5) 49 (492) (12) 520 298 Other comprehensive loss/(income) reclassified to earnings Interest rate contracts 1 296 — — — — — 296 Commodity contracts 5 1 — — — — — 1 Foreign exchange contracts 2 5 — — — — — 5 Other contracts 3 2 — — — — — 2 Equity investment disposal — — — — (66) — (66) Amortization of pension and OPEB actuarial loss and prior service costs 4 — — — — — 28 28 Other 17 — — (20) 3 — — 559 (5) 49 (512) (75) 548 564 Tax impact Income tax on amounts retained in AOCI (61) — — — — (126) (187) Income tax on amounts reclassified to earnings (69) — — — 4 (7) (72) (130) — — — 4 (133) (259) Balance as at December 31, 2021 (897) — (166) 56 (5) (84) (1,096) Cash Flow Hedges Excluded Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2020 (1,073) — (317) 1,396 67 (345) (272) Other comprehensive income/(loss) retained in AOCI (591) 5 115 (828) (2) (221) (1,522) Other comprehensive loss/(income) reclassified to earnings Interest rate contracts 1 253 — — — — — 253 Foreign exchange contracts 2 5 — — — — — 5 Other contracts 3 (2) — — — — — (2) Amortization of pension and OPEB actuarial loss and prior service costs 4 — — — — — 17 17 (335) 5 115 (828) (2) (204) (1,249) Tax impact Income tax on amounts retained in AOCI 140 — (13) — 1 54 182 Income tax on amounts reclassified to earnings (58) — — — — (4) (62) 82 — (13) — 1 50 120 Balance as at December 31, 2020 (1,326) 5 (215) 568 66 (499) (1,401) 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings. 3 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 4 These components are included in the computation of net periodic benefit (credit)/cost and are reported within Other income/(expense) in the Consolidated Statements of Earnings. 5 Reported within Transportation and other services revenues, Commodity sales, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

RISK MANAGEMENT AND FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2022
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. December 31, 2022 Derivative Instruments Used as Cash Flow Hedges Derivative Non- Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — 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 Accounts payable and other 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) December 31, 2021 Derivative Derivative Instruments Used as Fair Value Hedges Non- Total Gross Amounts Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — 259 259 (41) 218 Interest rate contracts 64 — — 64 — 64 Commodity contracts — — 204 204 (129) 75 Other contracts — — 2 2 — 2 64 — 465 529 (170) 359 Deferred amounts and other assets Foreign exchange contracts — — 240 240 (61) 179 Interest rate contracts 88 — — 88 (1) 87 Commodity contracts — — 29 29 (13) 16 Other contracts — — 3 3 — 3 88 — 272 360 (75) 285 Accounts payable and other Foreign exchange contracts (15) (112) (176) (303) 41 (262) Interest rate contracts (150) — — (150) — (150) Commodity contracts (14) — (250) (264) 129 (135) (179) (112) (426) (717) 170 (547) Other long-term liabilities Foreign exchange contracts — — (423) (423) 61 (362) Interest rate contracts (1) — (23) (24) 1 (23) Commodity contracts (17) — (67) (84) 13 (71) (18) — (513) (531) 75 (456) Total net derivative asset/(liability) Foreign exchange contracts (15) (112) (100) (227) — (227) Interest rate contracts 1 — (23) (22) — (22) Commodity contracts (31) — (84) (115) — (115) Other contracts — — 5 5 — 5 (45) (112) (202) (359) — (359)
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. 2022 2021 As at December 31, 2023 2024 2025 2026 2027 Thereafter Total Total Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) 655 1,000 500 — — — 2,155 2,508 Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) 8,297 6,386 4,613 4,121 2,837 1,356 27,610 25,427 Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) 29 30 30 28 32 — 149 177 Foreign exchange contracts - Euro forwards - sell (millions of Euro) 92 91 86 85 81 262 697 801 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) — — 84,800 — — — 84,800 72,500 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 8,698 538 30 26 25 39 9,356 597 Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 5,496 1,766 589 — — — 7,851 5,279 Equity contracts (millions of Canadian dollars) 37 31 12 — — — 80 67 Commodity contracts - natural gas (billions of cubic feet) 52 25 15 1 — — 93 199 Commodity contracts - crude oil (millions of barrels) 16 — — — — — 16 12 Commodity contracts - power (megawatt per hour (MW/H)) 26 (25) (44) — — — (14) 1 (43) 1 1 Total is an average net purchase/(sell) of power.
Schedule of Effect of Cash Flow Hedges and Net Investment Hedges on Consolidated Earnings and Consolidated Comprehensive Income, Before Income Taxes	The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes: 2022 2021 2020 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts 3 (29) (1) Interest rate contracts 1,151 252 (595) Commodity contracts (53) (28) 2 Other contracts (4) 1 (3) Fair value hedges Foreign exchange contracts (35) (5) 5 Net investment hedges Foreign exchange contracts — — 13 1,062 191 (579) Amount of (gain)/loss reclassified from AOCI to earnings Foreign exchange contracts 1 13 5 5 Interest rate contracts 2 186 296 253 Commodity contracts 3 — 1 — Other contracts 3 4 2 (2) 203 304 256 1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
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: Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Foreign exchange contracts 1 (1,344) 92 902 Interest rate contracts 2 10 2 (25) Commodity contracts 3 50 71 (114) Other contracts 4 4 8 (7) Total unrealized derivative fair value gain/(loss), net (1,280) 173 756 1 For the respective annual periods, reported within Transportation and other services revenue (2022 - $238 million loss; 2021 - $98 million gain; 2020 - $533 million gain) and Other income/(expense) (2022 - $1,106 million loss; 2021 - $6 million loss; 2020 - $369 million gain) in the Consolidated Statements of Earnings. 2 Reported as an increase within Interest expense in the Consolidated Statements of Earnings. 3 For the respective annual periods, reported within Transportation and other services revenue (2022 - $13 million gain; 2021 - $9 million gain; 2020 - $2 million loss), Commodity sales (2022 - $89 million gain; 2021 - $160 million gain; 2020 - $321 million loss), Commodity costs (2022 - $102 million loss; 2021 - $105 million loss; 2020 - $207 million gain) and Operating and administrative expense (2022 - $50 million gain; 2021 - $7 million gain; 2020 - $2 million gain) 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: December 31, 2022 2021 (millions of Canadian dollars) Canadian financial institutions 644 424 US financial institutions 277 130 European financial institutions 334 181 Asian financial institutions 224 30 Other 1 105 122 1,584 887 1 Other 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: 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) December 31, 2021 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 259 — 259 Interest rate contracts — 64 — 64 Commodity contracts 38 71 95 204 Other contracts — 2 — 2 38 396 95 529 Long-term derivative assets Foreign exchange contracts — 240 — 240 Interest rate contracts — 88 — 88 Commodity contracts — 21 8 29 Other contracts — 3 — 3 — 352 8 360 Financial liabilities Current derivative liabilities Foreign exchange contracts — (303) — (303) Interest rate contracts — (150) — (150) Commodity contracts (52) (66) (146) (264) (52) (519) (146) (717) Long-term derivative liabilities Foreign exchange contracts — (423) — (423) Interest rate contracts — (24) — (24) Commodity contracts — (19) (65) (84) — (466) (65) (531) Total net financial asset/(liability) Foreign exchange contracts — (227) — (227) Interest rate contracts — (22) — (22) Commodity contracts (14) 7 (108) (115) Other contracts — 5 — 5 (14) (237) (108) (359)
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: December 31, 2022 Fair Value Unobservable Input Minimum Price Maximum Price Weighted Average Price Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas (35) Forward gas price 4.57 34.56 6.25 $/mmbtu 2 Crude (4) Forward crude price 71.10 105.22 83.26 $/barrel Power (71) Forward power price 36.63 364.00 103.30 $/MW/H Commodity contracts - physical 1 Natural gas (41) Forward gas price 1.67 33.89 6.00 $/mmbtu 2 Crude (2) Forward crude price 64.43 116.60 86.25 $/barrel Power 17 Forward power price 30.49 183.88 72.48 $/MW/H (136) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 One 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: Year ended December 31, 2022 2021 (millions of Canadian dollars) Level 3 net derivative liability at beginning of period (108) (191) Total gain/(loss) Included in earnings 1 6 (39) Included in OCI (54) (29) Settlements 20 151 Level 3 net derivative liability at end of period (136) (108) 1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Schedule of Income Tax Rate Reconciliation	INCOME TAX RATE RECONCILIATION Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Earnings before income taxes 4,542 7,729 4,190 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 681 1,159 629 Increase/(decrease) resulting from: Provincial and state income taxes 1 108 228 288 Foreign and other statutory rate differentials 2 295 134 (53) Effects of rate-regulated accounting 3 (122) (139) (145) Foreign allowable interest deductions — — (4) Part VI.1 tax, net of federal Part I deduction 4 76 73 76 US Minimum Tax 5 107 — 44 Non-taxable portion of gain on sale of investment 6 — (23) — Valuation allowance 6 5 (6) Accounting impairment of non-deductible goodwill 7 370 — — Noncontrolling interests 8 9 (17) (8) Other 9 74 (5) (47) Income tax expense 1,604 1,415 774 Effective income tax rate 35.3 % 18.3 % 18.5 % 1 The change in provincial and state income taxes from 2021 to 2022 reflects the decrease in earnings from Canadian operations and the effect of the reduction in the Pennsylvania corporate income tax rate in the US, partially offset by the increase in earnings from US operations before the non-deductible goodwill impairment relating to the Gas Transmission reporting unit in combination with state tax apportionment changes. Refer to Note 16 - Goodwill. 2 The change in foreign and other statutory rate differentials from 2021 to 2022 reflects the increase in earnings from US operations, before the goodwill impairment relating to the Gas Transmission reporting unit. Refer to Note 16 - Goodwill. 3 The amount in 2022 relates to the federal component of the tax impact relating to the 2022 variable consideration attributable to the Canadian Mainline. Refer to Note 4 - Revenue. 4 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada. 5 There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation. 6 The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco. 7 The amount in 2022 relates to the federal impact of the non-deductible goodwill impairment relating to the Gas Transmission reporting unit. Refer to Note 16 - Goodwill. 8 The amount in 2022 includes the federal tax impact of an impairment to Magic Valley attributable to noncontrolling interests. Refer to Note 11 - Property, Plant and Equipment. 9 The amount in 2022 includes the federal component of the tax impact relating to the 2021 variable consideration attributable to the Canadian Mainline. Refer to
Schedule of Components of Pretax Earnings and Income Taxes	COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Earnings before income taxes Canada 583 3,399 2,789 US 2,865 3,336 407 Other 1,094 994 994 4,542 7,729 4,190 Current income taxes Canada 360 162 165 US 201 80 64 Other 86 82 98 647 324 327 Deferred income taxes Canada (358) 344 378 US 1,309 741 66 Other 6 6 3 957 1,091 447 Income tax expense 1,604 1,415 774
Schedule of Major Components of Deferred Income Tax Assets and Liabilities	Major components of deferred income tax assets and liabilities are as follows: December 31, 2022 2021 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (9,096) (8,721) Investments (7,099) (6,097) Regulatory assets (1,291) (1,245) Pension and OPEB plans (30) — Other (46) (208) Total deferred income tax liabilities (17,562) (16,271) Deferred income tax assets Financial instruments 456 315 Pension and OPEB plans — 110 Loss carryforwards 2,259 3,081 Other 1,753 1,648 Total deferred income tax assets 4,468 5,154 Less valuation allowance (215) (84) Total deferred income tax assets, net 4,253 5,070 Net deferred income tax liabilities (13,309) (11,201) Presented as follows: Total deferred income tax assets 472 488 Total deferred income tax liabilities (13,781) (11,689) Net deferred income tax liabilities (13,309) (11,201)
Schedule of Unrecognized Tax Benefits	UNRECOGNIZED TAX BENEFITS Year ended December 31, 2022 2021 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 76 121 Gross increases for tax positions of current year — 1 Gross decreases for tax positions of prior year (17) (26) Change in translation of foreign currency 1 (1) Lapses of statute of limitations (5) (19) Unrecognized tax benefits at end of year 55 76

PENSION AND OTHER POSTRETIREM_2

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2022
Retirement Benefits [Abstract]
Schedule of Changes in Projected Benefit Obligation, Plan Assets and Funded Status	The following table details the changes in the projected benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit pension plans: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 4,600 4,855 1,184 1,243 Service cost 131 139 43 44 Interest cost 127 101 24 17 Participant contributions 29 28 — — Actuarial gain 1 (1,069) (329) (201) (21) Benefits paid (187) (194) (94) (84) Foreign currency exchange rate changes — — 77 (11) Other (1) — (4) (4) Projected benefit obligation at end of year 2 3,630 4,600 1,029 1,184 Change in plan assets Fair value of plan assets at beginning of year 4,536 4,077 1,160 1,062 Actual return/(loss) on plan assets (235) 505 (64) 151 Employer contributions 3 91 120 4 43 Participant contributions 29 28 — — Benefits paid (187) (194) (94) (84) Foreign currency exchange rate changes — — 78 (8) Other — — (4) (4) Fair value of plan assets at end of year 4 4,234 4,536 1,080 1,160 Overfunded/(underfunded) status at end of year 604 (64) 51 (24) Presented as follows: Deferred amounts and other assets 764 250 141 98 Accounts payable and other (9) (9) (5) (4) Other long-term liabilities (151) (305) (85) (118) 604 (64) 51 (24) 1 Actuarial gains in 2022 and 2021 primarily due to increase in the discount rates used to measure the benefit obligations. 2 The accumulated benefit obligation for our Canadian pension plans was $3.4 billion and $4.3 billion as at December 31, 2022 and 2021, respectively. The accumulated benefit obligation for our US pension plans was $1.0 billion and $1.1 billion as at December 31, 2022 and 2021, respectively. 3 Lower employer contributions in 2022 compared to 2021 primarily due to more plans in an overfunded status. 4 Assets in the amount of $10 million (2021 - $13 million) and $58 million (2021 - $84 million), related to our Canadian and US non-registered supplemental pension plan obligations, are held in grantor trusts and rabbi trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes. Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Accumulated benefit obligation 360 440 89 115 Fair value of plan assets 218 247 — — Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Projected benefit obligation 377 1,272 90 121 Fair value of plan assets 218 1,020 — —
Schedule of Accumulated Benefit Obligation and Fair Value of Plan Assets	Certain of our OPEB plans have accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the accumulated benefit obligation and fair value of plan assets were as follows: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Accumulated benefit obligation 211 274 76 94 Fair value of plan assets — — 50 51
Schedule of Amounts Recognized in AOCI	The amount of pre-tax AOCI relating to our pension plans are as follows: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Net actuarial (gain)/loss (64) 226 40 92 Prior service (credit)/cost — — 1 (1) Total amount recognized in AOCI 1 (64) 226 41 91 1 Excludes amounts related to CTA. The amount of pre-tax AOCI relating to our OPEB plans are as follows: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Net actuarial gain (101) (35) (102) (104) Prior service credit (1) (1) (30) (37) Total amount recognized in AOCI 1 (102) (36) (132) (141) 1 Excludes amounts related to CTA.
Schedule of Net Benefit Costs Recognized	The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our pension plans are as follows: Canada US Year ended December 31, 2022 2021 2020 2022 2021 2020 (millions of Canadian dollars) Service cost 131 139 148 43 44 44 Interest cost 1 127 101 128 24 17 31 Expected return on plan assets 1 (295) (252) (260) (85) (73) (88) Amortization/settlement of net actuarial loss 1 8 54 42 — 11 1 Amortization/curtailment of prior service credit 1 — — — (2) — (1) Net periodic benefit (credit)/cost (29) 42 58 (20) (1) (13) Defined contribution benefit cost 10 7 6 — — — Net pension (credit)/cost recognized in Earnings (19) 49 64 (20) (1) (13) Amount recognized in OCI: Amortization/settlement of net actuarial loss (2) (25) (21) — (11) (1) Amortization/curtailment of prior service credit — — — 2 — 1 Net actuarial (gain)/loss arising during the year (288) (291) 118 (52) (99) 100 Total amount recognized in OCI (290) (316) 97 (50) (110) 100 Total amount recognized in Comprehensive income (309) (267) 161 (70) (111) 87 1 Reported within Other income/(expense) in the Consolidated Statements of Earnings. The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our OPEB plans are as follows: Canada US Year ended December 31, 2022 2021 2020 2022 2021 2020 (millions of Canadian dollars) Service cost 4 6 5 1 1 2 Interest cost 1 7 7 8 3 3 7 Expected return on plan assets 1 — — — (12) (10) (12) Amortization/settlement of net actuarial gain 1 (1) — (1) (6) (1) (1) Amortization/curtailment of prior service credit 1 — — — (7) (7) (2) Net periodic benefit (credit)/cost recognized in Earnings 10 13 12 (21) (14) (6) Amount recognized in OCI: Amortization/settlement of net actuarial gain 1 — 1 6 1 1 Amortization/curtailment of prior service credit — — — 7 7 2 Net actuarial (gain)/loss arising during the year (67) (50) 21 (4) (80) 15 Prior service credit — — — — — (33) Total amount recognized in OCI (66) (50) 22 9 (72) (15) Total amount recognized in Comprehensive income (56) (37) 34 (12) (86) (21) 1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.
Schedule of Actuarial Assumptions Used	The weighted average assumptions made in the measurement of the projected benefit obligation and net periodic benefit cost of our pension plans are as follows: Canada US 2022 2021 2020 2022 2021 2020 Projected benefit obligation Discount rate 5.1 % 3.2 % 2.6 % 4.9 % 2.6 % 2.2 % Rate of salary increase 2.9 % 2.9 % 2.3 % 2.8 % 2.8 % 2.7 % Cash balance interest credit rate N/A N/A N/A 4.3 % 4.3 % 4.3 % Net periodic benefit cost Discount rate 3.2 % 2.6 % 3.0 % 2.6 % 2.2 % 3.0 % Rate of return on plan assets 6.6 % 6.2 % 6.8 % 7.4 % 7.3 % 7.9 % Rate of salary increase 2.9 % 2.3 % 3.2 % 2.8 % 2.7 % 2.9 % Cash balance interest credit rate N/A N/A N/A 4.3 % 4.3 % 4.5 % The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligation and net periodic benefit cost of our OPEB plans are as follows: Canada US 2022 2021 2020 2022 2021 2020 Accumulated postretirement benefit obligation Discount rate 5.3 % 3.2 % 2.6 % 4.9 % 2.4 % 2.0 % Net periodic benefit cost Discount rate 3.2 % 2.6 % 3.1 % 2.4 % 2.0 % 2.8 % Rate of return on plan assets N/A N/A N/A 6.0 % 6.0 % 6.7 %
Schedule of Other Postretirement Benefits	The following table details the changes in the accumulated postretirement benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit OPEB plans: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 274 321 173 254 Service cost 4 6 1 1 Interest cost 7 7 3 3 Participant contributions — — 6 8 Actuarial gain 1 (66) (51) (37) (69) Benefits paid (8) (9) (21) (22) Foreign currency exchange rate changes — — 11 (3) Other — — — 1 Accumulated postretirement benefit obligation at end of year 211 274 136 173 Change in plan assets Fair value of plan assets at beginning of year — — 201 188 Actual return/(loss) on plan assets — — (21) 22 Employer contributions 8 9 7 6 Participant contributions — — 6 8 Benefits paid (8) (9) (21) (22) Foreign currency exchange rate changes — — 13 (3) Other — — — 2 Fair value of plan assets at end of year — — 185 201 Overfunded/(underfunded) status at end of year (211) (274) 49 28 Presented as follows: Deferred amounts and other assets — — 75 71 Accounts payable and other (12) (12) — — Other long-term liabilities (199) (262) (26) (43) (211) (274) 49 28 1 Actuarial gains in 2022 and 2021 primarily due to increase in the discount rates used to measure the benefit obligations.
Schedule of Assumed Health Care Cost Trend Rates	The assumed rates for the next year used to measure the expected cost of benefits are as follows: Canada US 1 2022 2021 2022 2021 Health care cost trend rate assumed for next year 4.0 % 4.0 % 4.7 % 7.0 % Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.0 % 4.0 % 3.3 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2021 - 2045 2037 1 In addition, under the Enbridge Employee Services, Inc., Health Reimbursement Account Plan, health care costs will increase by 5.0% every three years.
Schedule of Allocation of Plan Assets	The asset allocation targets and major categories of plan assets are as follows: Canada US Target December 31, Target December 31, Asset Category Allocation 2022 2021 Allocation 2022 2021 Equity securities 43.8 % 38.2 % 46.7 % 45.0 % 38.3 % 52.5 % Fixed income securities 28.4 % 31.7 % 29.8 % 20.0 % 20.5 % 18.4 % Alternatives 1 27.8 % 30.1 % 23.5 % 35.0 % 41.2 % 29.1 % 1 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Fund values are based on the net asset value of the funds that invest directly in the aforementioned underlying investments. The values of the investments have been estimated using the capital accounts representing the plan's ownership interest in the funds.
Schedule of Changes in Fair Value of Plan Assets	The following table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level: Canada US Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2022 Cash and cash equivalents 272 — — 272 13 — — 13 Equity securities Canada — 355 — 355 — — — — Global — 1,263 — 1,263 — 414 — 414 Fixed income securities Government 201 435 — 636 — 87 — 87 Corporate — 433 — 433 — 121 — 121 Alternatives 4 — — 1,291 1,291 — — 445 445 Forward currency contracts — (16) — (16) — — — — Total pension plan assets at fair value 473 2,470 1,291 4,234 13 622 445 1,080 December 31, 2021 Cash and cash equivalents 180 — — 180 10 — — 10 Equity securities Canada 198 228 — 426 — — — — US 1 — — 1 — — — — Global — 1,693 — 1,693 — 609 — 609 Fixed income securities Government 258 459 — 717 — 86 — 86 Corporate — 453 — 453 — 118 — 118 Alternatives 4 — — 1,064 1,064 — — 337 337 Forward currency contracts — 2 — 2 — — — — Total pension plan assets at fair value 637 2,835 1,064 4,536 10 813 337 1,160 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Changes in the net fair value of pension plan assets classified as Level 3 in the fair value hierarchy were as follows: Canada US December 31, 2022 2021 2022 2021 (millions of Canadian dollars) Balance at beginning of year 1,064 912 337 289 Unrealized and realized gains 155 77 78 38 Purchases and settlements, net 72 75 30 10 Balance at end of year 1,291 1,064 445 337 OPEB Plans The following table summarizes the fair value of plan assets for our US funded OPEB plans recorded at each fair value hierarchy level: Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2022 Cash and cash equivalents 2 — — 2 Equity securities US — 34 — 34 Global — 62 — 62 Fixed income securities Government 46 5 — 51 Corporate — 8 — 8 Alternatives 4 — — 28 28 Total OPEB plan assets at fair value 48 109 28 185 December 31, 2021 Cash and cash equivalents 4 — — 4 Equity securities US — 39 — 39 Global — 75 — 75 Fixed income securities Government 47 6 — 53 Corporate — 8 — 8 Alternatives 4 — — 22 22 Total OPEB plan assets at fair value 51 128 22 201 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives includes investments in private debt, private equity, infrastructure and real estate. Changes in the net fair value of US funded OPEB plan assets classified as Level 3 in the fair value hierarchy were as follows: December 31, 2022 2021 (millions of Canadian dollars) Balance at beginning of year 22 22 Unrealized and realized gains 4 2 Purchases and settlements, net 2 (2) Balance at end of year 28 22
Schedule of Expected Benefit Payments and Employer Contributions	Year ending December 31, 2023 2024 2025 2026 2027 2028-2032 (millions of Canadian dollars) Pension Canada 204 210 216 221 226 1,208 US 88 87 87 88 90 424 OPEB Canada 12 12 13 13 13 68 US 16 15 14 13 12 49

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Schedule of Assets and Liabilities, Lessee	Supplemental Statements of Financial Position Information December 31, 2022 December 31, 2021 (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 680 645 Operating lease liabilities - current 3 87 92 Operating lease liabilities - long-term 3 677 612 Total operating lease liabilities 764 704 Finance leases Finance lease right-of-use assets, net 4 62 49 Finance lease liabilities - current 5 17 13 Finance lease liabilities - long-term 3 39 33 Total finance lease liabilities 56 46 Weighted average remaining lease term Operating leases 12 years 12 years Finance leases 5 years 7 years Weighted average discount rate Operating leases 4.2 % 4.1 % Finance leases 4.4 % 3.8 % 1 Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2022 were $47 million (December 31, 2021 - $51 million), $5 million (December 31, 2021 - $5 million) and $43 million (December 31, 2021 - $47 million), respectively. 2 Operating lease ROU assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position. 3 Current operating lease liabilities and long-term operating and finance lease liabilities are reported under Accounts payable and other and Other long-term liabilities, respectively, in the Consolidated Statements of Financial Position. 4 Finance lease ROU assets are reported under Property, plant and equipment, net in the Consolidated Statements of Financial Position. 5 Current finance lease liabilities are reported under Current portion of long-term debt in the Consolidated Statements of Financial Position.
Schedule of Lessee, Operating Lease Liability, Maturity	As at December 31, 2022, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance leases (millions of Canadian dollars) 2023 109 19 2024 110 16 2025 104 8 2026 90 8 2027 82 1 Thereafter 489 10 Total undiscounted lease payments 984 62 Less imputed interest (220) (6) Total 764 56
Schedule of Lessee, Finance Lease Liability, Maturity	As at December 31, 2022, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance leases (millions of Canadian dollars) 2023 109 19 2024 110 16 2025 104 8 2026 90 8 2027 82 1 Thereafter 489 10 Total undiscounted lease payments 984 62 Less imputed interest (220) (6) Total 764 56
Schedule of Operating Lease, Lease Income	Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Operating lease income 266 263 265 Variable lease income 321 333 361 Total lease income 1 587 596 626 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings.
Schedule of Lessor, Operating Lease, Payments to be Received, Maturity	As at December 31, 2022, our future lease payments to be received under operating lease contracts where we are the lessor are as follows: Operating leases (millions of Canadian dollars) 2023 227 2024 215 2025 204 2026 198 2027 201 Thereafter 1,832 Future lease payments 2,877

OTHER INCOME_(EXPENSE) (Tables)

OTHER INCOME/(EXPENSE) (Tables)	12 Months Ended
	Dec. 31, 2022
Other Income and Expenses [Abstract]
Schedule of Other Income and Expenses	Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Gain/(loss) on dispositions (12) 319 (17) Realized foreign currency gain/(loss) 92 126 (10) Unrealized foreign currency gain/(loss) (1,094) 160 191 Net defined pension and OPEB credit 239 150 148 Other 186 224 (74) (589) 979 238

CHANGES IN OPERATING ASSETS A_2

CHANGES IN OPERATING ASSETS AND LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2022
CHANGES IN OPERATING ASSETS AND LIABILITIES
Schedule of Changes in Operating Assets and Liabilities	Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Accounts receivable and other (967) (1,228) 1,546 Accounts receivable from affiliates 17 (38) 8 Inventory (599) (118) (254) Deferred amounts and other assets 1 (195) (586) Accounts payable and other 1,100 87 (770) Accounts payable to affiliates 16 52 1 Interest payable 58 43 31 Other long-term liabilities 362 (69) 117 (12) (1,466) 93

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Schedule of Our Transactions with Equity Investees	Our transactions with significantly influenced investees are as follows: Year ended December 31, 2022 2021 2020 (millions of Canadian dollars) Transportation and other revenues 185 237 219 Commodity sales 51 20 21 Operating and administrative 1 503 380 338 Commodity costs 2 778 790 518 Gas distribution costs 136 131 135 1 During the years ended December 31, 2022, 2021 and 2020, we had Operating and administrative costs from the Seaway Crude Pipeline System of $495 million, $389 million and $342 million, respectively. These costs are a result of an operational contract where we utilize capacity on Seaway Crude Pipeline System assets for use in our Liquids Pipelines business.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Schedule of Commitments	As at December 31, 2022, we have commitments as detailed below: Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Annual debt maturities 1 78,742 6,024 8,220 6,051 3,730 10,344 44,373 Purchase of services, pipe and other materials, including transportation 2 10,661 3,553 1,513 1,070 1,001 767 2,757 Maintenance agreements 3 536 53 53 53 53 55 269 Right-of-ways commitments 1,474 45 45 46 46 46 1,246 Total 91,413 9,675 9,831 7,220 4,830 11,212 48,645 1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discounts, debt issuance costs, finance lease obligations and fair value adjustment. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. 2 Includes capital and operating commitments. Consists primarily of firm capacity payments that provide us with uninterrupted firm access to natural gas and crude oil transportation and storage contracts; contractual obligations to purchase physical quantities of natural gas; and power commitments.

QUARTERLY FINANCIAL DATA (UNA_2

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2022
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2022 Operating revenues 15,097 13,215 11,573 13,424 53,309 Operating income/(loss) 2,420 1,520 1,778 (540) 5,178 Earnings/(loss) 2,057 607 1,383 (1,109) 2,938 Earnings/(loss) attributable to controlling interests 2,029 595 1,362 (983) 3,003 Earnings/(loss) attributable to common shareholders 1,927 450 1,279 (1,067) 2,589 Earnings/(loss) per common share Basic 0.95 0.22 0.63 (0.53) 1.28 Diluted 0.95 0.22 0.63 (0.53) 1.28 2021 Operating revenues 12,187 10,948 11,466 12,470 47,071 Operating income 2,548 1,816 1,388 2,053 7,805 Earnings 2,014 1,521 814 1,965 6,314 Earnings attributable to controlling interests 1,992 1,484 780 1,933 6,189 Earnings attributable to common shareholders 1,900 1,394 682 1,840 5,816 Earnings per common share Basic 0.94 0.69 0.34 0.91 2.87 Diluted 0.94 0.69 0.34 0.91 2.87

BUSINESS OVERVIEW (Details)

BUSINESS OVERVIEW (Details)	12 Months Ended
	Dec. 31, 2022 segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments	5

SIGNIFICANT ACCOUNTING POLICI_3

SIGNIFICANT ACCOUNTING POLICIES - REGULATION (Details) - CAD ($)	Dec. 31, 2022	Dec. 31, 2021
REGULATION
Total regulatory asset	$ 6,467,000,000	$ 5,865,000,000
Deferral for Depreciation for Phase-In Plans Under U.S. GAAP Guidance
REGULATION
Total regulatory asset	$ 0

SIGNIFICANT ACCOUNTING POLICI_4

SIGNIFICANT ACCOUNTING POLICIES - Revenue Recognition (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 166
Largest Non-Affiliated Customer | Sales Revenue, Net | Customer Concentration Risk
Disaggregation of Revenue [Line Items]
Concentration (percent)		13.50%	13.60%
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 238	$ 127	$ 292

SIGNIFICANT ACCOUNTING POLICI_5

SIGNIFICANT ACCOUNTING POLICIES - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2022 depreciation_method
Accounting Policies [Abstract]
Number of primary methods of depreciation which are utilized	2

SIGNIFICANT ACCOUNTING POLICI_6

SIGNIFICANT ACCOUNTING POLICIES - Goodwill (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Impairment of goodwill (Note 16)	$ 2,465	$ 0	$ 0

SIGNIFICANT ACCOUNTING POLICI_7

SIGNIFICANT ACCOUNTING POLICIES - Stock-Based Compensation (Details)	12 Months Ended
	Dec. 31, 2022
Performance Stock Units (PSUs)
STOCK-BASED COMPENSATION
Vesting period	3 years
Annual vesting (percent)	33.33%
Restricted Stock Units (RSU)
STOCK-BASED COMPENSATION
Vesting period	3 years

REVENUE (Details)

REVENUE (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									$ 23,916	$ 19,432	$ 18,817
Total operating revenues	$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 12,470	$ 11,466	$ 10,948	$ 12,187	53,309	47,071	39,087
Mark-to-market (losses)/gains									$ (431)	59	265
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]									Total operating revenues
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									$ 127	70	60
Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									23,789	19,362	18,757
Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									17,077	14,532	14,358
Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									893	648	571
Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									22	49	27
Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,643	4,026	3,663
Total operating revenues									5,653	4,026	3,663
Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									281	177	198
Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									29,150	26,873	19,259
Total operating revenues									29,150	26,873	19,259
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									243	766	1,011
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									11,518	9,639	9,255
Liquids Pipelines | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Liquids Pipelines | Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									11,518	9,639	9,255
Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,384	4,668	4,824
Gas Transmission and Midstream | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Gas Transmission and Midstream | Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,384	4,668	4,824
Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									6,733	4,948	4,540
Gas Distribution and Storage | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									127	70	60
Gas Distribution and Storage | Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									6,606	4,878	4,480
Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									281	177	198
Renewable Power Generation | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Renewable Power Generation | Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									281	177	198
Business Segments | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									11,518	9,639	9,255
Total operating revenues									12,052	10,581	10,423
Business Segments | Liquids Pipelines | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									11,283	9,492	9,161
Business Segments | Liquids Pipelines | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									235	147	94
Business Segments | Liquids Pipelines | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Liquids Pipelines | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Liquids Pipelines | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Liquids Pipelines | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	0	0
Business Segments | Liquids Pipelines | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(81)	375	584
Business Segments | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,384	4,668	4,824
Total operating revenues									5,426	4,711	4,870
Business Segments | Gas Transmission and Midstream | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,012	4,364	4,523
Business Segments | Gas Transmission and Midstream | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									350	255	274
Business Segments | Gas Transmission and Midstream | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									22	49	27
Business Segments | Gas Transmission and Midstream | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Gas Transmission and Midstream | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Gas Transmission and Midstream | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	0	0
Business Segments | Gas Transmission and Midstream | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									39	42	44
Business Segments | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									6,733	4,948	4,540
Total operating revenues									6,729	4,980	4,569
Business Segments | Gas Distribution and Storage | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									782	676	674
Business Segments | Gas Distribution and Storage | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									308	246	203
Business Segments | Gas Distribution and Storage | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Gas Distribution and Storage | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,643	4,026	3,663
Business Segments | Gas Distribution and Storage | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Gas Distribution and Storage | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	0	0
Business Segments | Gas Distribution and Storage | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(20)	13	17
Business Segments | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									281	177	198
Total operating revenues									582	512	587
Business Segments | Renewable Power Generation | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Renewable Power Generation | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Renewable Power Generation | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Renewable Power Generation | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Renewable Power Generation | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									281	177	198
Business Segments | Renewable Power Generation | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	0	0
Business Segments | Renewable Power Generation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									305	336	389
Business Segments | Energy Services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Total operating revenues									29,175	26,917	19,283
Business Segments | Energy Services | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Energy Services | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Energy Services | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Energy Services | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Energy Services | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Energy Services | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									29,150	26,873	19,259
Business Segments | Energy Services | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	0	0
Eliminations and Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Total operating revenues									(655)	(630)	(645)
Eliminations and Other | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Eliminations and Other | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Eliminations and Other | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Eliminations and Other | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Eliminations and Other | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Eliminations and Other | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	0	0
Eliminations and Other | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	0	(23)
Intersegment revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(655)	(630)	(622)
Intersegment revenue | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									615	567	584
Intersegment revenue | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									3	1	2
Intersegment revenue | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									16	19	12
Intersegment revenue | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(4)	(1)	0
Intersegment revenue | Energy Services
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									$ 25	$ 44	$ 24

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)
Revenue from Contract with Customer [Abstract]
Revenue recognized	$ 166
Increase (decrease) in contract with customers, liability	453
Remaining performance obligation	58,600
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue from Contract with Customer [Abstract]
Remaining performance obligation	$ 7,600
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period	1 year

REVENUE - Contract Balances (De

REVENUE - Contract Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Contract Receivables	$ 3,183	$ 2,369
Contract Assets	230	213
Contract Liabilities	$ 2,241	$ 1,898

SEGMENTED INFORMATION (Details)

SEGMENTED INFORMATION (Details) $ in Millions, $ in Millions			3 Months Ended								12 Months Ended
	Aug. 17, 2022 CAD ($)	Aug. 17, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Sep. 30, 2022 CAD ($)	Jun. 30, 2022 CAD ($)	Mar. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Sep. 30, 2021 CAD ($)	Jun. 30, 2021 CAD ($)	Mar. 31, 2021 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)
Segmented Information
Revenues (Note 4)			$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 12,470	$ 11,466	$ 10,948	$ 12,187	$ 53,309	$ 47,071	$ 39,087
Commodity and gas distribution costs											(32,589)	(28,702)	(20,669)
Operating and administrative											(8,219)	(6,712)	(6,749)
Impairment of long-lived assets											(541)
Impairment of goodwill (Note 16)											(2,465)	0	0
Income/(loss) from equity investments (Note 13)											2,056	1,711	1,136
Impairment of equity investments											0	(111)	(2,351)
Gain on joint venture merger transaction (Note 13)	$ 1,100	$ 832									1,076	0	0
Other income/(expense) (Note 28)											(589)	979	238
Earnings/(loss) before interest, income taxes and depreciation and amortization											12,038	14,236	10,692
Depreciation and amortization											(4,317)	(3,852)	(3,712)
Interest expense (Note 18)											(3,179)	(2,655)	(2,790)
Income tax expense (Note 25)											(1,604)	(1,415)	(774)
Earnings			(1,109)	$ 1,383	$ 607	$ 2,057	1,965	$ 814	$ 1,521	$ 2,014	2,938	6,314	3,416
Capital expenditures											4,690	7,885	5,470
Property, plant and equipment, net			104,460				100,067				104,460	100,067	94,571
Liquids Pipelines
Segmented Information
Impairment of goodwill (Note 16)											0
Gas Distribution and Storage
Segmented Information
Impairment of goodwill (Note 16)											0
Business Segments | Liquids Pipelines
Segmented Information
Revenues (Note 4)											12,052	10,581	10,423
Commodity and gas distribution costs											0	(25)	(20)
Operating and administrative											(4,287)	(3,431)	(3,331)
Impairment of long-lived assets											(245)
Impairment of goodwill (Note 16)											0
Income/(loss) from equity investments (Note 13)											785	759	558
Impairment of equity investments												0	0
Gain on joint venture merger transaction (Note 13)											0
Other income/(expense) (Note 28)											59	13	53
Earnings/(loss) before interest, income taxes and depreciation and amortization											8,364	7,897	7,683
Capital expenditures											1,418	4,051	2,033
Property, plant and equipment, net			53,567				52,530				53,567	52,530	48,799
Business Segments | Gas Transmission and Midstream
Segmented Information
Revenues (Note 4)											5,426	4,711	4,870
Commodity and gas distribution costs											0	0	0
Operating and administrative											(2,254)	(1,877)	(1,859)
Impairment of long-lived assets											0
Impairment of goodwill (Note 16)											(2,465)
Income/(loss) from equity investments (Note 13)											1,133	813	479
Impairment of equity investments												(111)	(2,351)
Gain on joint venture merger transaction (Note 13)											1,076
Other income/(expense) (Note 28)											210	135	(52)
Earnings/(loss) before interest, income taxes and depreciation and amortization											3,126	3,671	1,087
Capital expenditures											1,690	2,420	2,130
Property, plant and equipment, net			29,666				27,028				29,666	27,028	25,745
Business Segments | Gas Distribution and Storage
Segmented Information
Revenues (Note 4)											6,729	4,980	4,569
Commodity and gas distribution costs											(3,693)	(2,147)	(1,810)
Operating and administrative											(1,289)	(1,143)	(1,091)
Impairment of long-lived assets											0
Impairment of goodwill (Note 16)											0
Income/(loss) from equity investments (Note 13)											1	42	9
Impairment of equity investments												0	0
Gain on joint venture merger transaction (Note 13)											0
Other income/(expense) (Note 28)											79	385	71
Earnings/(loss) before interest, income taxes and depreciation and amortization											1,827	2,117	1,748
Capital expenditures											1,499	1,343	1,134
Property, plant and equipment, net			17,857				16,904				17,857	16,904	16,079
Business Segments | Renewable Power Generation
Segmented Information
Revenues (Note 4)											582	512	587
Commodity and gas distribution costs											(16)	0	(2)
Operating and administrative											(255)	(180)	(191)
Impairment of long-lived assets											(235)
Impairment of goodwill (Note 16)											0
Income/(loss) from equity investments (Note 13)											141	101	94
Impairment of equity investments												0	0
Gain on joint venture merger transaction (Note 13)											0
Other income/(expense) (Note 28)											45	75	35
Earnings/(loss) before interest, income taxes and depreciation and amortization											262	508	523
Capital expenditures											50	16	81
Property, plant and equipment, net			3,082				3,315				3,082	3,315	3,495
Business Segments | Energy Services
Segmented Information
Revenues (Note 4)											29,175	26,917	19,283
Commodity and gas distribution costs											(29,525)	(27,174)	(19,450)
Operating and administrative											(49)	(48)	(67)
Impairment of long-lived assets											(13)
Impairment of goodwill (Note 16)											0
Income/(loss) from equity investments (Note 13)											0	0	(3)
Impairment of equity investments												0	0
Gain on joint venture merger transaction (Note 13)											0
Other income/(expense) (Note 28)											(5)	(8)	1
Earnings/(loss) before interest, income taxes and depreciation and amortization											(417)	(313)	(236)
Capital expenditures											0	1	2
Property, plant and equipment, net			6				23				6	23	24
Eliminations and Other
Segmented Information
Revenues (Note 4)											(655)	(630)	(645)
Commodity and gas distribution costs											645	644	613
Operating and administrative											(85)	(33)	(210)
Impairment of long-lived assets											(48)
Impairment of goodwill (Note 16)											0
Income/(loss) from equity investments (Note 13)											(4)	(4)	(1)
Impairment of equity investments												0	0
Gain on joint venture merger transaction (Note 13)											0
Other income/(expense) (Note 28)											(977)	379	130
Earnings/(loss) before interest, income taxes and depreciation and amortization											(1,124)	356	(113)
Capital expenditures											33	54	90
Property, plant and equipment, net			$ 282				$ 267				$ 282	$ 267	$ 429

SEGMENTED INFORMATION - Geograp

SEGMENTED INFORMATION - Geographic Information (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Geographic Information
Revenues (Note 4)	$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 12,470	$ 11,466	$ 10,948	$ 12,187	$ 53,309	$ 47,071	$ 39,087
Property, plant and equipment, net	104,460				100,067				104,460	100,067	94,571
Canada
Geographic Information
Revenues (Note 4)									27,498	20,474	16,453
Property, plant and equipment, net	47,602				47,102				47,602	47,102
US
Geographic Information
Revenues (Note 4)									25,811	26,597	$ 22,634
Property, plant and equipment, net	$ 56,858				$ 52,965				$ 56,858	$ 52,965

EARNINGS PER COMMON SHARE (Deta

EARNINGS PER COMMON SHARE (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share [Abstract]
Weighted average number of common shares outstanding (shares)		2	5
Weighted average shares outstanding (in shares)	2,025	2,023	2,020
Effect of dilutive options and RSUs (in shares)	4	2	1
Diluted weighted average shares outstanding (in shares)	2,029	2,025	2,021
Anti-dilutive stock options excluded from diluted earnings per common share calculation (in shares)	10.4	18.6	29.8
Weighted average exercise price of anti-dilutive stock options (in CAD per share)	$ 56.49	$ 52.89	$ 51.42

REGULATORY MATTERS - Liquids Pi

REGULATORY MATTERS - Liquids Pipelines (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 6,467	$ 5,865
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Term of CTS establishing a Canadian Local Toll	10 years
Regulatory assets	$ 2,100	$ 2,100
Southern Lights Pipeline
Public Utilities, General Disclosures [Line Items]
Pre-determined after-tax rate of return on equity (ROE) (as a percent)	10%

REGULATORY MATTERS - Enbridge G

REGULATORY MATTERS - Enbridge Gas Distribution Inc. (Narrative) (Details) - Enbridge Gas Distribution	12 Months Ended
	Dec. 31, 2022
Public Utilities, General Disclosures [Line Items]
Term of incentive regulation framework	5 years
Inflation stretch factor (percent)	0.30%
Earnings allowed to be retained under earnings sharing mechanism (as a percent)	1.50%

REGULATORY MATTERS - Schedule o

REGULATORY MATTERS - Schedule of Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	$ 604	$ 259
Total long - term regulatory assets	5,863	5,606
Regulatory assets	6,467	5,865
Regulatory Liabilities [Line Items]
Total current regulatory liabilities	167	106
Total long - term regulatory liabilities	3,624	3,321
Total regulatory liabilities	3,791	3,427
Other regulatory assets (liabilities)
Regulatory Liabilities [Line Items]
Total current regulatory liabilities	167	106
Total long - term regulatory liabilities	250	234
Future removal and restoration reserves
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities	1,615	1,543
U.S income Taxes
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities	918	895
Pipeline future abandonment costs (Note 14)
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities	610	649
Pension plans and OPEB
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities	231	0
Purchase gas variance
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	190	15
Total long - term regulatory assets	244	215
Under-recovery of fuel costs
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	109	114
Other regulatory assets (liabilities)
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	305	130
Total long - term regulatory assets	244	339
Deferred income taxes
Regulatory Assets [Line Items]
Total long - term regulatory assets	4,473	4,176
Long-term debt
Regulatory Assets [Line Items]
Total long - term regulatory assets	378	398
Negative salvage
Regulatory Assets [Line Items]
Total long - term regulatory assets	265	243
Accounting policy changes
Regulatory Assets [Line Items]
Total long - term regulatory assets	219	157
Pension plans and OPEB
Regulatory Assets [Line Items]
Total long - term regulatory assets	$ 40	$ 78

ACQUISITIONS AND DISPOSITIONS -

ACQUISITIONS AND DISPOSITIONS - Acquisitions (Narrative) (Details) $ in Millions, $ in Millions					3 Months Ended	12 Months Ended
	Sep. 27, 2022 CAD ($)	Sep. 27, 2022 USD ($)	Oct. 12, 2021 CAD ($)	Oct. 12, 2021 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 CAD ($)	Oct. 05, 2022	Sep. 27, 2022 USD ($)	Oct. 12, 2021 USD ($)
Athabasca Regional Oil Sands System | Athabasca Regional Oil Sands System
Business Acquisition [Line Items]
Noncontrolling interest (percent)							88.40%
Moda Midstream Operating, LLC (Moda)
Business Acquisition [Line Items]
Cash			$ 3,755	$ 3,000
Contingent consideration			$ 187						$ 150
Acquisition-related expenses/transaction costs incurred						$ 21
Revenues generated by acquiree					$ 80
Earnings generated by acquiree					$ 9
Tri Global Energy, LLC
Business Acquisition [Line Items]
Cash	$ 295	$ 215
Contingent future payment (up to)	$ 72							$ 53
Expected useful life	3 years 6 months	3 years 6 months
Goodwill expected tax deductible period	15 years	15 years
Contingent consideration	$ 49							$ 36

ACQUISITIONS AND DISPOSITIONS_2

ACQUISITIONS AND DISPOSITIONS - Summary of Estimated Fair Values Assigned to Net Assets (Details) $ in Millions, $ in Millions	Sep. 27, 2022 CAD ($)	Sep. 27, 2022 USD ($)	Oct. 12, 2021 CAD ($)	Oct. 12, 2021 USD ($)	Dec. 31, 2022 CAD ($)	Sep. 27, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Oct. 12, 2021 USD ($)	Dec. 31, 2020 CAD ($)
Fair value of net assets acquired:
Goodwill					$ 32,440		$ 32,775		$ 32,688
Moda Midstream Operating, LLC (Moda)
Fair value of net assets acquired:
Current assets			$ 62
Property, plant and equipment			1,480
Long-term investments			427
Intangible assets			1,781
Current liabilities			59
Long-term liabilities			17
Goodwill			268
Purchase price:
Cash			3,755	$ 3,000
Contingent consideration			187					$ 150
Purchase price			$ 3,942
Ownership interest acquired (as a percent)			20%					20%
Amortized on a straight-line basis over an expected useful life			10 years	10 years
Tax deductible period			15 years	15 years
Tri Global Energy, LLC
Fair value of net assets acquired:
Current assets	$ 5
Property, plant and equipment	3
Long-term investments	8
Intangible assets	117
Long-term assets	3
Current liabilities	61
Long-term debt (Note 18)	18
Long-term liabilities	105
Goodwill	392
Purchase price:
Cash	295	$ 215
Contingent consideration	49					$ 36
Purchase price	344
Contingent future payment (up to)	$ 72					$ 53

ACQUISITIONS AND DISPOSITIONS_3

ACQUISITIONS AND DISPOSITIONS - Schedule of Supplemental Pro Forma Consolidated Financial Information (Details) - Moda Midstream Operating, LLC (Moda) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Operating revenues	$ 47,339	$ 39,435
Earnings attributable to common shareholders	5,771	2,938
Acquisition-related expenses	21
Acquisition-related expenses, after tax	16
Amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets	193	207
Amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets, after tax	$ 145	$ 155

ACQUISITIONS AND DISPOSITIONS_4

ACQUISITIONS AND DISPOSITIONS - Dispositions (Narrative) (Details)				12 Months Ended
	Jun. 01, 2020 CAD ($)	May 01, 2020 CAD ($)	Apr. 01, 2020 CAD ($)	Dec. 31, 2022 CAD ($)	Oct. 05, 2022 CAD ($) _community pipeline
Athabasca Indigenous Investments Limited Partnership
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of communities represented | _community					23
Athabasca Regional Oil Sands System
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of pipelines to be sold | pipeline					7
Disposal group, consideration					$ 1,100,000,000
Athabasca Regional Oil Sands System | Athabasca Regional Oil Sands System
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest percentage held by noncontrolling owners					11.60%
Noncontrolling interest (percent)					88.40%
Dispositions | Line 10 Crude Oil
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest	$ 0
Dispositions | Ozark Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest			$ 1,000,000
Cash proceeds from sale of interest			$ 63,000,000
Dispositions | Athabasca Regional Oil Sands System
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest				$ 0
Dispositions | Montana-Alberta Tie Line (MATL)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest		$ 4,000,000
Cash proceeds from sale of interest		$ 189,000,000

ACCOUNTS RECEIVABLE AND OTHER_2

ACCOUNTS RECEIVABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Receivables [Abstract]
Trade receivables and unbilled revenues	$ 5,616	$ 4,957
Short-term portion of derivative assets (Note 24)	1,015	529
Regulatory assets (Note 7)	604	259
Gas imbalance	461	276
Taxes receivable	323	407
Other	852	434
Total accounts receivable and other	8,871	6,862
Allowance for doubtful accounts receivable	$ 92	$ 87

INVENTORY (Details)

INVENTORY (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Inventory Disclosure [Abstract]
Natural gas	$ 1,491	$ 953
Crude oil	652	624
Other	112	93
Total Inventory	$ 2,255	$ 1,670

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 134,000	$ 126,040
Total accumulated depreciation	(29,540)	(25,973)
Property, plant and equipment, net	$ 104,460	100,067
Pipelines
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.90%
Total property, plant and equipment	$ 66,528	62,997
Facilities and equipment
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	3.50%
Total property, plant and equipment	$ 37,028	34,331
Land and right-of-way
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.20%
Total property, plant and equipment	$ 3,637	3,320
Gas mains, services and other
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.60%
Total property, plant and equipment	$ 14,491	13,606
Storage
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.30%
Total property, plant and equipment	$ 3,477	3,099
Wind turbines, solar panels and other
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	4.10%
Total property, plant and equipment	$ 4,912	4,912
Other
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	8.50%
Total property, plant and equipment	$ 1,611	1,507
Under construction
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	0%
Total property, plant and equipment	$ 2,316	$ 2,268

PROPERTY, PLANT AND EQUIPMENT_2

PROPERTY, PLANT AND EQUIPMENT - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Depreciation expense	$ 3,800	$ 3,500	$ 3,400
Impairment loss	541
Magic Valley Wind Farm
Property, Plant and Equipment [Line Items]
Impairment loss	227
Bakken Pipeline System
Property, Plant and Equipment [Line Items]
Impairment loss	$ 183

VARIABLE INTEREST ENTITIES - Sc

VARIABLE INTEREST ENTITIES - Schedule of Assets and Liabilities of Consolidated VIEs (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Assets
Cash and cash equivalents	$ 861	$ 286
Restricted cash	46	34
Accounts receivable and other	8,871	6,862
Inventory	2,255	1,670
Current assets	12,147	8,959
Property, plant and equipment, net	104,460	100,067	$ 94,571
Long-term investments	15,936	13,324
Restricted long-term investments	593	630
Deferred amounts and other assets	9,542	8,613
Intangible assets, net	4,018	4,008
Total assets	179,608	168,864
Liabilities
Accounts payable and other	11,392	9,767
Current liabilities	20,301	18,229
Other long-term liabilities	9,189	7,617
Deferred income taxes	13,781	11,689
Liabilities	116,210	105,496
Variable Interest Entity, Primary Beneficiary
Assets
Cash and cash equivalents	426	247
Restricted cash	12	4
Accounts receivable and other	199	99
Accounts receivable from affiliates	23	0
Inventory	12	9
Current assets	672	359
Property, plant and equipment, net	7,707	3,052
Long-term investments	14	16
Restricted long-term investments	98	101
Deferred amounts and other assets	158	2
Intangible assets, net	102	108
Total assets	8,751	3,638
Liabilities
Accounts payable and other	251	84
Accounts payable to affiliates	21	0
Current liabilities	272	84
Other long-term liabilities	859	182
Deferred income taxes	5	5
Liabilities	1,136	271
Net assets	$ 7,615	$ 3,367

VARIABLE INTEREST ENTITIES - _2

VARIABLE INTEREST ENTITIES - Schedule of the Carrying Amount of Interest in VIEs (Details) $ in Millions	Dec. 31, 2022 CAD ($) project	Nov. 30, 2022	Dec. 31, 2021 CAD ($)
VARIABLE INTEREST ENTITY
Affiliate loan receivable	$ 752		$ 954
EIH S.a.r.l.
VARIABLE INTEREST ENTITY
Number of offshore wind projects | project	3
Woodfibre LNG LP
VARIABLE INTEREST ENTITY
Ownership interest (as a percent)		30%
Variable Interest Entity, Not Primary Beneficiary
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	$ 1,616		1,054
Maximum Exposure to Loss	4,466		4,288
Variable Interest Entity, Not Primary Beneficiary | Aux Sable Liquid Products L.P.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	91		113
Maximum Exposure to Loss	117		195
Variable Interest Entity, Not Primary Beneficiary | EIH S.a.r.l.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	37		38
Maximum Exposure to Loss	637		664
Affiliate loan receivable	56		73
Variable Interest Entity, Not Primary Beneficiary | Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE			54
Maximum Exposure to Loss			2,121
Affiliate loan receivable			807
Variable Interest Entity, Not Primary Beneficiary | Rampion Offshore Wind Limited
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	413		450
Maximum Exposure to Loss	468		508
Variable Interest Entity, Not Primary Beneficiary | Vector Pipeline L.P.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	195		189
Maximum Exposure to Loss	325		374
Affiliate loan receivable	25		80
Credit facility provided	105		105
Variable Interest Entity, Not Primary Beneficiary | Woodfibre LNG LP
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	635
Maximum Exposure to Loss			2,476
Variable Interest Entity, Not Primary Beneficiary | Other
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	245		210
Maximum Exposure to Loss	$ 443		$ 426

VARIABLE INTEREST ENTITIES - Na

VARIABLE INTEREST ENTITIES - Narrative (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Affiliate loan receivable	$ 752	$ 954

LONG-TERM INVESTMENTS - Schedul

LONG-TERM INVESTMENTS - Schedule of Long-Term Investments (Details) $ in Millions	Dec. 31, 2022 CAD ($) project	Nov. 30, 2022	Aug. 17, 2022	Aug. 16, 2022	Dec. 31, 2021 CAD ($)	Oct. 12, 2021	Mar. 18, 2021 project
LONG-TERM INVESTMENTS
Total long-term investments	$ 15,936				$ 13,324
DCP Midstream, LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	90%			50%
DCP Midstream, LP
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	13.20%				28.30%
Woodfibre LNG Limited Partnership
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		30%
EIH S.a.r.l.
LONG-TERM INVESTMENTS
Number of offshore wind projects | project	3
Gray Oak Pipeline, LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	65%				65%
Éolien Maritime France SAS
LONG-TERM INVESTMENTS
Number of offshore wind projects | project							3
EMF
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)							25.50%
Gray Oak Holdings LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)			58.50%	22.80%	35%
MaRen Bakken Company LLC | MaRen Bakken Company LLC | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	75%
EQUITY INVESTMENTS	$ 1,968				$ 1,752
MaRen Bakken Company LLC | Bakken Pipeline Investments, LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	49%
MaRen Bakken Company LLC | Bakken Pipeline System
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	27.60%
DCP Midstream, LLC | DCP Midstream, LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	23.40%
DCP Midstream, LLC | DCP Midstream, LLC | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	90%
EQUITY INVESTMENTS	$ 1,394				469
DCP Midstream, LLC | DCP Midstream, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	23.40%
EQUITY INVESTMENTS	$ 317				397
DCP Midstream, LLC | DCP Midstream, LP
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	56.50%
Seaway | Seaway | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
EQUITY INVESTMENTS	$ 2,744				2,634
Illinois Extension Pipeline Company, LLC | Illinois Extension Pipeline Company, LLC | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	65%
EQUITY INVESTMENTS	$ 622				593
Cactus II Pipeline, LLC | Cactus II Pipeline, LLC | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	30%					20%
EQUITY INVESTMENTS	$ 658				434
Other | Other | Liquids Pipelines
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	76				71
Other | Other | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	0				14
Other | Other | Gas Distribution and Storage
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	20				20
Other | Other | Renewable Power Generation
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	$ 107				92
Other | Other | Minimum | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	30%
Other | Other | Minimum | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	20%
Other | Other | Minimum | Gas Distribution and Storage
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	47.60%
Other | Other | Minimum | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	12%
Other | Other | Minimum | Eliminations and Other
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	42.70%
Other | Other | Maximum | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	43.80%
Other | Other | Maximum | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	33.30%
Other | Other | Maximum | Gas Distribution and Storage
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
Other | Other | Maximum | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
Other | Other | Maximum | Eliminations and Other
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
Alliance Pipeline | Alliance Pipeline | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
EQUITY INVESTMENTS	$ 430				504
Aux Sable | Aux Sable | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	$ 214				238
Aux Sable | Aux Sable | Minimum | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	42.70%
Aux Sable | Aux Sable | Maximum | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
Gulfstream Natural Gas System, L.L.C. | Gulfstream Natural Gas System, L.L.C. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
EQUITY INVESTMENTS	$ 1,274				1,180
Nexus Gas Transmission, LLC | Nexus Gas Transmission, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
EQUITY INVESTMENTS	$ 1,813				1,724
Sabal Trail Transmission, LLC | Sabal Trail Transmission, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
EQUITY INVESTMENTS	$ 1,535				1,464
Southeast Supply Header, LLC | Southeast Supply Header, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
EQUITY INVESTMENTS	$ 86				82
Steckman Ridge, LP | Steckman Ridge, LP | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50%
EQUITY INVESTMENTS	$ 91				88
Vector Pipeline Limited | Vector Pipeline Limited | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	60%
EQUITY INVESTMENTS	$ 195				189
Woodfibre LNG Limited Partnership | Woodfibre LNG Limited Partnership | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	30%
EQUITY INVESTMENTS	$ 635				0
Offshore - various joint ventures | Offshore - various joint ventures | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	$ 314				309
Offshore - various joint ventures | Offshore - various joint ventures | Minimum | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	22%
Offshore - various joint ventures | Offshore - various joint ventures | Maximum | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	74.30%
EIH S.a.r.l. | EIH S.a.r.l.
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)							49%
EIH S.a.r.l. | EIH S.a.r.l. | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	51%
EQUITY INVESTMENTS	$ 37				38
Enbridge Renewable Infrastructure Investments S.à.r.l. | Enbridge Renewable Infrastructure Investments S.à.r.l. | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	51%
EQUITY INVESTMENTS	$ 163				54
Rampion Offshore Wind Limited | Rampion Offshore Wind Limited | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	24.90%
EQUITY INVESTMENTS	$ 413				450
NextBridge Infrastructure LP | NextBridge Infrastructure LP | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	25%
EQUITY INVESTMENTS	$ 241				186
Fairwood Peninsula Energy Corporation | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	22				20
Emerging Technologies and Other | Renewable Power Generation
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	31				32
Other long-term investments | Eliminations and Other
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	$ 488				$ 290
Bakken Pipeline Investments, LLC | Bakken Pipeline System
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	75%
Gray Oak Pipeline, LLC | Gray Oak Pipeline, LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	58.50%
Gray Oak Pipeline, LLC | Gray Oak Holdings LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)					22.80%
Éolien Maritime France SAS | Éolien Maritime France SAS
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)							50%
Saint-Nazaire | Saint-Nazaire
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)							25.50%
Fécamp | Fécamp
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)							17.90%
Calvados | Calvados
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)							21.70%

LONG-TERM INVESTMENTS - Narrati

LONG-TERM INVESTMENTS - Narrative (Details) $ in Millions, $ in Millions						12 Months Ended
	Nov. 29, 2022 CAD ($)	Nov. 29, 2022 USD ($)	Aug. 17, 2022 CAD ($)	Aug. 17, 2022 USD ($)	Dec. 30, 2021 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)	Aug. 16, 2022	Jun. 06, 2021
Schedule of Equity Method Investments [Line Items]
Goodwill of investee						$ 3,400	$ 2,500
Amortizable assets of investee						1,500	730
Dividends received from equity investments						2,600	2,200	$ 2,100
Gain on joint venture merger transaction (Note 13)			$ 1,100	$ 832		1,076	0	0
Impairment of equity investments (Note 13)						0	111	2,351
Loss from equity method investment						$ (2,056)	$ (1,711)	(1,136)
Woodfibre LNG Limited
Schedule of Equity Method Investments [Line Items]
Cash	$ 533	$ 392
Noverco Preferred Shares
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)							38.90%			38.90%
Gain on joint venture merger transaction (Note 13)					$ 303
PennEast Pipeline Company, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)						20%
Impairment of equity investments (Note 13)							$ 111
Equity investment						$ 0	$ 12
Steckman Ridge, LP
Schedule of Equity Method Investments [Line Items]
Impairment of equity investments (Note 13)								221
Southeast Supply Header L.L.C.
Schedule of Equity Method Investments [Line Items]
Impairment of equity investments (Note 13)								394
DCP Midstream, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)						90%			50%
Impairment of equity investments (Note 13)								1,700
Loss from equity method investment								$ 324
Woodfibre LNG Limited
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	30%	30%
Gray Oak Holdings LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)			58.50%	58.50%			35%		22.80%
DCP LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)			13.20%	13.20%					28.30%

LONG-TERM INVESTMENTS - Summary

LONG-TERM INVESTMENTS - Summary of Combined Financial Information (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income statement information
Revenues (Note 4)	$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 12,470	$ 11,466	$ 10,948	$ 12,187	$ 53,309	$ 47,071	$ 39,087
Earnings	(1,109)	1,383	607	2,057	1,965	814	1,521	2,014	2,938	6,314	3,416
Earnings/(loss) attributable to controlling interests	(983)	$ 1,362	$ 595	$ 2,029	1,933	$ 780	$ 1,484	$ 1,992	3,003	6,189	3,363
Balance sheet information
Current assets	12,147				8,959				12,147	8,959
Current liabilities	20,301				18,229				20,301	18,229
Noncontrolling interests	3,511				2,542				3,511	2,542
Unconsolidated equity method investments
Income statement information
Revenues (Note 4)									27,043	20,021	14,096
Operating expenses									23,043	16,706	12,411
Earnings									4,334	3,022	2,324
Earnings/(loss) attributable to controlling interests									2,056	1,711	$ 1,136
Balance sheet information
Current assets	4,196				3,639				4,196	3,639
Non-current assets	53,405				44,863				53,405	44,863
Current liabilities	4,843				3,741				4,843	3,741
Non-current liabilities	18,595				16,979				18,595	16,979
Noncontrolling interests	$ 3,785				$ 3,786				$ 3,785	$ 3,786

RESTRICTED LONG-TERM INVESTME_2

RESTRICTED LONG-TERM INVESTMENTS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Long-Lived Assets Held-for-sale [Line Items]
Restricted long-term investments	$ 593	$ 630
Restricted long-term investments (Note 14)	593	630
Debt securities, available-for-sale, amortized cost	437	383
Unrealized holding gains (losses)	(122)	(8)
Future abandonment costs	$ 610	649
Fair Value Recurring Basis Unobservable Input Reconciliation Asset Gain Loss Statement Of Other Comprehensive Income Extensible List Not Disclosed Flag	Restricted long-term investments
Level 1
Long-Lived Assets Held-for-sale [Line Items]
Restricted long-term investments (Note 14)	$ 236	217
Level 2
Long-Lived Assets Held-for-sale [Line Items]
Restricted long-term investments (Note 14)	$ 357	$ 413

INTANGIBLE ASSETS (Details)

INTANGIBLE ASSETS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
INTANGIBLE ASSETS
Cost	$ 5,726	$ 5,535
Accumulated Amortization	(1,708)	(1,527)
Net	4,018	4,008
Amortization expenses
Amortization expense for intangible assets	$ 483	$ 348	$ 294
Software
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	10.90%	12%
Cost	$ 2,019	$ 2,067
Accumulated Amortization	(1,042)	(1,148)
Net	$ 977	$ 919
Power purchase agreements
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4.20%	4.50%
Cost	$ 64	$ 63
Accumulated Amortization	(23)	(21)
Net	$ 41	$ 42
Project agreement
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4%	4%
Cost	$ 163	$ 152
Accumulated Amortization	(36)	(27)
Net	$ 127	$ 125
Customer relationships
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	8.60%	8.50%
Cost	$ 2,701	$ 2,532
Accumulated Amortization	(459)	(215)
Net	$ 2,242	$ 2,317
Other intangible assets
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	5.90%	3.90%
Cost	$ 621	$ 475
Accumulated Amortization	(148)	(116)
Net	$ 473	$ 359
Under development
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	0%	0%
Cost	$ 158	$ 246
Accumulated Amortization	0	0
Net	$ 158	$ 246

INTANGIBLE ASSETS - Narrative (

INTANGIBLE ASSETS - Narrative (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2023	$ 498
2024	498
2025	498
2026	498
2027	$ 498

GOODWILL (Details)

GOODWILL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Oct. 12, 2021
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 32,775	$ 32,688
Impairment	(2,465)	0	$ 0
Foreign exchange and other	1,738	(200)
Acquisition	392	287
Goodwill, ending balance	32,440	32,775	32,688
Goodwill [Abstract]
Goodwill, gross at end of period	36,500	34,400
Goodwill accumulated impairment	4,100	1,600
Goodwill	32,440	32,775	32,688
Impairment of goodwill (Note 16)	2,465	0	0
Moda Midstream Operating, LLC (Moda)
Goodwill [Abstract]
Goodwill				$ 268
Liquids Pipelines
Goodwill [Roll Forward]
Goodwill, beginning balance	8,041	7,828
Impairment	0
Foreign exchange and other	506	(55)
Acquisition	0	268
Goodwill, ending balance	8,547	8,041	7,828
Goodwill [Abstract]
Goodwill	8,547	8,041	7,828
Impairment of goodwill (Note 16)	0
Gas Transmission and Midstream
Goodwill [Roll Forward]
Goodwill, beginning balance	19,335	19,480
Impairment	(2,465)
Foreign exchange and other	1,236	(145)
Acquisition	0	0
Goodwill, ending balance	18,106	19,335	19,480
Goodwill [Abstract]
Goodwill	18,106	19,335	19,480
Impairment of goodwill (Note 16)	2,465
Gas Distribution and Storage
Goodwill [Roll Forward]
Goodwill, beginning balance	5,397	5,378
Impairment	0
Foreign exchange and other	0	0
Acquisition	0	19
Goodwill, ending balance	5,397	5,397	5,378
Goodwill [Abstract]
Goodwill	5,397	5,397	5,378
Impairment of goodwill (Note 16)	0
Renewable Power Generation
Goodwill [Roll Forward]
Goodwill, beginning balance	0	0
Impairment	0
Foreign exchange and other	(4)	0
Acquisition	392	0
Goodwill, ending balance	388	0	0
Goodwill [Abstract]
Goodwill	388	0	0
Impairment of goodwill (Note 16)	0
Energy Services
Goodwill [Roll Forward]
Goodwill, beginning balance	2	2
Impairment	0
Foreign exchange and other	0	0
Acquisition	0	0
Goodwill, ending balance	2	2	2
Goodwill [Abstract]
Goodwill	2	$ 2	$ 2
Impairment of goodwill (Note 16)	0
Gas Transmission Assets
Goodwill [Roll Forward]
Impairment	(2,500)
Goodwill [Abstract]
Impairment of goodwill (Note 16)	$ 2,500

ACCOUNTS PAYABLE AND OTHER (Det

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Payables and Accruals [Abstract]
Trade payables and operating accrued liabilities	$ 5,235	$ 4,470
Dividends payable	1,825	1,773
Current deferred credits	1,056	853
Construction payables and contractor holdbacks	937	844
Current derivative liabilities	898	717
Taxes payable	683	478
Other	758	632
Accounts payable and other liabilities	$ 11,392	$ 9,767

DEBT - Schedule of Debt (Detail

DEBT - Schedule of Debt (Details) $ in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)
DEBT
Total debt	$ 80,980		$ 75,640
Fair value adjustment	608		667
Other	(393)		(363)
Current maturities	(6,045)		(6,164)
Short-term borrowings	(1,996)		(1,515)
Long-term debt	72,939		67,961
Long-term debt	$ 38,000	$ 31	$ 36,000	$ 31
Weighted average interest rate (as a percent)	4.50%	4.50%	0.50%	0.50%
US dollar senior notes | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	3.50%	3.50%
Total debt	$ 12,060		$ 10,992
Medium-term notes | Enbridge Gas Inc.
DEBT
Weighted average interest rate (percent)	4.10%	4.10%
Total debt	$ 9,535		9,010
Medium-term notes | Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (percent)	4.20%	4.20%
Total debt	$ 5,425		5,575
Carrying value	$ 100
Medium-term notes | Westcoast Energy Inc.
DEBT
Weighted average interest rate (percent)	4.90%	4.90%
Total debt	$ 1,225		1,475
Medium-term notes | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	3.80%	3.80%
Total debt	$ 8,223		8,123
Sustainability-linked bonds | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	2%	2%
Total debt	$ 3,355		2,363
Fixed-to-fixed subordinated term notes | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	4.10%	4.10%
Total debt	$ 3,596		1,263
Term of fixed rate	30 years
Fixed-to-fixed subordinated term notes | Enbridge Inc. | Initial Period
DEBT
Term of fixed rate	5 years
Fixed-to-fixed subordinated term notes | Enbridge Inc. | Subsequent period
DEBT
Term of fixed rate	10 years
Fixed-to-floating rate subordinated term notes | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	5.90%	5.90%
Total debt	$ 6,736		6,442
Term of fixed rate	10 years
Fixed-to-floating rate subordinated term notes | Enbridge Inc. | Initial Period
DEBT
Term of fixed rate	5 years
Floating rate notes | Enbridge Inc.
DEBT
Total debt	$ 1,491		1,579
Commercial paper and credit facility draws | Enbridge (U.S.) Inc.
DEBT
Weighted average interest rate (percent)	4.50%	4.50%
Total debt	$ 4,199		4,845
Commercial paper and credit facility draws | Enbridge Gas Inc.
DEBT
Weighted average interest rate (percent)	4.50%	4.50%
Total debt	$ 2,000		1,515
Commercial paper and credit facility draws | Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (percent)	4.60%	4.60%
Total debt	$ 312		667
Commercial paper and credit facility draws | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	4.80%	4.80%
Total debt	$ 7,984		7,837
Senior notes | Enbridge Energy Partners, L.P.
DEBT
Weighted average interest rate (percent)	6.50%	6.50%
Total debt	$ 3,320		3,095
Senior notes | Enbridge Pipelines (Southern Lights) L.L.C.
DEBT
Weighted average interest rate (percent)	4%	4%
Total debt	$ 921		949
Senior notes | Enbridge Southern Lights LP
DEBT
Weighted average interest rate (percent)	4%	4%
Total debt	$ 222		240
Senior notes | Spectra Energy Capital, LLC
DEBT
Weighted average interest rate (percent)	7%	7%
Total debt	$ 234		218
Senior notes | Algonquin Gas Transmission, LLC
DEBT
Weighted average interest rate (percent)	3.30%	3.30%
Total debt	$ 1,152		1,074
Senior notes | East Tennessee Natural Gas, LLC
DEBT
Weighted average interest rate (percent)	3.10%	3.10%
Total debt	$ 258		240
Senior notes | Texas Eastern Transmission, LP
DEBT
Weighted average interest rate (percent)	3.30%	3.30%
Total debt	$ 3,455		3,095
Senior notes | Spectra Energy Partners, LP
DEBT
Weighted average interest rate (percent)	4.30%	4.30%
Total debt	$ 4,336		4,042
Senior notes | Tri Global Energy, LLC
DEBT
Weighted average interest rate (percent)	12.70%	12.70%
Total debt	$ 18		0
Debentures | Enbridge Gas Inc.
DEBT
Weighted average interest rate (percent)	9.10%	9.10%
Total debt	$ 210		210
Debentures | Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (percent)	8.20%	8.20%
Total debt	$ 200		200
Debentures | Westcoast Energy Inc.
DEBT
Weighted average interest rate (percent)	8.10%	8.10%
Total debt	$ 275		275
Other | Enbridge (U.S.) Inc.
DEBT
Total debt	7		7
Other | Enbridge Gas Inc.
DEBT
Total debt	1		0
Other | Enbridge Inc.
DEBT
Total debt	$ 15		$ 5
Minimum | SOFR | Floating rate notes | Enbridge Inc.
DEBT
Basis spread on variable rate (as a percent)	0.40%
Maximum | SOFR | Floating rate notes | Enbridge Inc.
DEBT
Basis spread on variable rate (as a percent)	0.63%

DEBT - Schedule of Committed Cr

DEBT - Schedule of Committed Credit Facilities (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Committed credit facilities
DEBT
Total Facilities	$ 23,591
Draws	14,495
Available	9,096
Enbridge (U.S.) Inc.
DEBT
Total Facilities	8,604
Draws	4,199
Available	4,405
Enbridge Pipelines Inc.
DEBT
Total Facilities	2,000
Draws	312
Available	1,688
Enbridge Gas Inc.
DEBT
Total Facilities	2,000
Draws	2,000
Available	0
Enbridge Inc.
DEBT
Total Facilities	10,987
Draws	7,984
Available	$ 3,003

DEBT - Credit Facilities (Narra

DEBT - Credit Facilities (Narrative) (Details) $ in Millions, ¥ in Billions

2 Months Ended

12 Months Ended

Dec. 16, 2022 CAD ($)

Jun. 23, 2022 CAD ($)

May 17, 2022 CAD ($)

Feb. 10, 2022 CAD ($)

Jan. 19, 2022 CAD ($)

Jul. 23, 2021 CAD ($)

Feb. 25, 2021 CAD ($) loan

Feb. 10, 2021 CAD ($)

Aug. 31, 2022 CAD ($)

Dec. 31, 2022 CAD ($)

Dec. 31, 2022 USD ($)

Dec. 31, 2022 USD ($)

Jul. 31, 2022 CAD ($)

May 24, 2022 USD ($)

May 17, 2022 JPY (¥)

Dec. 31, 2021 CAD ($)

Line of Credit Facility [Line Items]

Long-term debt

$ 72,939,000,000

$ 67,961,000,000

Principal amount

3,400,000,000

$ 3,200

Extinguishment of debt

1,500,000,000

$ 2,000

Enbridge Inc.

Line of Credit Facility [Line Items]

Credit facility capacity

10,987,000,000

Unutilized credit facility

3,003,000,000

US dollar senior notes

Line of Credit Facility [Line Items]

Extinguishment of debt

$ 500,000,000

Number of term loans repaid | loan

2

Sustainability-linked bonds | Enbridge Inc.

Line of Credit Facility [Line Items]

Credit facility capacity

$ 1,000,000,000

Term of credit facility

3 years

Commercial paper and credit facility draws

Line of Credit Facility [Line Items]

Long-term debt

10,500,000,000

11,300,000,000

364-Day Extendible Credit Facilities

Line of Credit Facility [Line Items]

Credit facility capacity

$ 5,500,000,000

Term of credit facility

364 days

Term out option period

1 year

10-year Fixed-To-Fixed Subordinated Notes | Subordinated Debt

Line of Credit Facility [Line Items]

Term of credit facility

10 years

Principal amount

$ 750,000,000

Term Loan Maturing In May 2025

Line of Credit Facility [Line Items]

Term of credit facility

5 years

Uncommitted Credit Facilities

Line of Credit Facility [Line Items]

Credit facility capacity

1,300,000,000

1,300,000,000

Unutilized credit facility

$ 689,000,000

$ 854,000,000

Weighted average standby fee (as a percent)

0.10%

0.10%

Revolving Credit Facility

Line of Credit Facility [Line Items]

Line of credit facility, increase (decrease)

$ 640,000,000

Revolving Credit Facility | Sustainability-linked Credit Facility

Line of Credit Facility [Line Items]

Credit facility capacity

$ 1,000,000,000

$ 1,000,000,000

$ 12,700,000,000

$ 12,700,000,000

Term of credit facility

3 years

3 years

Revolving Credit Facility | Syndicated Credit Facility

Line of Credit Facility [Line Items]

Term of credit facility

1 year

Extinguishment of debt

$ 3,000,000,000

Revolving Credit Facility | Five-Year Credit Facilities

Line of Credit Facility [Line Items]

Credit facility capacity

$ 8,000,000,000

Term of credit facility

5 years

Revolving Credit Facility | 364-Day Extendible Credit Facilities

Line of Credit Facility [Line Items]

Credit facility capacity

$ 10,000,000,000

Term of credit facility

364 days

Maturity period

1 year

Term Loan Maturing In May 2025 | Five-Year Credit Facilities

Line of Credit Facility [Line Items]

Credit facility capacity

$ 479,000,000

Term Loan Maturing In May 2025 | Three Year Term Loan | US dollar senior notes

Line of Credit Facility [Line Items]

Credit facility capacity

$ 806,000,000

¥ 84.8

Term of credit facility

3 years

Term Loan Maturing In 2023 | 364-Day Term Loan | US dollar senior notes

Line of Credit Facility [Line Items]

Credit facility capacity

$ 1,900

Term Loan Matured In May 2022 | US dollar senior notes

Line of Credit Facility [Line Items]

Credit facility capacity

$ 499,000,000

¥ 52.5

DEBT - Schedule of Long-term De

DEBT - Schedule of Long-term Debt Issuances (Details) $ in Millions, $ in Millions

12 Months Ended

Dec. 31, 2022 CAD ($)

Dec. 31, 2022 USD ($)

Nov. 30, 2022 CAD ($)

Sep. 30, 2022 USD ($)

Aug. 31, 2022 CAD ($)

Feb. 28, 2022 USD ($)

Jan. 31, 2022 CAD ($)

Oct. 31, 2021

Sep. 30, 2021

Jun. 30, 2021

May 31, 2021

Feb. 28, 2021

Debt Instrument [Line Items]

Principal amount

$ 3,400

$ 3,200

Floating Rate Senior Notes Issued Due February 2024

Debt Instrument [Line Items]

Interest rate (percent)

0.63%

Enbridge Gas Inc. | 4.15% Medium Term Notes Due August 2032

Debt Instrument [Line Items]

Interest rate (percent)

4.15%

Principal amount

$ 325

Enbridge Gas Inc. | 4.55 % Medium Term Notes Due August 2052

Debt Instrument [Line Items]

Interest rate (percent)

4.55%

Principal amount

$ 325

Enbridge Gas Inc. | 2.35% Medium-Term Notes Due September 2031

Debt Instrument [Line Items]

Interest rate (percent)

2.35%

Enbridge Gas Inc. | 3.20% Medium-Term Notes Due September 2051

Debt Instrument [Line Items]

Interest rate (percent)

3.20%

Texas Eastern Transmission, LP | 6.20% Senior Notes due December 2032

Debt Instrument [Line Items]

Interest rate (percent)

6.20%

6.20%

Principal amount

$ 600

Texas Eastern Transmission, LP | 2.50% Senior Notes Due September 2031

Debt Instrument [Line Items]

Interest rate (percent)

2.50%

Enbridge Pipelines Inc. | 2.82% medium-term notes due May 2031

Debt Instrument [Line Items]

Interest rate (percent)

2.82%

Enbridge Pipelines Inc. | 4.20% medium-term notes due May 2051

Debt Instrument [Line Items]

Interest rate (percent)

4.20%

Enbridge Inc. | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Term of fixed rate

30 years

Enbridge Inc. | 5.00 %

Debt Instrument [Line Items]

Interest rate (percent)

5%

Principal amount

$ 750

Enbridge Inc. | Floating Rate Senior Notes Issued Due February 2024

Debt Instrument [Line Items]

Principal amount

$ 600

Enbridge Inc. | 2.15% Senior Notes Due February 2024

Debt Instrument [Line Items]

Interest rate (percent)

2.15%

Principal amount

$ 400

Enbridge Inc. | 2.50% Senior Notes Due February 2025

Debt Instrument [Line Items]

Interest rate (percent)

2.50%

Principal amount

$ 500

Enbridge Inc. | 7.38% Floating Rate Notes Issued January 2083

Debt Instrument [Line Items]

Interest rate (percent)

7.38%

Principal amount

$ 500

Enbridge Inc. | 7.63% Floating Rate Notes Issued January 2083

Debt Instrument [Line Items]

Interest rate (percent)

7.63%

Principal amount

$ 600

Enbridge Inc. | 5.70 % Medium-Term Notes Due November 2027

Debt Instrument [Line Items]

Interest rate (percent)

5.70%

Principal amount

$ 600

Enbridge Inc. | 6.10 % Sustainability-Linked Medium-Term Notes due November 20325

Debt Instrument [Line Items]

Interest rate (percent)

6.10%

Principal amount

$ 900

Enbridge Inc. | 6.51 % Medium-Term Notes Due November 2052

Debt Instrument [Line Items]

Interest rate (percent)

6.51%

Principal amount

$ 500

Enbridge Inc. | 2.50% Sustainability-Linked Senior Notes Due August 2033

Debt Instrument [Line Items]

Interest rate (percent)

2.50%

Enbridge Inc. | 3.40% Senior Notes Due August 2051

Debt Instrument [Line Items]

Interest rate (percent)

3.40%

Enbridge Inc. | 3.10% Sustainability-Linked Medium-Term Notes Due September 2033

Debt Instrument [Line Items]

Interest rate (percent)

3.10%

Enbridge Inc. | 4.10% Medium-Term Notes Due September 2051

Debt Instrument [Line Items]

Interest rate (percent)

4.10%

Enbridge Inc. | 0.55% Senior Term Notes Due October 2023

Debt Instrument [Line Items]

Interest rate (percent)

0.55%

Enbridge Inc. | 1.60% senior notes due October 2026

Debt Instrument [Line Items]

Interest rate (percent)

1.60%

Enbridge Inc. | 3.40% senior notes due August 2051

Debt Instrument [Line Items]

Interest rate (percent)

3.40%

Enbridge Inc. | 4.26% Medium-Term Notes February 2021

Debt Instrument [Line Items]

Interest rate (percent)

426%

Enbridge Inc. | Initial Period | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Term of fixed rate

5 years

Enbridge Inc. | Initial Period | 5.00 % | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

3.54%

Enbridge Inc. | Initial Period | 6.10 % Sustainability-Linked Medium-Term Notes due November 20325 | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Performance target, percent

0.35

Enbridge Inc. | Subsequent period | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Term of fixed rate

10 years

Enbridge Inc. | Subsequent period | 5.00 % | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

4.29%

Enbridge Inc. | Subsequent period | 6.10 % Sustainability-Linked Medium-Term Notes due November 20325

Debt Instrument [Line Items]

Interest rate (percent)

6.10%

6.10%

Enbridge Inc. | US Treasury Rate | Initial Period | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

4.71%

Enbridge Inc. | US Treasury Rate | Initial Period | 7.38% Floating Rate Notes Issued January 2083 | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

3.71%

Enbridge Inc. | US Treasury Rate | Initial Period | 7.63% Floating Rate Notes Issued January 2083 | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

4.42%

Enbridge Inc. | US Treasury Rate | Subsequent period | 7.38% Floating Rate Notes Issued January 2083 | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

3.96%

Enbridge Inc. | US Treasury Rate | Subsequent period | 7.63% Floating Rate Notes Issued January 2083 | Fixed-to-fixed subordinated term notes

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

5.17%

Enbridge Inc. | US Treasury Rate | Subsequent period | 6.10 % Sustainability-Linked Medium-Term Notes due November 20325

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

0.70%

DEBT - Schedule of Long-Term _2

DEBT - Schedule of Long-Term Debt Repayments (Details) $ in Millions, $ in Millions

1 Months Ended

12 Months Ended

Dec. 31, 2022 CAD ($)

Dec. 31, 2022 USD ($)

Nov. 30, 2022 CAD ($)

Oct. 31, 2022 USD ($)

Jul. 31, 2022 USD ($)

Jun. 30, 2022 CAD ($)

Jun. 30, 2022 USD ($)

Apr. 30, 2022 CAD ($)

Feb. 28, 2022 CAD ($)

Feb. 28, 2022 USD ($)

Dec. 31, 2022 CAD ($)

Dec. 31, 2022 USD ($)

Dec. 31, 2021

Oct. 31, 2021

Jun. 30, 2021

May 31, 2021

Mar. 31, 2021

Feb. 28, 2021

Debt Instrument [Line Items]

Extinguishment of debt

$ 1,500

$ 2,000

Enbridge Gas Inc. | 4.85% Medium-Term Notes

Debt Instrument [Line Items]

Interest rate (percent)

4.85%

Extinguishment of debt

$ 125

Enbridge Gas Inc. | 2.76% Medium-Term Notes May 2021

Debt Instrument [Line Items]

Interest rate (percent)

276%

Enbridge Gas Inc. | 4.77% Medium-Term Notes December 2021

Debt Instrument [Line Items]

Interest rate (percent)

477%

Enbridge Pipelines (Southern Lights) L.L.C. | 3.98% Senior Notes Due 2040

Debt Instrument [Line Items]

Interest rate (percent)

3.98%

3.98%

3.98%

3.98%

3.98%

3.98%

Extinguishment of debt

$ 72

$ 72

Enbridge Pipelines (Southern Lights) L.L.C. | 3.98% Senior Notes June and December 2021

Debt Instrument [Line Items]

Interest rate (percent)

398%

398%

Enbridge Pipelines Inc. | 2.93 % Medium-Term Notes

Debt Instrument [Line Items]

Interest rate (percent)

2.93%

Extinguishment of debt

$ 150

Enbridge Southern Lights LP | 4.10 % Senior Notes

Debt Instrument [Line Items]

Interest rate (percent)

4.01%

4.01%

4.01%

4.01%

4.01%

4.01%

Extinguishment of debt

$ 18

$ 18

Enbridge Southern Lights LP | 4.01% Senior Notes June and December 2021

Debt Instrument [Line Items]

Interest rate (percent)

401%

401%

Texas Eastern Transmission, LP | 2.80 % Senior Notes

Debt Instrument [Line Items]

Interest rate (percent)

2.80%

Extinguishment of debt

$ 500

Westcoast Energy Inc. | 3.12% Medium- Term Notes

Debt Instrument [Line Items]

Interest rate (percent)

3.12%

3.12%

3.12%

3.12%

Extinguishment of debt

$ 250

Westcoast Energy Inc. | 3.88% Medium-Term Notes October 2021

Debt Instrument [Line Items]

Interest rate (percent)

388%

Enbridge Energy Partners, L.P. | 4.20% Senior Notes June 2021

Debt Instrument [Line Items]

Interest rate (percent)

420%

Enbridge Inc. | Floating Rate Notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 750

Enbridge Inc. | Floating Rate Notes | LIBOR

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

0.50%

0.50%

Enbridge Inc. | 4.85% Medium-Term Notes

Debt Instrument [Line Items]

Interest rate (percent)

4.85%

4.85%

Extinguishment of debt

$ 200

Enbridge Inc. | 2.90% Senior Notes Due July 2022

Debt Instrument [Line Items]

Interest rate (percent)

2.90%

Extinguishment of debt

$ 700

Enbridge Inc. | 3.19% Medium- Term Notes

Debt Instrument [Line Items]

Interest rate (percent)

3.19%

3.19%

3.19%

3.19%

Extinguishment of debt

$ 350

Enbridge Inc. | 3.19% Medium- Term Notes, Second

Debt Instrument [Line Items]

Interest rate (percent)

3.19%

3.19%

3.19%

3.19%

Extinguishment of debt

$ 450

Enbridge Inc. | 3.16% Medium-Term Notes March 2021

Debt Instrument [Line Items]

Interest rate (percent)

316%

Enbridge Inc. | 4.26% Medium-Term Notes February 2021

Debt Instrument [Line Items]

Interest rate (percent)

426%

Spectra Energy Partners, LP | 4.60% senior notes March 2021

Debt Instrument [Line Items]

Interest rate (percent)

460%

DEBT - Schedule of Interest Exp

DEBT - Schedule of Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
DEBT
Capitalized interest	$ (74)	$ (215)	$ (192)
Total interest expense	3,179	2,655	2,790
Spectra Energy Capital, LLC
DEBT
Amortization of fair value adjustment	(45)	(50)	(54)
Debentures and term notes
DEBT
Interest expense on debt	2,910	2,806	2,873
Commercial paper and credit facility draws
DEBT
Interest expense on debt	$ 388	$ 114	$ 163

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of movements in the Company's ARO
Obligations at beginning of year	$ 502	$ 496
Liabilities incurred	30	0
Liabilities settled	(126)	(67)
Change in estimate and other	51	70
Foreign currency translation adjustment	24	(3)
Accretion expense	7	6
Obligations at end of year	488	502
Accounts payable and other	83	160
Other long-term liabilities	405	342
Asset retirement obligations	$ 488	$ 502
Minimum
Asset Retirement Obligations [Line Items]
Discount rate (as a percent)	1.50%	0.90%
Maximum
Asset Retirement Obligations [Line Items]
Discount rate (as a percent)	9%	9%

NONCONTROLLING INTERESTS (Detai

NONCONTROLLING INTERESTS (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Oct. 05, 2022	Dec. 31, 2021
NONCONTROLLING INTERESTS
Noncontrolling interests	$ 3,511		$ 2,542
Algonquin Gas Transmission, LLC
NONCONTROLLING INTERESTS
Noncontrolling interests	400		377
Enbridge Athabasca Midstream Investor Limited Partnership
NONCONTROLLING INTERESTS
Noncontrolling interests	1,106		0
Maritimes & Northeast Pipeline, L.L.C.
NONCONTROLLING INTERESTS
Noncontrolling interests	582		546
Renewable energy assets
NONCONTROLLING INTERESTS
Noncontrolling interests	1,302		1,503
Westcoast Energy Inc.
NONCONTROLLING INTERESTS
Noncontrolling interests	117		116
Other Non Controlling Interest
NONCONTROLLING INTERESTS
Noncontrolling interests	$ 4		$ 0
Athabasca Regional Oil Sands System | Athabasca Regional Oil Sands System
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners		11.60%

SHARE CAPITAL - Common Shares (

SHARE CAPITAL - Common Shares (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Common Shares
Balance at beginning of period (in shares)	2,026
Share purchases at stated value (in shares)	(3)	0	0
Share purchases at stated value	$ (88)	$ 0	$ 0
Other	$ (4)	$ 0	$ 0
Other ( in shares)	0	0	0
Balance at end of period (in shares)	2,025	2,026
Common Shares
Common Shares
Balance at beginning of period (in shares)	2,026	2,026	2,025
Balance at beginning of period, Amount	$ 64,799	$ 64,768	$ 64,746
Shares issued on exercise of stock options (in shares)	2	0	1
Shares issued on exercise of stock options	$ 53	$ 31	$ 22
Share purchases at stated value	$ (88)	$ 0	$ 0
Balance at end of period (in shares)	2,025	2,026	2,026
Balance at end of period, Amount	$ 64,760	$ 64,799	$ 64,768

SHARE CAPITAL - Preferred Share

SHARE CAPITAL - Preferred Shares (Details) $ / shares in Units, $ / shares in Units, shares in Millions, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) $ / shares shares	Dec. 31, 2022 CAD ($) $ / shares $ / shares shares	Dec. 31, 2021 CAD ($) shares	Dec. 31, 2020 CAD ($) shares	Dec. 31, 2022 $ / shares	Jun. 01, 2022 USD ($)	Mar. 01, 2022 CAD ($)
Preferred Shares
Share Capital
Preferred stock, value, outstanding | $	$ 6,818	$ 6,818	$ 7,747	$ 7,747
Issuance costs | $	$ (135)		$ (155)	$ (155)
Preference Shares, Series A | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	5	5	5	5
Preferred stock, value, outstanding | $	$ 125	$ 125	$ 125	$ 125
Initial Yield (as a percent)	5.50%
Yearly dividend per share (in dollars per share)	$ 1.37500
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series B | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	20	20	18	18
Preferred stock, value, outstanding | $	$ 500	$ 500	$ 457	$ 457
Initial Yield (as a percent)	5.20%
Yearly dividend per share (in dollars per share)	$ 1.30052
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series C1 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	0	0	2	2
Preferred stock, value, outstanding | $	$ 0	$ 0	$ 43	$ 43
Preference Shares, Series C1 | Preferred Shares | US Treasury Rate
Share Capital
Initial yield, spread on variable rate (percent)	2.40%	2.40%
Preference Shares, Series D | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	18	18	18	18
Preferred stock, value, outstanding | $	$ 450	$ 450	$ 450	$ 450
Initial Yield (as a percent)	4.46%
Yearly dividend per share (in dollars per share)	$ 1.11500
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series F | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	20	20	20	20
Preferred stock, value, outstanding | $	$ 500	$ 500	$ 500	$ 500
Initial Yield (as a percent)	4.69%
Yearly dividend per share (in dollars per share)	$ 1.17224
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series H | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	14	14	14	14
Preferred stock, value, outstanding | $	$ 350	$ 350	$ 350	$ 350
Initial Yield (as a percent)	4.38%
Yearly dividend per share (in dollars per share)	$ 1.09400
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Series J Preferred Stock
Share Capital
Preferred stock, redemption amount | $						$ 200
Series J Preferred Stock | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	0	0	8	8
Preferred stock, value, outstanding | $	$ 0	$ 0	$ 199	$ 199
Preference Shares, Series L | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	16	16	16	16
Preferred stock, value, outstanding | $	$ 411	$ 411	$ 411	$ 411
Initial Yield (as a percent)	5.86%
Yearly dividend per share (in dollars per share)		$ 1.46448
Per Share Base Redemption Value (in dollars per shares)					$ 25
Preference Shares, Series N | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	18	18	18	18
Preferred stock, value, outstanding | $	$ 450	$ 450	$ 450	$ 450
Initial Yield (as a percent)	5.09%
Yearly dividend per share (in dollars per share)	$ 1.27152
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series P | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	16	16	16	16
Preferred stock, value, outstanding | $	$ 400	$ 400	$ 400	$ 400
Initial Yield (as a percent)	4.38%
Yearly dividend per share (in dollars per share)	$ 1.09476
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series R | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	16	16	16	16
Preferred stock, value, outstanding | $	$ 400	$ 400	$ 400	$ 400
Initial Yield (as a percent)	4.07%
Yearly dividend per share (in dollars per share)	$ 1.01825
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series 1 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	16	16	16	16
Preferred stock, value, outstanding | $	$ 411	$ 411	$ 411	$ 411
Initial Yield (as a percent)	5.95%
Yearly dividend per share (in dollars per share)		$ 1.48728
Per Share Base Redemption Value (in dollars per shares)					25
Preference Shares, Series 3 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	24	24	24	24
Preferred stock, value, outstanding | $	$ 600	$ 600	$ 600	$ 600
Initial Yield (as a percent)	3.74%
Yearly dividend per share (in dollars per share)	$ 0.93425
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series 5 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	8	8	8	8
Preferred stock, value, outstanding | $	$ 206	$ 206	$ 206	$ 206
Initial Yield (as a percent)	5.38%
Yearly dividend per share (in dollars per share)		$ 1.34383
Per Share Base Redemption Value (in dollars per shares)					$ 25
Preference Shares, Series 7 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	10	10	10	10
Preferred stock, value, outstanding | $	$ 250	$ 250	$ 250	$ 250
Initial Yield (as a percent)	4.45%
Yearly dividend per share (in dollars per share)	$ 1.11224
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series 9 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	11	11	11	11
Preferred stock, value, outstanding | $	$ 275	$ 275	$ 275	$ 275
Initial Yield (as a percent)	4.10%
Yearly dividend per share (in dollars per share)	$ 1.02424
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series 11 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	20	20	20	20
Preferred stock, value, outstanding | $	$ 500	$ 500	$ 500	$ 500
Initial Yield (as a percent)	3.94%
Yearly dividend per share (in dollars per share)	$ 0.98452
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series 13 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	14	14	14	14
Preferred stock, value, outstanding | $	$ 350	$ 350	$ 350	$ 350
Initial Yield (as a percent)	3.04%
Yearly dividend per share (in dollars per share)	$ 0.76076
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Preference Shares, Series 15 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	11	11	11	11
Preferred stock, value, outstanding | $	$ 275	$ 275	$ 275	$ 275
Initial Yield (as a percent)	2.98%
Yearly dividend per share (in dollars per share)	$ 0.74576
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25
Series17 Preferred Stock
Share Capital
Preferred stock, redemption amount | $							$ 750
Series17 Preferred Stock | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	0	0	30	30
Preferred stock, value, outstanding | $	$ 0	$ 0	$ 750	$ 750
Preference Shares, Series 19 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares	20	20	20	20
Preferred stock, value, outstanding | $	$ 500	$ 500	$ 500	$ 500
Initial Yield (as a percent)	4.90%
Yearly dividend per share (in dollars per share)	$ 1.22500
Per Share Base Redemption Value (in dollars per shares)	$ 25	$ 25

SHARE CAPITAL - Plans (Details)

SHARE CAPITAL - Plans (Details)	Dec. 31, 2022
Equity [Abstract]
Minimum outstanding common shares required to be acquired to exercise the Shareholder Rights Plan (as a percent)	20%
Discount to the market price available to each rights holder, other than the acquiring person and related parties, under the Shareholder Rights Plan (as a percent)	50%

STOCK OPTION AND STOCK UNIT P_3

STOCK OPTION AND STOCK UNIT PLANS - Stock Option Activity (Details) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) compensationPlan $ / shares shares	Dec. 31, 2021 CAD ($) $ / shares shares	Dec. 31, 2020 CAD ($)
STOCK OPTION AND STOCK UNIT PLANS
Number of long-term incentive compensation plans | compensationPlan	3
Compensation expense	$ 260	$ 157	$ 145
INCENTIVE STOCK OPTIONS
STOCK OPTION AND STOCK UNIT PLANS
Compensation expense	$ 15	$ 16	24
Vesting period	4 years
Expiration term	10 years
Number
Options outstanding at beginning of year (in shares) | shares	34,017
Options granted (in shares) | shares	3,430
Options exercised (in shares) | shares	(8,684)
Options cancelled or expired (in shares) | shares	(1,139)
Options outstanding at end of year (in shares) | shares	27,624	34,017
Options vested at end of year (in shares) | shares	17,631
Weighted Average Exercise Price
Options outstanding at beginning of year (in dollars per share) | $ / shares	$ 49.28
Options granted (in dollars per share) | $ / shares	49.58
Options exercised (in dollars per share) | $ / shares	44.55
Options cancelled or expired (in dollars per share) | $ / shares	51.32
Options outstanding at end of year (in dollars per share) | $ / shares	48.46	$ 49.28
Options vested at end of year (in dollars per share) | $ / shares	$ 49.20
Weighted Average Remaining Contractual Life (years)
Options outstanding at end of year	5 years 8 months 12 days
Options vested at end of year	4 years 4 months 24 days
Aggregate Intrinsic Value
Options outstanding at end of year	$ 133
Options vested at end of year	84
Stock options, additional disclosures
Total intrinsic value of awards exercised	66	$ 24	13
Cash received on exercise of awards	3	2	4
Total fair value of options vested	$ 21	$ 25	$ 30

STOCK OPTION AND STOCK UNIT P_4

STOCK OPTION AND STOCK UNIT PLANS - Weighted Average Assumptions (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) $ / shares	Dec. 31, 2021 CAD ($) $ / shares	Dec. 31, 2020 CAD ($) $ / shares	Dec. 31, 2022 $ / shares	Dec. 31, 2021 $ / shares	Dec. 31, 2020 $ / shares
Weighted average assumptions used to determine the fair value of options
Compensation expense | $	$ 260	$ 157	$ 145
INCENTIVE STOCK OPTIONS
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares	$ 5.07	$ 4.10	$ 4.01
Expected option term (in years)	6 years	6 years	6 years
Expected volatility (as a percent)	21.90%	25.50%	18.30%
Expected dividend yield (as a percent)	6.50%	7.60%	5.90%
Risk-free interest rate (as a percent)	1.80%	0.70%	1.30%
Expected option term - historical exercise practice	6 years
Compensation expense | $	$ 15	$ 16	$ 24
Unrecognized compensation cost related to non-vested share-based compensation arrangements granted | $	$ 12
Weighted average period over which compensation cost is expected to be recognized	2 years
INCENTIVE STOCK OPTIONS | Canadian Employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares	$ 4.78	$ 3.91	$ 3.75
INCENTIVE STOCK OPTIONS | United States Employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares				$ 4.62	$ 3.65	$ 3.62
INCENTIVE STOCK OPTIONS | Retirement-Eligible Employees
Weighted average assumptions used to determine the fair value of options
Expected option term (in years)	5 years

STOCK OPTION AND STOCK UNIT P_5

STOCK OPTION AND STOCK UNIT PLANS - PSUs and RSUs (Details) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) shares	Dec. 31, 2021 CAD ($) shares	Dec. 31, 2020 CAD ($)
Stock units, additional disclosures
Compensation expense | $	$ 260	$ 157	$ 145
Performance Stock Units (PSUs)
STOCK OPTION AND STOCK UNIT PLANS
Performance / maturity period	3 years
Period prior to the maturity of the grant for which weighted average share price is used to calculate cash awards	20 days
Performance multiplier	1.25	1.25	2
Number
Units outstanding at beginning of year (in shares)	3,429
Units granted (in shares)	1,467
Units cancelled (in shares)	(131)
Units matured (in shares)	(1,700)
Dividend reinvestment (in shares)	184
Units outstanding at end of year (in shares)	3,249	3,429
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	1 year 1 month 6 days
Aggregate Intrinsic Value
Units outstanding at end of year | $	$ 261
Stock units, additional disclosures
Total amount paid | $	90	$ 70	$ 14
Compensation expense | $	169	$ 56	76
Unrecognized compensation expense related to non-vested units granted | $	$ 72
Weighted average period over which compensation cost is expected to be recognized	2 years
Restricted Stock Units (RSU)
STOCK OPTION AND STOCK UNIT PLANS
Performance / maturity period	3 years
Period prior to the maturity of the grant for which weighted average share price is used to calculate cash awards	20 days
Number
Units outstanding at beginning of year (in shares)	2,705
Units granted (in shares)	1,400
Units cancelled (in shares)	(134)
Units matured (in shares)	(602)
Dividend reinvestment (in shares)	196
Units outstanding at end of year (in shares)	3,565	2,705
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	1 year
Aggregate Intrinsic Value
Units outstanding at end of year | $	$ 185
Stock units, additional disclosures
Total amount paid | $	32	$ 72	27
Compensation expense | $	76	$ 85	$ 44
Unrecognized compensation expense related to non-vested units granted | $	$ 35
Weighted average period over which compensation cost is expected to be recognized	2 years
Minimum | Performance Stock Units (PSUs)
STOCK OPTION AND STOCK UNIT PLANS
Performance multiplier	0
Maximum | Performance Stock Units (PSUs)
STOCK OPTION AND STOCK UNIT PLANS
Performance multiplier	2

COMPONENTS OF ACCUMULATED OTH_3

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Components of accumulated other comprehensive loss
Balance at beginning of year	$ 63,368	$ 64,363
Other comprehensive income/(loss) retained in AOCI	4,816	298	$ (1,522)
Changes in AOCI
Other	16	0
Other comprehensive loss/(income) reclassified to earnings	5,004	564	(1,249)
Income tax on amounts retained in AOCI	(349)	(187)	182
Income tax on amounts reclassified to earnings	(39)	(72)	(62)
Tax impact	(388)	(259)	120
Balance at end of year	63,398	63,368	64,363
Interest rate contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	186	296	253
Commodity contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs		1
Forward exchange contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	(4)	5	5
Other contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	4	2	(2)
Equity investment disposal
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs		(66)
Cash Flow Hedges
Components of accumulated other comprehensive loss
Balance at beginning of year	(897)	(1,326)	(1,073)
Other comprehensive income/(loss) retained in AOCI	1,125	238	(591)
Changes in AOCI
Other	0	17
Other comprehensive loss/(income) reclassified to earnings	1,311	559	(335)
Income tax on amounts retained in AOCI	(250)	(61)	140
Income tax on amounts reclassified to earnings	(43)	(69)	(58)
Tax impact	(293)	(130)	82
Balance at end of year	121	(897)	(1,326)
Cash Flow Hedges | Interest rate contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	186	296	253
Cash Flow Hedges | Commodity contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs		1
Cash Flow Hedges | Forward exchange contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	(4)	5	5
Cash Flow Hedges | Other contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	4	2	(2)
Cash Flow Hedges | Equity investment disposal
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs		0
Excluded Components of Fair Value Hedges
Components of accumulated other comprehensive loss
Balance at beginning of year	0	5	0
Other comprehensive income/(loss) retained in AOCI	(35)	(5)	5
Changes in AOCI
Other comprehensive loss/(income) reclassified to earnings	(35)	(5)	5
Income tax on amounts retained in AOCI	0	0	0
Income tax on amounts reclassified to earnings	0	0	0
Tax impact	0	0	0
Balance at end of year	(35)	0	5
Net Investment Hedges
Components of accumulated other comprehensive loss
Balance at beginning of year	(166)	(215)	(317)
Other comprehensive income/(loss) retained in AOCI	(971)	49	115
Changes in AOCI
Other comprehensive loss/(income) reclassified to earnings	(971)	49	115
Income tax on amounts retained in AOCI	0	0	(13)
Income tax on amounts reclassified to earnings	0	0
Tax impact	0	0	(13)
Balance at end of year	(1,137)	(166)	(215)
Cumulative Translation Adjustment
Components of accumulated other comprehensive loss
Balance at beginning of year	56	568	1,396
Other comprehensive income/(loss) retained in AOCI	4,292	(492)	(828)
Changes in AOCI
Other	0	(20)
Other comprehensive loss/(income) reclassified to earnings	4,292	(512)	(828)
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings	0	0
Tax impact	0	0
Balance at end of year	4,348	56	568
Equity Investees
Components of accumulated other comprehensive loss
Balance at beginning of year	(5)	66	67
Other comprehensive income/(loss) retained in AOCI	(6)	(12)	(2)
Changes in AOCI
Other	16	3
Other comprehensive loss/(income) reclassified to earnings	10	(75)	(2)
Income tax on amounts retained in AOCI	0	0	1
Income tax on amounts reclassified to earnings	0	4
Tax impact	0	4	1
Balance at end of year	5	(5)	66
Equity Investees | Equity investment disposal
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs		66
Pension and OPEB Adjustment
Components of accumulated other comprehensive loss
Balance at beginning of year	(84)	(499)	(345)
Other comprehensive income/(loss) retained in AOCI	411	520	(221)
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	(14)	28	17
Other comprehensive loss/(income) reclassified to earnings	397	548	(204)
Income tax on amounts retained in AOCI	(99)	(126)	54
Income tax on amounts reclassified to earnings	4	(7)	(4)
Tax impact	(95)	(133)	50
Balance at end of year	218	(84)	(499)
Total
Components of accumulated other comprehensive loss
Balance at beginning of year	(1,096)	(1,401)	(272)
Changes in AOCI
Balance at end of year	$ 3,520	$ (1,096)	$ (1,401)

RISK MANAGEMENT AND FINANCIAL_3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Total Derivative Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	$ (546)	$ (359)
Total Net Derivative Instruments	(546)	(359)
Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(1,476)	(202)
Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	816	(45)
Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	114	(112)
Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	1,015	529
Derivative assets, Amounts Available for Offset	(223)	(170)
Derivative assets, Total Net Derivative Instruments	$ 792	$ 359
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Accounts receivable and other (Note 9)	Accounts receivable and other (Note 9)
Accounts receivable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	$ 366	$ 465
Accounts receivable and other | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	649	64
Accounts receivable and other | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	627	360
Derivative assets, Amounts Available for Offset	(163)	(75)
Derivative assets, Total Net Derivative Instruments	$ 464	$ 285
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Deferred amounts and other assets	Deferred amounts and other assets
Deferred amounts and other assets | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	$ 216	$ 272
Deferred amounts and other assets | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	255	88
Deferred amounts and other assets | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	156	0
Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(898)	(717)
Derivative liabilities, Amounts Available for Offset	223	170
Derivative liabilities, Total Net Derivative Instruments	$ (675)	$ (547)
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Accounts payable and other (Note 17)	Accounts payable and other (Note 17)
Accounts payable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	$ (808)	$ (426)
Accounts payable and other | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(48)	(179)
Accounts payable and other | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(42)	(112)
Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1,290)	(531)
Derivative liabilities, Amounts Available for Offset	163	75
Derivative liabilities, Total Net Derivative Instruments	$ (1,127)	$ (456)
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Other long-term liabilities	Other long-term liabilities
Other long-term liabilities | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	$ (1,250)	$ (513)
Other long-term liabilities | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(40)	(18)
Other long-term liabilities | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(1,327)	(227)
Total Net Derivative Instruments	(1,327)	(227)
Foreign exchange contracts | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(1,441)	(100)
Foreign exchange contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	0	(15)
Foreign exchange contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	114	(112)
Foreign exchange contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	46	259
Derivative assets, Amounts Available for Offset	(41)	(41)
Derivative assets, Total Net Derivative Instruments	5	218
Foreign exchange contracts | Accounts receivable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	46	259
Foreign exchange contracts | Accounts receivable and other | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Accounts receivable and other | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	309	240
Derivative assets, Amounts Available for Offset	(138)	(61)
Derivative assets, Total Net Derivative Instruments	171	179
Foreign exchange contracts | Deferred amounts and other assets | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	153	240
Foreign exchange contracts | Deferred amounts and other assets | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Deferred amounts and other assets | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	156	0
Foreign exchange contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(566)	(303)
Derivative liabilities, Amounts Available for Offset	41	41
Derivative liabilities, Total Net Derivative Instruments	(525)	(262)
Foreign exchange contracts | Accounts payable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(524)	(176)
Foreign exchange contracts | Accounts payable and other | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(15)
Foreign exchange contracts | Accounts payable and other | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(42)	(112)
Foreign exchange contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1,116)	(423)
Derivative liabilities, Amounts Available for Offset	138	61
Derivative liabilities, Total Net Derivative Instruments	(978)	(362)
Foreign exchange contracts | Other long-term liabilities | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1,116)	(423)
Foreign exchange contracts | Other long-term liabilities | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Other long-term liabilities | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(4)
Total net financial asset/(liability)	910	(22)
Derivative liabilities, Amounts Available for Offset	0
Total Net Derivative Instruments	910	(22)
Interest rate contracts | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1)
Total net financial asset/(liability)	10	(23)
Interest rate contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(3)
Total net financial asset/(liability)	900	1
Interest rate contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0
Total net financial asset/(liability)	0	0
Interest rate contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	660	64
Derivative assets, Amounts Available for Offset	0	0
Derivative assets, Total Net Derivative Instruments	660	64
Interest rate contracts | Accounts receivable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	11	0
Interest rate contracts | Accounts receivable and other | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	649	64
Interest rate contracts | Accounts receivable and other | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	254	88
Derivative assets, Amounts Available for Offset	0	(1)
Derivative assets, Total Net Derivative Instruments	254	87
Interest rate contracts | Deferred amounts and other assets | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Deferred amounts and other assets | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	254	88
Interest rate contracts | Deferred amounts and other assets | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(150)
Derivative liabilities, Amounts Available for Offset		0
Derivative liabilities, Total Net Derivative Instruments		(150)
Interest rate contracts | Accounts payable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		0
Interest rate contracts | Accounts payable and other | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(150)
Interest rate contracts | Accounts payable and other | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		0
Interest rate contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(24)
Derivative liabilities, Amounts Available for Offset		1
Derivative liabilities, Total Net Derivative Instruments	(4)	(23)
Interest rate contracts | Other long-term liabilities | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(23)
Interest rate contracts | Other long-term liabilities | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(1)
Interest rate contracts | Other long-term liabilities | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		0
Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(139)	(115)
Total Net Derivative Instruments	(139)	(115)
Commodity contracts | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(54)	(84)
Commodity contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(85)	(31)
Commodity contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	0	0
Commodity contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	302	204
Derivative assets, Amounts Available for Offset	(182)	(129)
Derivative assets, Total Net Derivative Instruments	120	75
Commodity contracts | Accounts receivable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	302	204
Commodity contracts | Accounts receivable and other | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Accounts receivable and other | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	61	29
Derivative assets, Amounts Available for Offset	(25)	(13)
Derivative assets, Total Net Derivative Instruments	36	16
Commodity contracts | Deferred amounts and other assets | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	61	29
Commodity contracts | Deferred amounts and other assets | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Deferred amounts and other assets | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(332)	(264)
Derivative liabilities, Amounts Available for Offset	182	129
Derivative liabilities, Total Net Derivative Instruments	(150)	(135)
Commodity contracts | Accounts payable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(284)	(250)
Commodity contracts | Accounts payable and other | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(48)	(14)
Commodity contracts | Accounts payable and other | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(170)	(84)
Derivative liabilities, Amounts Available for Offset	25	13
Derivative liabilities, Total Net Derivative Instruments	(145)	(71)
Commodity contracts | Other long-term liabilities | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(133)	(67)
Commodity contracts | Other long-term liabilities | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(37)	(17)
Commodity contracts | Other long-term liabilities | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Other contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	10	5
Total Net Derivative Instruments	10	5
Other contracts | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	9	5
Other contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	1	0
Other contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	0	0
Other contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	7	2
Derivative assets, Amounts Available for Offset	0	0
Derivative assets, Total Net Derivative Instruments	7	2
Other contracts | Accounts receivable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	7	2
Other contracts | Accounts receivable and other | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Accounts receivable and other | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	3	3
Derivative assets, Amounts Available for Offset	0	0
Derivative assets, Total Net Derivative Instruments	3	3
Other contracts | Deferred amounts and other assets | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	2	3
Other contracts | Deferred amounts and other assets | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	1	0
Other contracts | Deferred amounts and other assets | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	$ 0	$ 0

RISK MANAGEMENT AND FINANCIAL_4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional Principal or Quantity Information (Details) € in Millions, ¥ in Millions, £ in Millions, MWh in Millions, MMBbls in Millions, Bcf in Millions, $ in Millions, $ in Millions	Dec. 31, 2022 USD ($) MWh MMBbls Bcf	Dec. 31, 2022 GBP (£) MWh MMBbls Bcf	Dec. 31, 2022 EUR (€) MWh MMBbls Bcf	Dec. 31, 2022 JPY (¥) MWh MMBbls Bcf	Dec. 31, 2022 CAD ($) MWh MMBbls Bcf	Dec. 31, 2021 USD ($) MWh MMBbls Bcf	Dec. 31, 2021 GBP (£) MWh MMBbls Bcf	Dec. 31, 2021 EUR (€) MWh MMBbls Bcf	Dec. 31, 2021 JPY (¥) MWh MMBbls Bcf	Dec. 31, 2021 CAD ($) MWh MMBbls Bcf
Foreign exchange contracts - United States dollar or GBP or Japanese yen forwards - purchase
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023	$ 655			¥ 0
2024	1,000			0
2025	500			84,800
2026	0			0
2027	0			0
Thereafter	0			0
Total notional principal	2,155			¥ 84,800		$ 2,508			¥ 72,500
Foreign exchange contracts - United States dollar or GBP forwards - sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023	8,297	£ 29	€ 92
2024	6,386	30	91
2025	4,613	30	86
2026	4,121	28	85
2027	2,837	32	81
Thereafter	1,356	0	262
Total notional principal	$ 27,610	£ 149	€ 697			$ 25,427	£ 177	€ 801
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023					$ 8,698
2024					538
2025					30
2026					26
2027					25
Thereafter					39
Total notional principal					9,356					$ 597
Interest rate contract - long term debt - Pay Fixed Rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023					5,496
2024					1,766
2025					589
2026					0
2027					0
Thereafter					0
Total notional principal					7,851					5,279
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2023					37
2024					31
2025					12
2026					0
2027					0
Thereafter					0
Total notional principal					$ 80					$ 67
Commodity contracts | Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2022 notional quantity (in bcf, bbl or mbbl) | Bcf	52	52	52	52	52
2023 notional quantity (in bcf, bbl or mbbl) | Bcf	25	25	25	25	25
2024 notional quantity (in bcf, bbl or mbbl) | Bcf	15	15	15	15	15
2025 notional quantity (in bcf, bbl or mbbl) | Bcf	1	1	1	1	1
2026 notional quantity (in bcf, bbl or mbbl) | Bcf	0	0	0	0	0
Thereafter notional quantity (in bcf, bbl or mbbl) | Bcf	0	0	0	0	0
Total notional quantity (in bcf, bbl or mbbl) | Bcf	93	93	93	93	93	199	199	199	199	199
Commodity contracts | Crude
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2022 notional quantity (in bcf, bbl or mbbl) | MMBbls	16	16	16	16	16
2023 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2024 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2025 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2026 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
Thereafter notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
Total notional quantity (in bcf, bbl or mbbl) | MMBbls	16	16	16	16	16	12	12	12	12	12
Commodity contracts | Power | Net sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2022 notional quantity (MW/H) | MWh	26	26	26	26	26
2023 notional quantity (MW/H) | MWh	(25)	(25)	(25)	(25)	(25)
2024 notional quantity (MW/H) | MWh	(44)	(44)	(44)	(44)	(44)
2025 notional quantity (MW/H) | MWh	0	0	0	0	0
2026 notional quantity (MW/H) | MWh	0	0	0	0	0
Thereafter notional quantity (MW/H) | MWh	0	0	0	0	0
Total notional quantity (MW/H) | MWh	(14)	(14)	(14)	(14)	(14)	(43)	(43)	(43)	(43)	(43)

RISK MANAGEMENT AND FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Effects on Earnings and Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	$ 1,062	$ 191	$ (579)
Amount (gain)/loss reclassified from AOCI to earnings	$ 203	304	256
Period to hedge exposures to the variability of cash flows for all forecasted transactions	36 months
Realized loss on derivative	$ (431)	59	265
Unrealized gain (loss) on derivatives	(1,280)	173	756
Cash flow hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Estimated gain of AOCI related to cash flow hedges reclassified to earnings in the next 12 months	67
Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	13	5	5
Foreign exchange contracts | Cash flow hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	3	(29)	(1)
Foreign exchange contracts | Fair value hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(35)	(5)	5
Foreign exchange contracts | Net investment hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	0	0	13
Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	186	296	253
Interest rate contracts | Cash flow hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	1,151	252	(595)
Interest rate contracts | Fair value hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain on derivative	262	8
Unrealized loss on hedged item	(254)	(15)
Realized loss on derivative	(110)	(41)
Realized gain on hedged item	85	45
Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	0	1	0
Commodity contracts | Cash flow hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(53)	(28)	2
Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	4	2	(2)
Other contracts | Cash flow hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(4)	1	(3)
Non- Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(1,280)	173	756
Non- Qualifying Derivative Instruments | Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(1,344)	92	902
Non- Qualifying Derivative Instruments | Foreign exchange contracts | Transportation and other services
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(238)	98	533
Non- Qualifying Derivative Instruments | Foreign exchange contracts | Other income/(expense)
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(1,106)	(6)	369
Non- Qualifying Derivative Instruments | Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	10	2	(25)
Non- Qualifying Derivative Instruments | Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	50	71	(114)
Non- Qualifying Derivative Instruments | Commodity contracts | Transportation and other services
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	13	9	(2)
Non- Qualifying Derivative Instruments | Commodity contracts | Commodity sales
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	89	160	(321)
Non- Qualifying Derivative Instruments | Commodity contracts | Commodity costs
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(102)	(105)	207
Non- Qualifying Derivative Instruments | Commodity contracts | Operating and administrative expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	50	7	2
Non- Qualifying Derivative Instruments | Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	$ 4	$ 8	$ (7)

RISK MANAGEMENT AND FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Liquidity and Credit Risk (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
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
Cash collateral	$ 0	$ 0
Policy limit increase (percent)	30%
Period after which receivables are classified as past due	30 days
Interest Rate Swaption
LIQUIDITY RISK AND CREDIT RISK
Average swap rate (as a percent)	4%
Interest rate contracts - long-term borrowings
LIQUIDITY RISK AND CREDIT RISK
Average swap rate (as a percent)	2.20%
Derivative Instruments
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 1,584,000,000	887,000,000
Derivative Instruments | Canadian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	644,000,000	424,000,000
Derivative Instruments | US financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	277,000,000	130,000,000
Derivative Instruments | European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	334,000,000	181,000,000
Derivative Instruments | Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	224,000,000	30,000,000
Derivative Instruments | Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 105,000,000	$ 122,000,000

RISK MANAGEMENT AND FINANCIAL_7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Derivatives (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	$ 1,015	$ 529
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Deferred amounts and other assets	Deferred amounts and other assets
Current derivative liabilities	$ (898)	$ (717)
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other long-term liabilities	Other long-term liabilities
Total net financial asset/(liability)	$ (546)	$ (359)
Foreign exchange contracts
Fair Value of Derivatives
Total net financial asset/(liability)	(1,327)	(227)
Interest rate contracts
Fair Value of Derivatives
Total net financial asset/(liability)	910	(22)
Commodity contracts
Fair Value of Derivatives
Total net financial asset/(liability)	(139)	(115)
Other contracts
Fair Value of Derivatives
Total net financial asset/(liability)	10	5
Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	1,015	529
Long-term derivative assets	627	360
Current derivative liabilities	(898)	(717)
Long-term derivative liabilities	(1,290)	(531)
Total net financial asset/(liability)	(546)	(359)
Fair Value | Foreign exchange contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	46	259
Long-term derivative assets	309	240
Current derivative liabilities	(566)	(303)
Long-term derivative liabilities	(1,116)	(423)
Total net financial asset/(liability)	(1,327)	(227)
Fair Value | Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	660	64
Long-term derivative assets	254	88
Current derivative liabilities		(150)
Long-term derivative liabilities	(4)	(24)
Total net financial asset/(liability)	910	(22)
Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	302	204
Long-term derivative assets	61	29
Current derivative liabilities	(332)	(264)
Long-term derivative liabilities	(170)	(84)
Total net financial asset/(liability)	(139)	(115)
Fair Value | Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	7	2
Long-term derivative assets	3	3
Total net financial asset/(liability)	10	5
Level 1 | Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	65	38
Long-term derivative assets	0	0
Current derivative liabilities	(60)	(52)
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	5	(14)
Level 1 | Fair Value | Foreign exchange contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	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 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	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 | Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	65	38
Long-term derivative assets	0	0
Current derivative liabilities	(60)	(52)
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	5	(14)
Level 1 | Fair Value | Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	0	0
Long-term derivative assets	0	0
Total net financial asset/(liability)	0	0
Level 2 | Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	803	396
Long-term derivative assets	583	352
Current derivative liabilities	(643)	(519)
Long-term derivative liabilities	(1,158)	(466)
Total net financial asset/(liability)	(415)	(237)
Level 2 | Fair Value | Foreign exchange contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	46	259
Long-term derivative assets	309	240
Current derivative liabilities	(566)	(303)
Long-term derivative liabilities	(1,116)	(423)
Total net financial asset/(liability)	(1,327)	(227)
Level 2 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	660	64
Long-term derivative assets	254	88
Current derivative liabilities		(150)
Long-term derivative liabilities	(4)	(24)
Total net financial asset/(liability)	910	(22)
Level 2 | Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	90	71
Long-term derivative assets	17	21
Current derivative liabilities	(77)	(66)
Long-term derivative liabilities	(38)	(19)
Total net financial asset/(liability)	(8)	7
Level 2 | Fair Value | Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	7	2
Long-term derivative assets	3	3
Total net financial asset/(liability)	10	5
Level 3
Fair Value of Derivatives
Total net financial asset/(liability)	(136)
Level 3 | Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	147	95
Long-term derivative assets	44	8
Current derivative liabilities	(195)	(146)
Long-term derivative liabilities	(132)	(65)
Total net financial asset/(liability)	(136)	(108)
Level 3 | Fair Value | Foreign exchange contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	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 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	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 | Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	147	95
Long-term derivative assets	44	8
Current derivative liabilities	(195)	(146)
Long-term derivative liabilities	(132)	(65)
Total net financial asset/(liability)	(136)	(108)
Level 3 | Fair Value | Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets (Note 24)	0	0
Long-term derivative assets	0	0
Total net financial asset/(liability)	$ 0	$ 0

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Level 3 Inputs (Details) $ in Millions	Dec. 31, 2022 CAD ($) $ / MillionsofBTU-MMBTU $ / bbl $ / MWh	Dec. 31, 2021 CAD ($)
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (546)	$ (359)
Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(546)	(359)
Level 3
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(136)
Level 3 | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (136)	$ (108)
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 | $ / MillionsofBTU-MMBTU	4.57
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 | $ / MillionsofBTU-MMBTU	34.56
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 | $ / MillionsofBTU-MMBTU	6.25
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 | $ / bbl	71.10
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 | $ / bbl	105.22
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 | $ / bbl	83.26
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 | $ / MWh	36.63
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 | $ / MWh	364
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 | $ / MWh	103.30
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 | $ / MillionsofBTU-MMBTU	1.67
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 | $ / MillionsofBTU-MMBTU	33.89
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 | $ / MillionsofBTU-MMBTU	6
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 | $ / bbl	64.43
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 | $ / 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 | $ / bbl	86.25
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 | $ / MWh	30.49
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 | $ / MWh	183.88
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 | $ / MWh	72.48
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Natural gas
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (35)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Crude
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(4)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Power
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(71)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | Natural gas
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(41)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | Crude
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(2)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | Power
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ 17

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Changes in Level 3 (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Changes in net fair value of derivative assets and liabilities classified as Level 3
Level 3 net derivative liability at beginning of period	$ (108)	$ (191)
Total gain/(loss)
Included in earnings	$ 6	$ (39)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Other Comprehensive Income or Comprehensive Income [Extensible Enumeration]	Excluded components of fair value hedges	Excluded components of fair value hedges
Included in OCI	$ (54)	$ (29)
Settlements	20	151
Level 3 net derivative liability at end of period	$ (136)	$ (108)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues (Note 4)	Revenues (Note 4)

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Other Financial Instruments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Fair Value of Other Financial Instruments
Equity investments at carrying value	$ 102	$ 52
Long-term debt	73,500	82,000
Foreign exchange contracts
Fair Value of Other Financial Instruments
Amount of unrealized gain/(loss) recognized in OCI	0	0
Realized gain on AOCI	0	0
Equity Funds And Debt Securities
Fair Value of Other Financial Instruments
Unrealized gain (loss) on investments	(26)	(12)
Level 1 | Debt Securities
Fair Value of Other Financial Instruments
Fair value of investments	145	14
Level 2 | Debt Securities
Fair Value of Other Financial Instruments
Fair value of investments	488	290
Net investment hedges
Fair Value of Other Financial Instruments
Unrealized foreign exchange gain (loss) on translation of United States dollar denominated debt	(954)	49
Realized loss associated with the settlement of foreign exchange forward contracts	21	0
Carrying value
Fair Value of Other Financial Instruments
Long-term debt	79,300	74,400
Long-term loans receivable from affiliates	752	954
Fair Value
Fair Value of Other Financial Instruments
Fair value note receivable	$ 752	$ 954

INCOME TAXES - Rate Reconciliat

INCOME TAXES - Rate Reconciliation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
INCOME TAX RATE RECONCILIATION
Earnings before income taxes	$ 4,542	$ 7,729	$ 4,190
Canadian federal statutory income tax rate	15%	15%	15%
Expected federal taxes at statutory rate	$ 681	$ 1,159	$ 629
Increase/(decrease) resulting from:
Provincial and state income taxes	108	228	288
Foreign and other statutory rate differentials	295	134	(53)
Effects of rate-regulated accounting	(122)	(139)	(145)
Foreign allowable interest deductions	0	0	(4)
Part VI.1 tax, net of federal Part I deduction	76	73	76
US Minimum Tax	107	0	44
Non-taxable portion of gain on sale of investment	0	(23)	0
Valuation allowance	6	5	(6)
Accounting impairment of non-deductible goodwill	370	0	0
Noncontrolling interests	9	(17)	(8)
Other	74	(5)	(47)
Income tax expense	$ 1,604	$ 1,415	$ 774
Effective income tax rate (as a percent)	35.30%	18.30%	18.50%

INCOME TAXES - Components (Deta

INCOME TAXES - Components (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings/(loss) before income taxes and discontinued operations
Earnings before income taxes	$ 4,542	$ 7,729	$ 4,190
Current income taxes
Total current income taxes	647	324	327
Deferred income taxes
Total deferred income taxes	957	1,091	447
Income tax expense	1,604	1,415	774
Canada
Earnings/(loss) before income taxes and discontinued operations
Domestic	583	3,399	2,789
Current income taxes
Domestic	360	162	165
Deferred income taxes
Domestic	(358)	344	378
US
Earnings/(loss) before income taxes and discontinued operations
Foreign	2,865	3,336	407
Current income taxes
Foreign	201	80	64
Deferred income taxes
Foreign	1,309	741	66
Other
Earnings/(loss) before income taxes and discontinued operations
Foreign	1,094	994	994
Current income taxes
Foreign	86	82	98
Deferred income taxes
Foreign	$ 6	$ 6	$ 3

INCOME TAXES - Deferred Income

INCOME TAXES - Deferred Income Taxes (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred income tax liabilities
Property, plant and equipment	$ (9,096)	$ (8,721)
Investments	(7,099)	(6,097)
Regulatory assets	(1,291)	(1,245)
Pension and OPEB plans	(30)	0
Other	(46)	(208)
Total deferred income tax liabilities	(17,562)	(16,271)
Deferred income tax assets
Financial instruments	456	315
Pension and OPEB plans	0	110
Loss carryforwards	2,259	3,081
Other	1,753	1,648
Total deferred income tax assets	4,468	5,154
Less valuation allowance	(215)	(84)
Total deferred income tax assets, net	4,253	5,070
Net deferred income tax liabilities	(13,309)	(11,201)
Deferred income taxes	472	488
Total deferred income tax liabilities	(13,781)	(11,689)
Operating loss carryforwards that do not expire	7,900	7,500
Foreign subsidiaries' undistributed earnings on which deferred income taxes has not been provided	8,000	4,300
Canada
Deferred income tax assets
Benefit of unused tax loss carryforwards recognized	2,100	1,900
US
Deferred income tax assets
Benefit of unused tax loss carryforwards recognized	8,100	11,000
Operating loss carryforwards that expire	$ 200	$ 3,500

INCOME TAXES - Unrecognized Tax

INCOME TAXES - Unrecognized Tax Benefits (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
UNRECOGNIZED TAX BENEFITS
Unrecognized tax benefits at beginning of year	$ 76	$ 121
Gross increases for tax positions of current year	0	1
Gross decreases for tax positions of prior year	(17)	(26)
Change in translation of foreign currency	1	(1)
Lapses of statute of limitations	(5)	(19)
Unrecognized tax benefits at end of year	55	76
Interest and penalties expense (recovery) related to unrecognized tax benefits	1	(5)
Accrued interest and penalties related to unrecognized tax benefits	$ 13	$ 12

PENSION AND OTHER POSTRETIREM_3

PENSION AND OTHER POSTRETIREMENT BENEFITS - Benefit Obligation, Plan Assets and Funded Status (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Presented as follows:
Accumulated benefit obligation		$ 1,100
Canada | Pension
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	$ 4,600	4,855
Service cost	131	139	$ 148
Interest cost	127	101	128
Participant contributions	29	28
Actuarial gain	(1,069)	(329)
Benefits paid	(187)	(194)
Foreign currency exchange rate changes	0	0
Other	(1)	0
Accumulated postretirement benefit obligation at end of year	3,630	4,600	4,855
Change in plan assets
Fair value of plan assets at beginning of year	4,536	4,077
Actual return/(loss) on plan assets	(235)	505
Employer contributions	91	120
Participant contributions	29	28
Benefits paid	(187)	(194)
Foreign currency exchange rate changes	0	0
Other	0	0
Fair value of plan assets at end of year	4,234	4,536	4,077
Overfunded/(underfunded) status at end of year	604	(64)
Presented as follows:
Deferred amounts and other assets	764	250
Accounts payable and other	(9)	(9)
Other long-term liabilities	(151)	(305)
Amount recognized in balance sheet	604	(64)
Accumulated benefit obligation	3,400	4,300
Canada | Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	10	13
Canada | OPEB
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	274	321
Service cost	4	6	5
Interest cost	7	7	8
Participant contributions	0	0
Actuarial gain	(66)	(51)
Benefits paid	(8)	(9)
Foreign currency exchange rate changes	0	0
Other	0	0
Accumulated postretirement benefit obligation at end of year	211	274	321
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return/(loss) on plan assets	0	0
Employer contributions	8	9
Participant contributions	0	0
Benefits paid	(8)	(9)
Foreign currency exchange rate changes	0	0
Other	0	0
Fair value of plan assets at end of year	0	0	0
Overfunded/(underfunded) status at end of year	(211)	(274)
Presented as follows:
Deferred amounts and other assets	0	0
Accounts payable and other	(12)	(12)
Other long-term liabilities	(199)	(262)
Amount recognized in balance sheet	(211)	(274)
United States
Change in plan assets
Employer contributions	30	27	27
United States | Pension
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	1,184	1,243
Service cost	43	44	44
Interest cost	24	17	31
Participant contributions	0	0
Actuarial gain	(201)	(21)
Benefits paid	(94)	(84)
Foreign currency exchange rate changes	77	(11)
Other	(4)	(4)
Accumulated postretirement benefit obligation at end of year	1,029	1,184	1,243
Change in plan assets
Fair value of plan assets at beginning of year	1,160	1,062
Actual return/(loss) on plan assets	(64)	151
Employer contributions	4	43
Participant contributions	0	0
Benefits paid	(94)	(84)
Foreign currency exchange rate changes	78	(8)
Other	(4)	(4)
Fair value of plan assets at end of year	1,080	1,160	1,062
Overfunded/(underfunded) status at end of year	51	(24)
Presented as follows:
Deferred amounts and other assets	141	98
Accounts payable and other	(5)	(4)
Other long-term liabilities	(85)	(118)
Amount recognized in balance sheet	51	(24)
Accumulated benefit obligation	1,000
United States | Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	58	84
United States | OPEB
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	173	254
Service cost	1	1	2
Interest cost	3	3	7
Participant contributions	6	8
Actuarial gain	(37)	(69)
Benefits paid	(21)	(22)
Foreign currency exchange rate changes	11	(3)
Other	0	1
Accumulated postretirement benefit obligation at end of year	136	173	254
Change in plan assets
Fair value of plan assets at beginning of year	201	188
Actual return/(loss) on plan assets	(21)	22
Employer contributions	7	6
Participant contributions	6	8
Benefits paid	(21)	(22)
Foreign currency exchange rate changes	13	(3)
Other	0	2
Fair value of plan assets at end of year	185	201	$ 188
Overfunded/(underfunded) status at end of year	49	28
Presented as follows:
Deferred amounts and other assets	75	71
Accounts payable and other	0	0
Other long-term liabilities	(26)	(43)
Amount recognized in balance sheet	$ 49	$ 28

PENSION AND OTHER POSTRETIREM_4

PENSION AND OTHER POSTRETIREMENT BENEFITS - Amount Recognized in Excess of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Canada
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	$ 360	$ 440
Fair value of plan assets	218	247
Canada | OPEB
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	211	274
Fair value of plan assets	0	0
Projected benefit obligation	377	1,272
Fair value of plan assets	218	1,020
United States
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	89	115
Fair value of plan assets	0	0
United States | OPEB
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	76	94
Fair value of plan assets	50	51
Projected benefit obligation	90	121
Fair value of plan assets	$ 0	$ 0

PENSION AND OTHER POSTRETIREM_5

PENSION AND OTHER POSTRETIREMENT BENEFITS - Amount Recognized in Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Canada | OPEB
Amount included in AOCI
Net actuarial (gain)/loss	$ (101)	$ (35)
Prior service (credit)/cost	(1)	(1)
Total amount recognized in AOCI	(102)	(36)
Canada | Pension
Amount included in AOCI
Net actuarial (gain)/loss	(64)	226
Prior service (credit)/cost	0	0
Total amount recognized in AOCI	(64)	226
United States | OPEB
Amount included in AOCI
Net actuarial (gain)/loss	(102)	(104)
Prior service (credit)/cost	(30)	(37)
Total amount recognized in AOCI	(132)	(141)
United States | Pension
Amount included in AOCI
Net actuarial (gain)/loss	40	92
Prior service (credit)/cost	1	(1)
Total amount recognized in AOCI	$ 41	$ 91

PENSION AND OTHER POSTRETIREM_6

PENSION AND OTHER POSTRETIREMENT BENEFITS - Net Benefit Costs Recognized (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 131	$ 139	$ 148
Interest cost	127	101	128
Expected return on plan assets	(295)	(252)	(260)
Amortization/settlement of net actuarial loss	8	54	42
Amortization/curtailment of prior service credit	0	0	0
Net periodic benefit (credit)/cost	(29)	42	58
Defined contribution benefit cost	10	7	6
Net pension (credit)/cost recognized in Earnings	(19)	49	64
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	(2)	(25)	(21)
Amortization/curtailment of prior service credit	0	0	0
Net actuarial (gain)/loss arising during the year	(288)	(291)	118
Total amount recognized in OCI	(290)	(316)	97
Total amount recognized in Comprehensive income	(309)	(267)	161
Pension | United States
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	43	44	44
Interest cost	24	17	31
Expected return on plan assets	(85)	(73)	(88)
Amortization/settlement of net actuarial loss	0	11	1
Amortization/curtailment of prior service credit	(2)	0	(1)
Net periodic benefit (credit)/cost	(20)	(1)	(13)
Defined contribution benefit cost	0	0	0
Net pension (credit)/cost recognized in Earnings	(20)	(1)	(13)
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	0	(11)	(1)
Amortization/curtailment of prior service credit	2	0	1
Net actuarial (gain)/loss arising during the year	(52)	(99)	100
Total amount recognized in OCI	(50)	(110)	100
Total amount recognized in Comprehensive income	(70)	(111)	87
OPEB | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	4	6	5
Interest cost	7	7	8
Expected return on plan assets	0	0	0
Amortization/settlement of net actuarial loss	(1)	0	(1)
Amortization/curtailment of prior service credit	0	0	0
Net pension (credit)/cost recognized in Earnings	10	13	12
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	1	0	1
Amortization/curtailment of prior service credit	0	0	0
Net actuarial (gain)/loss arising during the year	(67)	(50)	21
Prior service credit	0	0	0
Total amount recognized in OCI	(66)	(50)	22
Total amount recognized in Comprehensive income	(56)	(37)	34
OPEB | United States
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	1	1	2
Interest cost	3	3	7
Expected return on plan assets	(12)	(10)	(12)
Amortization/settlement of net actuarial loss	(6)	(1)	(1)
Amortization/curtailment of prior service credit	(7)	(7)	(2)
Net pension (credit)/cost recognized in Earnings	(21)	(14)	(6)
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	6	1	1
Amortization/curtailment of prior service credit	7	7	2
Net actuarial (gain)/loss arising during the year	(4)	(80)	15
Prior service credit	0	0	(33)
Total amount recognized in OCI	9	(72)	(15)
Total amount recognized in Comprehensive income	$ (12)	$ (86)	$ (21)

PENSION AND OTHER POSTRETIREM_7

PENSION AND OTHER POSTRETIREMENT BENEFITS - Actuarial Assumptions (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
OPEB | Canada
Projected benefit obligation
Discount rate	5.30%	3.20%	2.60%
Net periodic benefit cost
Discount rate	3.20%	2.60%	3.10%
OPEB | United States
Projected benefit obligation
Discount rate	4.90%	2.40%	2%
Net periodic benefit cost
Discount rate	2.40%	2%	2.80%
Rate of return on plan assets	6%	6%	6.70%
Pension | Canada
Projected benefit obligation
Discount rate	5.10%	3.20%	2.60%
Rate of salary increase	2.90%	2.90%	2.30%
Net periodic benefit cost
Discount rate	3.20%	2.60%	3%
Rate of return on plan assets	6.60%	6.20%	6.80%
Rate of salary increase	2.90%	2.30%	3.20%
Pension | United States
Projected benefit obligation
Discount rate	4.90%	2.60%	2.20%
Rate of salary increase	2.80%	2.80%	2.70%
Cash balance interest credit rate	4.30%	4.30%	4.30%
Net periodic benefit cost
Discount rate	2.60%	2.20%	3%
Rate of return on plan assets	7.40%	7.30%	7.90%
Rate of salary increase	2.80%	2.70%	2.90%
Cash balance interest credit rate	4.30%	4.30%	4.50%

PENSION AND OTHER POSTRETIREM_8

PENSION AND OTHER POSTRETIREMENT BENEFITS - Assumed Health Care Cost Trend Rates (Details)	Dec. 31, 2022	Dec. 31, 2021
MEDICAL COST TRENDS (as percent)
Health care cost trend rate assumed for next year	5%
Canada
MEDICAL COST TRENDS (as percent)
Health care cost trend rate assumed for next year	4%	4%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	4%	4%
United States
MEDICAL COST TRENDS (as percent)
Health care cost trend rate assumed for next year	4.70%	7%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	3.30%	4.50%

PENSION AND OTHER POSTRETIREM_9

PENSION AND OTHER POSTRETIREMENT BENEFITS - Plan Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Canada | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	43.80%
Plan asset allocations	38.20%	46.70%
Canada | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	28.40%
Plan asset allocations	31.70%	29.80%
Canada | Alternatives
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	27.80%
Plan asset allocations	30.10%	23.50%
Canada | Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 4,536	$ 4,077
Fair value of plan assets at end of year	4,234	4,536
Canada | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	637
Fair value of plan assets at end of year	473	637
Canada | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	2,835
Fair value of plan assets at end of year	2,470	2,835
Canada | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	1,064	912
Unrealized and realized gains	155	77
Purchases and settlements, net	72	75
Fair value of plan assets at end of year	1,291	1,064
Canada | Pension | Alternatives
Change in plan assets
Fair value of plan assets at beginning of year	1,064
Fair value of plan assets at end of year	1,291	1,064
Canada | Pension | Alternatives | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Alternatives | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Alternatives | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	1,064
Fair value of plan assets at end of year	1,291	1,064
Canada | Pension | Cash and Cash Equivalents
Change in plan assets
Fair value of plan assets at beginning of year	180
Fair value of plan assets at end of year	272	180
Canada | Pension | Cash and Cash Equivalents | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	180
Fair value of plan assets at end of year	272	180
Canada | Pension | Cash and Cash Equivalents | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Cash and Cash Equivalents | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	1,693
Fair value of plan assets at end of year	1,263	1,693
Canada | Pension | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	1,693
Fair value of plan assets at end of year	1,263	1,693
Canada | Pension | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	1
Fair value of plan assets at end of year		1
Canada | Pension | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	1
Fair value of plan assets at end of year		1
Canada | Pension | Equity Securities, US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
Canada | Pension | Equity Securities, US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
Canada | Pension | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	426
Fair value of plan assets at end of year	355	426
Canada | Pension | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	198
Fair value of plan assets at end of year	0	198
Canada | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	228
Fair value of plan assets at end of year	355	228
Canada | Pension | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Government
Change in plan assets
Fair value of plan assets at beginning of year	717
Fair value of plan assets at end of year	636	717
Canada | Pension | Government | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	258
Fair value of plan assets at end of year	201	258
Canada | Pension | Government | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	459
Fair value of plan assets at end of year	435	459
Canada | Pension | Government | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Corporate
Change in plan assets
Fair value of plan assets at beginning of year	453
Fair value of plan assets at end of year	433	453
Canada | Pension | Corporate | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Corporate | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	453
Fair value of plan assets at end of year	433	453
Canada | Pension | Corporate | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Foreign exchange contracts
Change in plan assets
Fair value of plan assets at beginning of year	2
Fair value of plan assets at end of year	(16)	2
Canada | Pension | Foreign exchange contracts | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Foreign exchange contracts | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	2
Fair value of plan assets at end of year	(16)	2
Canada | Pension | Foreign exchange contracts | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Fair value of plan assets at end of year	$ 0	$ 0
United States | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	45%
Plan asset allocations	38.30%	52.50%
United States | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	20%
Plan asset allocations	20.50%	18.40%
United States | Alternatives
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	35%
Plan asset allocations	41.20%	29.10%
United States | Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 1,160	$ 1,062
Fair value of plan assets at end of year	1,080	1,160
United States | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	10
Fair value of plan assets at end of year	13	10
United States | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	813
Fair value of plan assets at end of year	622	813
United States | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	337	289
Unrealized and realized gains	78	38
Purchases and settlements, net	30	10
Fair value of plan assets at end of year	445	337
United States | Pension | Alternatives
Change in plan assets
Fair value of plan assets at beginning of year	337
Fair value of plan assets at end of year	445	337
United States | Pension | Alternatives | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Alternatives | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Alternatives | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	337
Fair value of plan assets at end of year	445	337
United States | Pension | Cash and Cash Equivalents
Change in plan assets
Fair value of plan assets at beginning of year	10
Fair value of plan assets at end of year	13	10
United States | Pension | Cash and Cash Equivalents | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	10
Fair value of plan assets at end of year	13	10
United States | Pension | Cash and Cash Equivalents | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Cash and Cash Equivalents | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	609
Fair value of plan assets at end of year	414	609
United States | Pension | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	609
Fair value of plan assets at end of year	414	609
United States | Pension | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | Pension | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | Pension | Equity Securities, US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | Pension | Equity Securities, US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | Pension | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Government
Change in plan assets
Fair value of plan assets at beginning of year	86
Fair value of plan assets at end of year	87	86
United States | Pension | Government | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Government | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	86
Fair value of plan assets at end of year	87	86
United States | Pension | Government | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Corporate
Change in plan assets
Fair value of plan assets at beginning of year	118
Fair value of plan assets at end of year	121	118
United States | Pension | Corporate | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Corporate | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	118
Fair value of plan assets at end of year	121	118
United States | Pension | Corporate | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Foreign exchange contracts
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Foreign exchange contracts | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Foreign exchange contracts | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Foreign exchange contracts | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB
Change in plan assets
Fair value of plan assets at beginning of year	201	188
Fair value of plan assets at end of year	185	201
United States | OPEB | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	201
Fair value of plan assets at end of year	185	201
United States | OPEB | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	51
Fair value of plan assets at end of year	48	51
United States | OPEB | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	128
Fair value of plan assets at end of year	109	128
United States | OPEB | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	22	22
Unrealized and realized gains	4	2
Purchases and settlements, net	2	(2)
Fair value of plan assets at end of year	28	22
United States | OPEB | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	22
Fair value of plan assets at end of year	28	22
United States | OPEB | Alternatives | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	22
Fair value of plan assets at end of year	28	22
United States | OPEB | Alternatives | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Alternatives | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Alternatives | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	22
Fair value of plan assets at end of year	28	22
United States | OPEB | Cash and Cash Equivalents | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	4
Fair value of plan assets at end of year	2	4
United States | OPEB | Cash and Cash Equivalents | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	4
Fair value of plan assets at end of year	2	4
United States | OPEB | Cash and Cash Equivalents | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Cash and Cash Equivalents | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	39
Fair value of plan assets at end of year	34	39
United States | OPEB | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	39
Fair value of plan assets at end of year	34	39
United States | OPEB | Equity Securities, US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	75
Fair value of plan assets at end of year	62	75
United States | OPEB | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	75
Fair value of plan assets at end of year	62	75
United States | OPEB | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Government | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	53
Fair value of plan assets at end of year	51	53
United States | OPEB | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	47
Fair value of plan assets at end of year	46	47
United States | OPEB | Government | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	6
Fair value of plan assets at end of year	5	6
United States | OPEB | Government | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Corporate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	8
Fair value of plan assets at end of year	8	8
United States | OPEB | Corporate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Corporate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	8
Fair value of plan assets at end of year	8	8
United States | OPEB | Corporate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	$ 0	$ 0

PENSION AND OTHER POSTRETIRE_10

PENSION AND OTHER POSTRETIREMENT BENEFITS - Expected Benefit Payments and Employer Contributions (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Canada | Pension
Benefits Expected to be Paid by the Company
2023	$ 204
2024	210
2025	216
2026	221
2027	226
2028-2032	1,208
Contributions expected to be paid in next fiscal year	29
Canada | OPEB
Benefits Expected to be Paid by the Company
2023	12
2024	12
2025	13
2026	13
2027	13
2028-2032	68
Contributions expected to be paid in next fiscal year	12
United States | Pension
Benefits Expected to be Paid by the Company
2023	88
2024	87
2025	87
2026	88
2027	90
2028-2032	424
Contributions expected to be paid in next fiscal year	5
United States | OPEB
Benefits Expected to be Paid by the Company
2023	16
2024	15
2025	14
2026	13
2027	12
2028-2032	49
Contributions expected to be paid in next fiscal year	$ 6

PENSION AND OTHER POSTRETIRE_11

PENSION AND OTHER POSTRETIREMENT BENEFITS - Retirement Savings Plan (Details) - United States - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension and Other Postretirement Benefit Disclosures
Percent of match (percent)	6%
Total contributions by the Company	$ 30	$ 27	$ 27

LEASES - Narrative (Details)

LEASES - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Operating lease, expense	$ 118	$ 95	$ 107
Operating lease, payments	$ 123	$ 118	$ 133
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease term	1 month
Lessor, operating lease, remaining lease term	1 month
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	24 years
Lessor, operating lease, remaining lease term	29 years

LEASES - Supplemental Statement

LEASES - Supplemental Statements of Financial Postion (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Supplemental Statements Of Financial Position
Operating lease right-of-use assets, net	$ 680	$ 645
Operating lease liabilities - current	87	92
Operating lease liabilities - long-term	677	612
Total	764	704
Finance lease right-of-use assets, net	62	49
Finance lease liabilities - current	17	13
Finance lease liabilities - long-term	39	33
Total finance lease liabilities	$ 56	$ 46
Operating leases - Weighted average remaining lease term	12 years	12 years
Finance leases - Weighted average remaining lease term	5 years	7 years
Operating leases - Weighted average discount rate	4.20%	4.10%
Finance leases - Weighted average discount rate	4.40%	3.80%
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Deferred amounts and other assets	Deferred amounts and other assets
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts payable and other (Note 17)	Accounts payable and other (Note 17)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Property, plant and equipment, net (Note 11)	Property, plant and equipment, net (Note 11)
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	Current portion of long-term debt (Note 18)	Current portion of long-term debt (Note 18)
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Affiliated Entity
Supplemental Statements Of Financial Position
Operating lease right-of-use assets, net	$ 47	$ 51
Operating lease liabilities - current	5	5
Operating lease liabilities - long-term	$ 43	$ 47

LEASES - Lease Commitments (Det

LEASES - Lease Commitments (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Operating leases
2023	$ 109
2024	110
2025	104
2026	90
2027	82
Thereafter	489
Total undiscounted lease payments	984
Less imputed interest	(220)
Total	764	$ 704
Finance leases
2023	19
2024	16
2025	8
2026	8
2027	1
Thereafter	10
Total undiscounted lease payments	62
Less imputed interest	(6)
Total finance lease liabilities	$ 56	$ 46

LEASES - Lessor Lease Income (D

LEASES - Lessor Lease Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease income	$ 266	$ 263	$ 265
Variable lease income	$ 321	333	361
Operating Lease Income Comprehensive Income Extensible List Not Disclosed Flag	Total lease income1
Total lease income	$ 587	$ 596	$ 626

LEASES - Lessor Future Expected

LEASES - Lessor Future Expected Lease Receipts (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Leases [Abstract]
2023	$ 227
2024	215
2025	204
2026	198
2027	201
Thereafter	1,832
Future lease payments	$ 2,877

OTHER INCOME_(EXPENSE) (Details

OTHER INCOME/(EXPENSE) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Income and Expenses [Abstract]
Gain/(loss) on dispositions	$ (12)	$ 319	$ (17)
Realized foreign currency gain/(loss)	92	126	(10)
Unrealized foreign currency gain/(loss)	(1,094)	160	191
Net defined pension and OPEB credit	239	150	148
Other	186	224	(74)
Total	$ (589)	$ 979	$ 238

CHANGES IN OPERATING ASSETS A_3

CHANGES IN OPERATING ASSETS AND LIABILITIES (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
CHANGES IN OPERATING ASSETS AND LIABILITIES
Accounts receivable and other	$ (967)	$ (1,228)	$ 1,546
Accounts receivable from affiliates	17	(38)	8
Inventory	(599)	(118)	(254)
Deferred amounts and other assets	1	(195)	(586)
Accounts payable and other	1,100	87	(770)
Accounts payable to affiliates	16	52	1
Interest payable	58	43	31
Other long-term liabilities	362	(69)	117
Changes in operating assets and liabilities	$ (12)	$ (1,466)	$ 93

RELATED PARTY TRANSACTIONS - Tr

RELATED PARTY TRANSACTIONS - Transactions With Significantly Influenced Investees (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Aug. 02, 2022
Oakville Enterprises Corporation | Gas Distribution and Storage
RELATED PARTY TRANSACTIONS
OTHER LONG-TERM INVESTMENTS	$ 48	$ 0
Ownership interest (as a percent)				10%
Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Transportation and other revenues	185	237	$ 219
Commodity sales	51	20	21
Operating and administrative	503	380	338
Commodity costs	778	790	518
Gas distribution costs	$ 136	131	135
Other | Other | Gas Distribution and Storage | Minimum
RELATED PARTY TRANSACTIONS
Ownership interest (as a percent)	47.60%
Other | Other | Gas Distribution and Storage | Maximum
RELATED PARTY TRANSACTIONS
Ownership interest (as a percent)	50%
Other | Other | Gas Transmission and Midstream | Minimum
RELATED PARTY TRANSACTIONS
Ownership interest (as a percent)	20%
Other | Other | Gas Transmission and Midstream | Maximum
RELATED PARTY TRANSACTIONS
Ownership interest (as a percent)	33.30%
Offshore - various joint ventures | Offshore - various joint ventures | Gas Transmission and Midstream | Minimum
RELATED PARTY TRANSACTIONS
Ownership interest (as a percent)	22%
Offshore - various joint ventures | Offshore - various joint ventures | Gas Transmission and Midstream | Maximum
RELATED PARTY TRANSACTIONS
Ownership interest (as a percent)	74.30%
Seaway Crude Pipeline System
RELATED PARTY TRANSACTIONS
Operating and administrative	$ 495	389	342
Aux Sable Canada LP
RELATED PARTY TRANSACTIONS
Commodity costs	$ 571	$ 447	$ 91

RELATED PARTY TRANSACTIONS - Na

RELATED PARTY TRANSACTIONS - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
RELATED PARTY TRANSACTIONS
Affiliate loan receivable	$ 752	$ 954
Interest income	$ 30	$ 39	$ 44
Minimum
RELATED PARTY TRANSACTIONS
Annual interest rate on the loans (as a percent)	3%
Maximum
RELATED PARTY TRANSACTIONS
Annual interest rate on the loans (as a percent)	8%

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Annual debt maturities
Total	$ 78,742
Less than 1 year	6,024
2 years	8,220
3 years	6,051
4 years	3,730
5 years	10,344
Thereafter	44,373
Purchase of services, pipe and other materials, including transportation
Total	10,661
Less than 1 year	3,553
2 years	1,513
3 years	1,070
4 years	1,001
5 years	767
Thereafter	2,757
Maintenance agreements3
Total	536
Less than 1 year	53
2 years	53
3 years	53
4 years	53
5 years	55
Thereafter	269
Right-of-ways commitments
Total	1,474
Less than 1 year	45
2 years	45
3 years	46
4 years	46
5 years	46
Thereafter	1,246
Total
Total	91,413
Less than 1 year	9,675
2 years	9,831
3 years	7,220
4 years	4,830
5 years	11,212
Thereafter	$ 48,645

QUARTERLY FINANCIAL DATA (UNA_3

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - CAD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 12,470	$ 11,466	$ 10,948	$ 12,187	$ 53,309	$ 47,071	$ 39,087
Operating income/(loss)	(540)	1,778	1,520	2,420	2,053	1,388	1,816	2,548	5,178	7,805	7,957
Earnings	(1,109)	1,383	607	2,057	1,965	814	1,521	2,014	2,938	6,314	3,416
Earnings/(loss) attributable to controlling interests	(983)	1,362	595	2,029	1,933	780	1,484	1,992	3,003	6,189	3,363
Earnings/(loss) attributable to common shareholders	$ (1,067)	$ 1,279	$ 450	$ 1,927	$ 1,840	$ 682	$ 1,394	$ 1,900	$ 2,589	$ 5,816	$ 2,983
Earnings/(loss) per common share
Earnings (loss) per common share attributable to common shareholders (in CAD per share)	$ (0.53)	$ 0.63	$ 0.22	$ 0.95	$ 0.91	$ 0.34	$ 0.69	$ 0.94	$ 1.28	$ 2.87	$ 1.48
Diluted earnings per common share attributable to common shareholders (in CAD per share)	$ (0.53)	$ 0.63	$ 0.22	$ 0.95	$ 0.91	$ 0.34	$ 0.69	$ 0.94	$ 1.28	$ 2.87	$ 1.48

Uncategorized Items - enb-20221

Label	Element	Value
Proceeds from Sale of Equity Method Investments	us-gaap_ProceedsFromSaleOfEquityMethodInvestments	$ 522,000,000
Proceeds from Sale of Equity Method Investments	us-gaap_ProceedsFromSaleOfEquityMethodInvestments	$ 404,000,000