Enbridge (ENB) 10-K9 Feb 242023 FY Annual reportFinancial data

Company Profile

Cover

Cover - USD ($) $ in Billions	12 Months Ended
Cover - USD ($) $ in Billions	Dec. 31, 2023	Feb. 02, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
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
Title of 12(b) Security	Common Shares
Trading Symbol	ENB
Security Exchange Name	NYSE
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
Document Financial Statement Error Correction Flag	false
Entity Shell Company	false
Entity Public Float			$ 75.1
Entity Common Stock, Shares Outstanding		2,125,586,356
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE: Not applicable.
Entity Central Index Key	0000895728
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY

Audit Information

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2023
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, 2023 CAD ($) $ / shares	Dec. 31, 2022 CAD ($) $ / shares	Dec. 31, 2021 CAD ($) $ / shares
Operating revenues
Total operating revenues (Note 4)	$ 43,649	$ 53,309	$ 47,071
Operating expenses
Operating and administrative	8,600	8,219	6,712
Depreciation and amortization	4,613	4,317	3,852
Impairment of long-lived assets	419	541	0
Impairment of goodwill (Note 15)	0	2,465	0
Total operating expenses	34,998	48,131	39,266
Operating income	8,651	5,178	7,805
Income from equity investments (Note 13)	1,816	2,056	1,600
Gain on joint venture merger transaction (Note 13)	0	1,076	0
Other income/(expense) (Note 27)	1,224	(589)	979
Interest expense (Note 17)	(3,812)	(3,179)	(2,655)
Earnings before income taxes	7,879	4,542	7,729
Income tax expense (Note 24)	(1,821)	(1,604)	(1,415)
Earnings	6,058	2,938	6,314
(Earnings)/loss attributable to noncontrolling interests	133	65	(125)
Earnings attributable to controlling interests	6,191	3,003	6,189
Preference share dividends	(352)	(414)	(373)
Earnings attributable to common shareholders	$ 5,839	$ 2,589	$ 5,816
Earnings per common share attributable to common shareholders (in Canadian dollars per share) \| $ / shares	$ 2.84	$ 1.28	$ 2.87
Diluted earnings per common share attributable to common shareholders (in Canadian dollars per share) \| $ / shares	$ 2.84	$ 1.28	$ 2.87
Commodity sales
Operating revenues
Total operating revenues (Note 4)	$ 18,981	$ 29,150	$ 26,873
Operating expenses
Commodity costs and Gas distribution costs	18,526	28,942	26,608
Gas distribution sales
Operating revenues
Total operating revenues (Note 4)	4,839	5,653	4,026
Operating expenses
Commodity costs and Gas distribution costs	2,840	3,647	2,094
Transportation and other services
Operating revenues
Total operating revenues (Note 4)	$ 19,829	$ 18,506	$ 16,172

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Earnings	$ 6,058	$ 2,938	$ 6,314
Other comprehensive income/(loss), net of tax
Change in unrealized gain on cash flow hedges	220	847	162
Change in unrealized gain/(loss) on net investment hedges	409	(971)	49
Other comprehensive income/(loss) from equity investees	6	(6)	(12)
Excluded components of fair value hedges	12	(35)	(5)
Reclassification to earnings of loss on cash flow hedges	14	143	235
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(18)	(10)	21
Reclassification to earnings of (gain)/loss on equity investees	0	16	(62)
Actuarial gain/(loss) on pension and OPEB	(130)	312	394
Foreign currency translation adjustments	(1,728)	4,406	(507)
Other comprehensive income/(loss), net of tax	(1,215)	4,702	275
Comprehensive income	4,843	7,640	6,589
Comprehensive (income)/loss attributable to noncontrolling interests	131	(21)	(95)
Comprehensive income attributable to controlling interests	4,974	7,619	6,494
Preference share dividends	(352)	(414)	(373)
Comprehensive income attributable to common shareholders	$ 4,622	$ 7,205	$ 6,121

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - CAD ($) $ in Millions	Total	Total Enbridge Inc. shareholders' equity	Preference shares (Note 20)	Common shares (Note 20)	Additional paid-in capital	Deficit	Accumulated other comprehensive income/(loss) (Note 22)	Treasury Stock, Common	Noncontrolling interests (Note 19)
Balance at beginning of year at Dec. 31, 2020			$ 7,747	$ 64,768	$ 277	$ (9,995)	$ (1,401)	$ (29)	$ 2,996
Increase (Decrease) in Stockholders' Equity
Shares issued, net of issue costs				0
Redemption of preference shares			0
Shares issued on exercise of stock options				31	(23)
Shares issued on vesting of restricted stock units (RSU), net of tax	$ 0			0
Share purchases at stated value				0
Other				0					0
Stock-based compensation					28
Purchase of noncontrolling interest					0
Change in reciprocal interest					98			29
Other				0	(15)
Earnings 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 gain/(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/(loss) attributable to noncontrolling interests	(95)								95
Distributions									(271)
Contributions									15
Redemption of noncontrolling interests									(293)
Purchase of noncontrolling interests									0
Balance at end of year at Dec. 31, 2021	$ 63,368	$ 60,826	7,747	64,799	365	(10,989)	(1,096)	0	2,542
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share)	$ 3.34
Shares issued, net of issue costs				0
Redemption of preference shares			(929)
Shares issued on exercise of stock options				53	(50)
Shares issued on vesting of restricted stock units (RSU), net of tax				0	0
Share purchases at stated value				(88)
Other				(4)					47
Stock-based compensation					36
Purchase of noncontrolling interest					(43)
Change in reciprocal interest					0			0
Other				(4)	(33)
Earnings 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 gain/(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/(loss) attributable to noncontrolling interests	(21)								21
Distributions									(259)
Contributions									1,105
Redemption of noncontrolling interests									0
Purchase of noncontrolling interests									55
Balance at end of year at Dec. 31, 2022	$ 63,398	59,887	6,818	64,760	275	(15,486)	3,520	0	3,511
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share)	$ 3.44
Shares issued, net of issue costs				4,485
Redemption of preference shares			0
Shares issued on exercise of stock options				3	(3)
Shares issued on vesting of restricted stock units (RSU), net of tax				12	(20)
Share purchases at stated value				(80)
Other				0					(1)
Stock-based compensation					71
Purchase of noncontrolling interest					(28)
Change in reciprocal interest					0			0
Other				0	(27)
Earnings attributable to controlling interests	$ 6,191					6,191
Preference share dividends						(352)
Common share dividends declared						(7,423)
Dividends paid to reciprocal shareholder						0
Share purchases in excess of stated value						(45)
Other comprehensive income/(loss) attributable to common shareholders, net of tax							(1,217)
Earnings/(loss) attributable to noncontrolling interests									(133)
Change in unrealized gain/(loss) on cash flow hedges									35
Foreign currency translation adjustments									(33)
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									2
Comprehensive income/(loss) attributable to noncontrolling interests	131								(131)
Distributions									(363)
Contributions									11
Redemption of noncontrolling interests									0
Purchase of noncontrolling interests									2
Balance at end of year at Dec. 31, 2023	$ 64,483	$ 61,454	$ 6,818	$ 69,180	$ 268	$ (17,115)	$ 2,303	$ 0	$ 3,029
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share)	$ 3.55

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Operating activities
Earnings	$ 6,058	$ 2,938	$ 6,314
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	4,613	4,317	3,852
Deferred income tax expense (Note 24)	1,420	957	1,091
Unrealized derivative fair value (gain)/loss, net (Note 23)	(1,180)	1,280	(173)
Income from equity investments (Note 13)	(1,816)	(2,056)	(1,600)
Distributions from equity investments	1,998	1,827	1,630
Impairment of long-lived assets	419	541	0
Impairment of goodwill (Note 15)	0	2,465	0
Gain on joint venture merger transaction (Note 13)	0	(1,076)	0
(Gain)/loss on dispositions (Note 27)	(15)	12	(319)
Other	393	37	(73)
Changes in operating assets and liabilities (Note 28)	2,311	(12)	(1,466)
Net cash provided by operating activities	14,201	11,230	9,256
Investing activities
Capital expenditures	(4,654)	(4,647)	(7,818)
Long-term, restricted and other investments	(1,276)	(1,041)	(640)
Distributions from equity investments in excess of cumulative earnings	1,151	763	533
Additions to intangible assets	(222)	(174)	(275)
Acquisitions	(954)	(828)	(3,785)
Proceeds from joint venture merger transaction (Note 13)	0	522	0
Proceeds from dispositions	0	0	1,263
Net change in affiliate loans	(27)	135	65
Other	(61)	0	0
Net cash used in investing activities	(6,043)	(5,270)	(10,657)
Financing activities
Net change in short-term borrowings	(1,596)	481	394
Net change in commercial paper and credit facility draws	(8,157)	(1,333)	2,960
Debenture and term note issues, net of issue costs	15,377	7,547	8,032
Debenture and term note repayments	(4,819)	(4,198)	(2,264)
Sale of noncontrolling interest in subsidiary (Note 8)	0	1,092	0
Contributions from noncontrolling interests	11	13	15
Distributions to noncontrolling interests	(363)	(259)	(271)
Common shares issued, net of issue costs	4,450	3	5
Common shares repurchased	(125)	(151)	0
Preference share dividends	(352)	(338)	(367)
Common share dividends	(7,276)	(6,968)	(6,766)
Redemption of preference shares	0	(1,003)	0
Redemption of preferred shares held by subsidiary	0	0	(415)
Net change in affiliate loan	71	0	0
Other	(85)	(314)	(87)
Net cash provided by/(used in) financing activities	(2,864)	(5,428)	1,236
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	(216)	55	(5)
Net change in cash and cash equivalents and restricted cash	5,078	587	(170)
Cash and cash equivalents and restricted cash at beginning of year	907	320	490
Cash and cash equivalents and restricted cash at end of year	5,985	907	320
Supplementary cash flow information
Cash paid for income taxes	578	495	489
Cash paid for interest, net of amount capitalized	3,380	2,920	2,427
Property, plant and equipment and intangible assets non-cash accruals	$ 813	$ 937	$ 831

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 5,901	$ 861
Restricted cash	84	46
Trade receivables and unbilled revenues	4,410	5,616
Other current assets	2,440	3,255
Accounts receivable from affiliates	85	114
Inventory (Note 10)	1,479	2,255
Current assets	14,399	12,147
Property, plant and equipment, net (Note 11)	104,641	104,460
Long-term investments (Note 13)	16,793	15,936
Restricted long-term investments	717	593
Deferred amounts and other assets	8,041	9,542
Intangible assets, net (Note 14)	3,537	4,018
Goodwill (Note 15)	31,848	32,440
Deferred income taxes (Note 24)	341	472
Total assets	180,317	179,608
Current liabilities
Short-term borrowings (Note 17)	400	1,996
Trade payables and accrued liabilities	4,308	6,172
Other current liabilities (Note 16)	5,659	5,220
Accounts payable to affiliates	26	105
Interest payable	958	763
Current portion of long-term debt (Note 17)	6,084	6,045
Current liabilities	17,435	20,301
Long-term debt (Note 17)	74,715	72,939
Other long-term liabilities	8,653	9,189
Deferred income taxes (Note 24)	15,031	13,781
Liabilities	115,834	116,210
Commitments and contingencies (Note 30)
Share capital
Preference shares	6,818	6,818
Common shares (2,125 and 2,025 outstanding at December 31, 2023 and 2022, respectively)	69,180	64,760
Additional paid-in capital	268	275
Deficit	(17,115)	(15,486)
Accumulated other comprehensive income (Note 22)	2,303	3,520
Total Enbridge Inc. shareholders’ equity	61,454	59,887
Noncontrolling interests (Note 19)	3,029	3,511
Equity	64,483	63,398
Total liabilities and equity	$ 180,317	$ 179,608

CONSOLIDATED STATEMENTS OF FI_2

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	2,125	2,025

BUSINESS OVERVIEW

BUSINESS OVERVIEW	12 Months Ended
BUSINESS OVERVIEW	Dec. 31, 2023
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. On October 12, 2021, we acquired Moda Midstream Operating, LLC (Moda) (Note 8) , which includes the Enbridge Ingleside Energy Center, 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. This segment also includes certain investments in renewable natural gas (RNG) facilities. 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, Ontario and Québec, and in the states of Colorado, Texas, Indiana, Ohio and West Virginia. We also hold interests in offshore wind facilities in operation, under construction and in active development in the United Kingdom, France and Germany. 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. This segment 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
SIGNIFICANT ACCOUNTING POLICIES	Dec. 31, 2023
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 14) ; measurement of goodwill (Note 15) ; fair value of asset retirement obligations (ARO) (Note 18) ; valuation of stock-based compensation (Note 21) ; fair value of financial instruments (Note 23) ; provisions for income taxes (Note 24) ; assumptions used to measure retirement benefits and OPEB (Note 25) ; commitments and contingencies (Note 30) ; and estimates of losses related to environmental remediation obligations (Note 30) . 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 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 BC Energy Regulator, the Ontario Energy Board (OEB) and the Québec Régie de l’énergie. 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, amounts collected from customers in advance of costs being incurred, or to be paid to cover future abandonment costs in relation to the CER's Land Matters Consultation Initiative (LMCI) and for future removal and site restoration costs as approved by the regulator. If there are changes in our assessment of the probability of recovery for a regulatory asset, we reduce its carrying amount to the balance that we expect to recover from customers in future periods through rates. If a regulator later excludes from allowable costs all or a part of costs that were capitalized as a regulatory asset, we reduce the carrying amount of the asset by the excluded amounts. 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. During the fourth quarter of 2023, Southern Lights Pipeline completed an open season to negotiate new transportation service agreements. We do not expect to renew the agreements under a cost-of-service toll methodology, therefore Southern Lights Pipeline is no longer subject to rate-regulated accounting. As a result, the related regulatory liabilities, regulatory tax assets and associated regulatory deferred tax liabilities were derecognized. We believe that the recovery of our remaining regulatory assets as at December 31, 2023 is probable over the periods described in Note 7 - Regulatory Matters . 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 regulatory requirements under the 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. An 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 and 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, 2023, 2022 and 2021, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $210 million, $238 million and $127 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 we are acting as the principal in the transactions. No non-affiliated customer exceeded 10.0% of our third-party revenues for the years ended December 31, 2023 and 2022. Our largest non-affiliated customer accounted for approximately 13.5% of our third-party revenues for the year ended December 31, 2021. 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 revenues, 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 and debt 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. Trade receivables and unbilled revenues 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. Trade receivables and unbilled revenues are presented net of allowance for expected credit losses of $100 million and $92 million as at December 31, 2023 and 2022, respectively. 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 our 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 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 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. The lease term may include periods associated with options to extend or terminate the lease if it is reasonably certain the options will be exercised. 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 for certain regulated entities; 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 for Enbridge Gas. 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 discounted cash flow technique. 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 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, 2023, we performed our annual goodwill impairment assessment which consisted of a qualitative assessment for the Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation reporting units and did not identify impairment indicators. Due to an impairment recorded in 2022 for the Gas Transmission reporting unit and the OEB decision on Phase 1 for Enbridge Gas, we performed a quantitative assessment for the Gas Transmission and Gas Distribution and Storage reporting units as at Dece

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES	12 Months Ended
CHANGES IN ACCOUNTING POLICIES	Dec. 31, 2023
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, 2023. FUTURE ACCOUNTING POLICY CHANGES Segment Reporting Accounting Standards Update (ASU) 2023-07 was issued in November 2023 to improve reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and to require in interim period financial statements all disclosures about a reportable segment's profit or loss and assets that are currently required annually. The new ASU requires entities to disclose the title and position of the individual or the name of the group or committee identified as the chief operating decision-maker (CODM) of each segment. ASU 2023-07 is effective January 1, 2024, with interim period disclosure requirements effective after January 1, 2025 and should be applied retrospectively to all prior periods presented in the financial statements. We are currently assessing the impact of the new standard on our consolidated financial statements. Income Tax Disclosures ASU 2023-09 was issued in December 2023 to improve income tax disclosures by requiring specified categories in the annual rate reconciliation that meet quantitative thresholds and further disaggregation on income taxes paid by jurisdiction. ASU 2023-09 is effective January 1, 2025 and should be applied prospectively, with retrospective application being permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

REVENUE

REVENUE	12 Months Ended
REVENUE	Dec. 31, 2023
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, 2023 (millions of Canadian dollars) Transportation revenue 11,875 5,302 814 — — — 17,991 Storage and other revenue 257 461 355 — — — 1,073 Gas distribution revenue — — 4,859 — — — 4,859 Electricity and transmission revenue — — — 259 — — 259 Commodity sales — 17 — — — — 17 Total revenue from contracts with customers 12,132 5,780 6,028 259 — — 24,199 Commodity sales — — — — 18,964 — 18,964 Other revenue 1,2 257 72 (58) 215 — — 486 Intersegment revenue 474 2 6 3 25 (510) — Total revenue 12,863 5,854 5,976 477 18,989 (510) 43,649 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 1 Includes realized and unrealized gains and losses 2 Includes revenues from lease contracts. Refer to Note 26 - 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, 2023 2,802 400 2,591 Balance as at December 31, 2022 3,183 230 2,241 Contract receivables represent the amount of receivables derived from contracts with customers. Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or have partially fulfilled) and prior to the point in time at which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional. Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the year ended December 31, 2023 included in contract liabilities at the beginning of the year is $246 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2023, were $632 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, 2023 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 $59.1 billion, of which $7.5 billion is expected to be recognized during the year ending December 31, 2024. 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 first six months of 2023, revenue for the Canadian Mainline was 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 continued on an interim basis until July 1, 2023 when revised interim tolls took effect. Until a new commercial arrangement is approved, the tolls are subject to finalization and adjustment applicable to the interim period, if any. Due to the uncertainty of adjustment to tolling pursuant to a CER decision and potential customer negotiations, interim toll revenue recognized during the year ended December 31, 2023 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, 2023 (millions of Canadian dollars) Revenue from products transferred at a point in time — 17 138 — 155 Revenue from products and services transferred over time 1 12,132 5,763 5,890 259 24,044 Total revenue from contracts with customers 12,132 5,780 6,028 259 24,199 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 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
SEGMENTED INFORMATION	Dec. 31, 2023
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION Year ended December 31, 2023 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Operating revenues (Note 4) 12,863 5,854 5,976 477 18,989 (510) 43,649 Commodity and gas distribution costs — (15) (2,871) (20) (18,975) 515 (21,366) Operating and administrative (4,629) (2,380) (1,285) (261) (52) 7 (8,600) Impairment of long-lived assets 1 145 — (281) (283) — — (419) Income/(loss) from equity investments (Note 13) 1,007 688 2 140 — (21) 1,816 Other income (Note 27) 113 117 51 96 1 846 1,224 Earnings/(loss) before interest, income taxes and depreciation and amortization 9,499 4,264 1,592 149 (37) 837 16,304 Depreciation and amortization (4,613) Interest expense (Note 17) (3,812) Income tax expense (Note 24) (1,821) Earnings 6,058 Capital expenditures 2 1,158 1,944 1,451 100 — 55 4,708 Total property, plant and equipment, net (Note 11) 51,851 31,016 18,766 2,706 4 298 104,641 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) Operating 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 15) — (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 27) 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 17) (3,179) Income tax expense (Note 24) (1,604) Earnings 2,938 Capital expenditures 2 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) Operating 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) 759 702 42 101 — (4) 1,600 Other income/(expense) (Note 27) 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 17) (2,655) Income tax expense (Note 24) (1,415) Earnings 6,314 Capital expenditures 2 4,051 2,420 1,343 16 1 54 7,885 Total property, plant and equipment, net 52,530 27,028 16,904 3,315 23 267 100,067 1 The Liquids Pipelines segment includes the impact of a gain resulting from the derecognition of a net regulatory liability due to the discontinuance of regulatory accounting for our Southern Lights Pipeline (Note 7). 2 Includes equity component of AFUDC. The measurement basis for preparation of segmented information is consistent with our significant accounting policies (Note 2) . GEOGRAPHIC INFORMATION Revenues 1 Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Canada 23,781 27,498 20,474 US 19,868 25,811 26,597 43,649 53,309 47,071 1 Revenues are based on the country of origin of the product or service sold. Property, Plant and Equipment 1 December 31, 2023 2022 (millions of Canadian dollars) Canada 48,570 47,602 US 56,071 56,858 104,641 104,460 1 Amounts are based on the location where the assets are held. Change in Reportable Segments Effective January 1, 2024, to better align how the CODM reviews operating performance and resource allocation across operating segments, we transferred our Canadian and US crude oil businesses from the Energy Services segment to the Liquids Pipelines segment. The Energy Services segment will cease to exist and the remainder of the business will be reported in the Eliminations and Other segment. Beginning in the first quarter of 2024, prior period comparable results for segmented information will be recast to reflect the change in reportable segments. This segment reporting change will have no impact on our consolidated results.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	12 Months Ended
EARNINGS PER COMMON SHARE	Dec. 31, 2023
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 as at December 31, 2021 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, 2023 2022 2021 (number of shares in millions) Weighted average shares outstanding 2,056 2,025 2,023 Effect of dilutive options and RSUs 2 4 2 Diluted weighted average shares outstanding 2,058 2,029 2,025 For the years ended December 31, 2023, 2022 and 2021, 19.3 million, 10.4 million and 18.6 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $54.42, $56.49 and $52.89, respectively, were excluded from the diluted earnings per common share calculation.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
REGULATORY MATTERS	Dec. 31, 2023
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 tax asset and the related earnings impact would not be recorded. LIQUIDS PIPELINES Canadian Mainline Canadian Mainline includes the Canadian portion of our Mainline system. The CTS which governed tolls paid for products shipped on the Canadian Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis, expired on June 30, 2021 at which point the tolls in place became interim. Enbridge has reached an agreement on a new negotiated settlement, the Mainline Tolling Settlement (MTS), for tolls on its Mainline System. The settlement is subject to regulatory approval and the term is seven and a half years through the end of 2028, with revised interim tolls effective on July 1, 2023. The MTS continues with the previous C TS framework with 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. We have recognized a regulatory asset of $1.9 billion as at December 31, 2023 (2022 - $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 MTS. During the year ended December 31, 2023, we wrote off $160 million related to regulatory tax assets and $40 million of regulatory deferred tax liabilities that are no longer probable to be flowed through future tolls. 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%. During the fourth quarter of 2023, Southern Lights Pipeline completed an open season to negotiate new transportation service agreements effective 2025. We do not expect to renew the agreements under a cost-of-service toll methodology, therefore Southern Lights Pipeline is no longer subject to rate-regulated accounting. As a result, $151 million of net regulatory liabilities, $92 million of regulatory tax assets and $23 million of regulatory deferred tax liabilities were derecognized in the year. GAS TRANSMISSION AND MIDSTREAM British Columbia (BC) Pipeline and Maritimes & Northeast Canada (M&N Canada) are regulated by the CER. Rates are approved by the CER through negotiated toll settlement agreements 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. The toll settlement agreement for M&N Canada expired in December 2023. M&N Canada reached a toll settlement with shippers for the effective period from January 1, 2024 to December 31, 2025. On November 28, 2023, M&N Canada filed the 2024 - 2025 toll settlement agreement with the CER for review and approval. A CER decision is expected in the first quarter of 2024. 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 gas commissions. 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, were set under a five-year Incentive Regulation (IR) framework using a price cap mechanism ending December 31, 2023. 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. On December 21, 2023, we received a decision from the OEB on Phase 1 of our 2024 - 2028 Incentive Regulation rate setting framework (Phase 1 Decision). The Phase 1 Decision established new interim rates effective January 1, 2024. In addition, the Phase 1 Decision resulted in the following items not approved for future recovery, and the subsequent impairments recognized for the year ended December 31, 2023: • a portion of undepreciated capital projects in Property, plant and equipment, net and Intangible assets, net were removed from 2024 rate base of $41 million; • undepreciated integration capital costs in Intangible assets, net were removed from 2024 rate base of $84 million; • pre-2017 Union Gas related pension balances in Deferred amounts and other assets of $156 million. 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, 2023 2022 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Purchase gas variance 15 190 2024 Under-recovery of fuel costs 75 109 2024 Other current regulatory assets 380 305 2024 Total current regulatory assets 1 (Note 9) 470 604 Long-term regulatory assets Deferred income taxes 2 4,456 4,473 Various Long-term debt 3 348 378 2032-2046 Negative salvage 4 180 265 Various Purchase gas variance — 244 2024 Accounting policy changes 5 — 219 2024 Pension plan receivable 6 1 40 Various Other long-term regulatory assets 252 244 Various Total long-term regulatory assets 1 5,237 5,863 Total regulatory assets 5,707 6,467 Current regulatory liabilities Purchase gas variance 31 — 2024 Other current regulatory liabilities 276 167 2024 Total current regulatory liabilities 7 307 167 Long-term regulatory liabilities Future removal and site restoration reserves 8 1,693 1,615 Various Regulatory liability related to US income taxes 9 854 918 2050-2072 Pipeline future abandonment costs (Note 23) 745 610 Various Pension plan payable 6 143 231 Various Other long-term regulatory liabilities 86 250 Various Total long-term regulatory liabilities 7 3,521 3,624 Total regulatory liabilities 3,828 3,791 1 Current regulatory assets are included in Other current assets, 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. The balance as at December 31, 2023 is net of regulatory deferred tax write-offs. 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 In 2022, this deferral primarily consisted 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. The Phase 1 Decision disallowed recovery of the remaining balance related to pre-2017 pension amounts and was impaired with a nil balance as at December 31, 2023. The residual balance in this account pertains to the impact of other accounting changes during the deferred rebasing period and were approved for disposition in 2024 in the Phase 1 Decision and subsequently transferred to Other current regulatory assets as at December 31, 2023. 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 Other current liabilities, 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
ACQUISITIONS AND DISPOSITIONS	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS ACQUISITIONS Aitken Creek Gas Storage On November 1, 2023, through a wholly-owned Canadian subsidiary, we acquired a 93.8% interest in Aitken Creek Gas Storage Facility and a 100% interest in Aitken Creek North Gas Storage Facility (collectively, Aitken Creek), located in BC, Canada, for $400 million, subject to other customary closing adjustments (the Aitken Creek Acquisition). Aitken Creek is the only underground natural gas storage facility in BC and connects to all major natural gas pipelines in western Canada. The Aitken Creek Acquisition enables us to continue to meet regional energy needs and to support increasing demand for liquefied natural gas (LNG) exports. We accounted for the Aitken Creek Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations . In accordance with valuation methodologies described in ASC 820 Fair Value Measurements , the acquired assets and assumed liabilities are recorded at their estimated fair values as at the date of acquisition. The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Aitken Creek: November 1, 2023 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 105 Property, plant and equipment (b) 466 Current liabilities 20 Long-term liabilities (c) 130 Goodwill (d) 46 Purchase price: Cash 397 Additional consideration (e) 70 467 a) Current assets consist primarily of inventory which is short-term in nature and represents natural gas held in storage. Fair value was determined using the market price of natural gas at the date of acquisition. b) Aitken Creek's property, plant and equipment constitutes an integrated system of cavern storage facilities, associated header pipeline, and land and right-of-ways. The depreciated replacement cost approach was adopted as the primary valuation methodology to determine the fair value of property, plant and equipment, excluding the reservoir storage asset. 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. Fair value of the reservoir storage asset was determined using a residual approach whereby the adjusted purchase price was allocated to the fair value of the net tangible assets, excluding the reservoir storage asset, with the remaining value allocated to the reservoir storage asset. The income approach was also utilized to corroborate that the cash flows attributable to the reservoir storage asset support the residual value. c) Long-term liabilities consist primarily of a deferred income tax liability arising from temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes at the date of acquisition. d) Goodwill is primarily attributable to the recognition of a deferred income tax liability. The goodwill balance recognized has been assigned to our Gas Transmission and Midstream segment and is not tax deductible. e) The $70 million of additional consideration recognized in the purchase price represents the fair value of derivative contracts and working gas as at March 31, 2023. Upon completion of the Aitken Creek Acquisition, we began consolidating Aitken Creek. For the period beginning November 1, 2023 through to December 31, 2023, operating revenues and earnings attributable to common shareholders generated by Aitken Creek were immaterial. The impact to our supplemental pro forma consolidated operating revenues and earnings attributable to common shareholders for the years ended December 31, 2023 and 2022, as if the Aitken Creek Acquisition had been completed on January 1, 2022, was also immaterial. Acquisitions of US Gas Utilities On September 5, 2023, we announced that Enbridge had entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina for an aggregate purchase price of $19.1 billion (US$14.0 billion), comprised of $12.8 billion (US$9.4 billion) of cash consideration and $6.3 billion (US$4.6 billion) of assumed debt, subject to customary closing adjustments (together, the Acquisitions). The Acquisitions are expected to close in 2024, subject to the satisfaction of customary closing conditions including the receipt of certain regulatory approvals, which are not cross-conditional. On September 8, 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions. We closed two offerings in September 2023 and four offerings in November 2023 for aggregate principal amounts of US$5.5 billion and $1.0 billion. The proceeds from the September 2023 offerings and a portion of the November 2023 offerings are intended to finance a portion of the aggregate cash consideration payable for the Acquisitions. Refer to Note 17 - Debt for further details on the debt issuances and credit facility obtained to support the Acquisitions. Tres Palacios Holdings LLC On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for $451 million (US$335 million) of cash. Tres Palacios is a natural gas storage facility located in the US Gulf Coast and its infrastructure serves Texas gas-fired power generation and LNG exports, as well as Mexico pipeline exports. We allocated assets with a fair value of $790 million (US$588 million) to Property, plant and equipment, net, of which $254 million (US$189 million) relates to storage cavern right-of-use assets, and recorded the related lease liabilities of $7 million (US$5 million) and $248 million (US$184 million) to Current portion of long-term debt and Long-term debt, respectively, in the Consolidated Statements of Financial Position. The acquired assets are included in our Gas Transmission and Midstream segment. 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). TGE is an onshore renewable project developer in the US with a development portfolio of wind and solar projects. The TGE Acquisition enhances Enbridge's renewable power platform and accelerates our North American growth strategy. We accounted for the TGE Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations . In accordance with valuation methodologies described in ASC 820 Fair Value Measurements , the acquired assets and assumed liabilities are recorded at their estimated fair values as at the date of acquisition. The following table summarizes the estimated fair values that were assigned to the net assets of TGE: September 27, 2022 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 5 Property, plant and equipment 3 Long-term investments 8 Intangible assets (a) 117 Long-term assets 3 Current liabilities 61 Long-term debt 18 Long-term liabilities (b) 105 Goodwill (c) 392 Purchase price: Cash 295 Contingent consideration (d) 49 344 a) Intangible assets consist of compensation expected to be earned by TGE on existing development contracts once certain project development milestones are met. Fair value was determined using a discounted cash flow method which is an income-based approach to valuation that estimates the present value of future projected benefits from the contracts. The intangible assets will be amortized on a straight-line basis over an expected useful life of three and a half years. b) Long-term liabilities consist primarily of obligations payable to third parties which are contingent on milestones being met for certain projects. Fair value represents the present value of the future cash flow payments at the date of the TGE Acquisition. c) Goodwill is primarily attributable to expected future returns from new opportunities to develop wind and solar projects, as well as enhanced scale and operational diversity of our renewable projects portfolio. The goodwill balance recognized has been assigned to our Renewable Power Generation segment and is tax deductible over 15 years. d) We agreed to pay additional contingent consideration of up to US$53 million to TGE's former common unit holders if performance milestones are met on certain projects. The US$36 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition. The fair value was determined using an income-based approach. Upon completion of the TGE Acquisition, we began consolidating TGE. For the period beginning September 27, 2022 through to 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). 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 year ended December 31, 2021, 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 (unaudited; millions of Canadian dollars) Operating revenues 47,339 Earnings attributable to common shareholders 1,2 5,771 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. 2 Includes the amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets of $193 million (after-tax of $145 million) for the year ended December 31, 2021. 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 19) . 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.

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
OTHER CURRENT ASSETS	Dec. 31, 2023
Receivables [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS December 31, 2023 2022 (millions of Canadian dollars) Derivative assets (Note 23) 623 1,015 Regulatory assets (Note 7) 470 604 Gas imbalances 209 461 Income taxes receivable 347 323 Other 791 852 2,440 3,255

INVENTORY

INVENTORY	12 Months Ended
INVENTORY	Dec. 31, 2023
Inventory Disclosure [Abstract]
INVENTORY	INVENTORY December 31, 2023 2022 (millions of Canadian dollars) Natural gas 938 1,491 Crude oil 413 652 Other 128 112 1,479 2,255

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
PROPERTY, PLANT AND EQUIPMENT	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Weighted Average December 31, Depreciation Rate 2023 2022 (millions of Canadian dollars) Pipelines 2.9 % 66,698 66,528 Facilities and equipment 3.1 % 37,634 37,028 Land and right-of-way 1 2.3 % 3,600 3,637 Gas mains, services and other 2.6 % 15,346 14,491 Storage 2.5 % 4,929 3,477 Wind turbines, solar panels and other 4.1 % 4,511 4,912 Other 10.1 % 1,652 1,611 Under construction — % 2,829 2,316 Total property, plant and equipment 137,199 134,000 Total accumulated depreciation (32,558) (29,540) Property, plant and equipment, net 104,641 104,460 1 The measurement of weighted average depreciation rate excludes non-depreciable assets. Depreciation expense for the years ended December 31, 2023, 2022 and 2021 was $4.0 billion, $3.8 billion and $3.5 billion, respectively. IMPAIRMENT Chapman Ranch Wind Farm Chapman Ranch Wind Farm (Chapman Ranch) is experiencing financial challenges associated with the original equipment integrity. As a result, we have recognized an impairment loss of $251 million for the year ended December 31, 2023, which is included in Impairment of long-lived assets in the Consolidated Statements of Earnings and is part of our Renewable Power Generation segment. Magic Valley Wind Farm In 2022, Magic Valley Wind Farm (Magic Valley) had 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 recognized an impairment loss of $227 million for the year ended December 31, 2022, 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 For the year ended December 31, 2022, we 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 Pipeline System in connection with the expiration of certain long-term take-or-pay contracts in 2023. This loss 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
VARIABLE INTEREST ENTITIES	Dec. 31, 2023
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, 2023 2022 (millions of Canadian dollars) Assets Cash and cash equivalents 442 426 Restricted cash 9 12 Trade receivables and unbilled revenue 144 185 Other current assets 8 14 Accounts receivable from affiliates 5 23 Inventory 11 12 619 672 Property, plant and equipment, net 7,105 7,707 Long-term investments 14 14 Restricted long-term investments 106 98 Deferred amounts and other assets 148 158 Intangible assets, net 84 102 8,076 8,751 Liabilities Trade payables and accrued liabilities 83 99 Other current liabilities 145 152 Accounts payable to affiliates 4 21 232 272 Long-term debt 1 — Other long-term liabilities 971 859 Deferred income taxes 5 5 1,209 1,136 6,867 7,615 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, 2023 and 2022 are presented below: Carrying Maximum December 31, 2023 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 105 130 Rampion Offshore Wind Limited 2 391 452 Vector Pipeline L.P. 3 191 320 Woodfibre LNG Limited Partnership 4 778 2,854 Fox Squirrel Solar LLC 5 312 661 Other 4 132 230 1,909 4,647 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. 6 37 637 Rampion Offshore Wind Limited 2 413 468 Vector Pipeline L.P. 3 195 325 Woodfibre LNG Limited Partnership 4 635 2,476 Other 4 245 443 1,616 4,466 1 As at December 31, 2023 and 2022, 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, 2023 and 2022, 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. 3 As at December 31, 2023 and 2022, the maximum exposure to loss includes the carrying value of outstanding affiliate loans receivable for $24 million and $25 million held by us as at December 31, 2023 and 2022, respectively, and an outstanding credit facility for $105 million as at December 31, 2023 and 2022. 4 As at December 31, 2023 and 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. 5 In November 2023, Enbridge acquired a 50% interest in Fox Squirrel JV, LLC (Fox Squirrel Solar LLC). Refer to Note 13 - Long-Term Investments. Fox Squirrel Solar LLC 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 Fox Squirrel Solar LLC's activities that most significantly impacts its economic performance. As at December 31, 2023, 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. 6 As at December 31, 2023, EIH S.á r.l no longer met the requirements of a VIE as a result of a VIE reconsideration event. As at December 31, 2022, 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. We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 2023 and 2022.

LONG-TERM INVESTMENTS

LONG-TERM INVESTMENTS	12 Months Ended
LONG-TERM INVESTMENTS	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
LONG-TERM INVESTMENTS	LONG-TERM INVESTMENTS Ownership December 31, Interest 2023 2022 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines MarEn Bakken Company LLC 1 75.0 % 1,819 1,968 DCP Midstream, LLC (Class B Units) 2 90.0 % 1,486 1,394 Seaway Crude Holdings LLC 50.0 % 2,661 2,744 Illinois Extension Pipeline Company, L.L.C. 3 65.0 % 584 622 Cactus II Pipeline LLC 4 30.0 % 618 658 Other 30.0% - 43.8% 84 76 Gas Transmission and Midstream Alliance Pipeline 5, 7 50.0 % 359 430 Aux Sable 6, 7 42.7% - 50.0% 229 214 DCP Midstream, LLC (Class A Units) 8 23.4 % 367 317 Gulfstream Natural Gas System, L.L.C. 50.0 % 1,224 1,274 NEXUS Gas Transmission, LLC 50.0 % 1,220 1,813 Sabal Trail Transmission, LLC 50.0 % 1,467 1,535 Southeast Supply Header, LLC 50.0 % 80 86 Steckman Ridge, LP 50.0 % 87 91 Vector Pipeline 9 60.0 % 191 195 Woodfibre LNG Limited Partnership 10 30.0 % 777 635 Offshore - various joint ventures 22.0% - 74.3% 217 314 Gas Distribution and Storage Other 30.0% - 50.0% 22 20 Renewable Power Generation EIH S.à r.l. 11 51.0 % 52 37 Hohe See and Albatros Offshore Wind Facilities 49.9 % 1,701 163 Rampion Offshore Wind Limited 24.9 % 391 413 East-West Tie Limited Partnership 24.1 % 132 241 Fox Squirrel Solar LLC 50.0 % 312 — Other 16.4% - 50.0% 110 107 OTHER LONG-TERM INVESTMENTS Gas Transmission and Midstream Ara Divert HoldCo, Inc. 106 — Other 22 22 Gas Distribution and Storage Other 24 48 Renewable Power Generation Other 21 31 Eliminations and Other Other 12 430 488 16,793 15,936 1 Owns a 49.0% interest in Bakken Pipeline Investments LLC. Bakken Pipeline Investments LLC 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. On January 9, 2023, we acquired an additional 10.0% direct interest in Gray Oak for cash consideration of $230 million (US$172 million), bringing our effective interest to 68.5%. 3 Owns the Southern Access Extension Project. 4 On October 12, 2021, we acquired a 20.0% equity interest in Cactus II through the Moda Acquisition (Note 8). On November 2, 2022, we acquired an additional 10.0% ownership in Cactus II for cash consideration 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 L.P. and Aux Sable Midstream LLC in the US. 7 On December 13, 2023, we announced that Enbridge had entered into a definitive agreement to sell its 50.0% interest in the Alliance Pipeline and interest in Aux Sable to Pembina Pipeline Corporation for $3.1 billion, including approximately $0.3 billion of non-recourse debt, subject to customary closing adjustments. 8 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. 9 Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US. 10 On November 29, 2022, we acquired an effective 30.0% interest in Woodfibre LNG Limited Partnership (Woodfibre) for cash consideration of $533 million (US$392 million). Woodfibre will operate a LNG export facility in BC being constructed by us and our partners. 11 Owns a 50.0% interest in Éolien Maritime France SAS (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%). 12 Consists of investments in exchange-traded funds and debt securities held by our wholly-owned captive insurance subsidiaries. Refer to Note 23 - 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, 2023, this basis difference was $3.5 billion (2022 - $3.4 billion), of which $1.7 billion (2022 - $1.5 billion) was amortizable. For the years ended December 31, 2023, 2022 and 2021, distributions received from equity investments were $3.1 billion, $2.6 billion and $2.2 billion, respectively. Summarized combined financial information of our unconsolidated equity investments (presented at 100%) is as follows: Year ended December 31, 2023 2022 1 2021 1 (millions of Canadian dollars) Operating revenues 22,586 30,026 22,551 Operating expenses 17,111 23,835 17,446 Earnings 4,818 5,123 3,656 Earnings attributable to Enbridge 1,816 2,056 1,600 December 31, 2023 2022 1 (millions of Canadian dollars) Current assets 5,842 5,328 Non-current assets 61,141 61,393 Current liabilities 6,194 5,631 Non-current liabilities 23,957 23,208 Noncontrolling interests 4,124 4,640 1 Balances have been updated to reflect the impact of revisions made to conform to the current year's presentation. These revisions do not have an effect on our previously reported consolidated statements of earnings, comprehensive income, changes in equity, cash flows or financial position. OTHER EQUITY INVESTMENT TRANSACTIONS Fox Squirrel Solar LLC On November 15, 2023, we acquired a 50% interest in a newly formed partnership with EDF Renewables North America to participate in the initial phase of a solar power facility in Ohio. Cash consideration includes an upfront payment of $157 million (US$115 million) and subsequent capital commitments up to $398 million (US$291 million). Investments past the first phase are contingent on certain conditions being met. An additional payment of $164 million (US$123 million) was made at Phase 1 in-service in December 2023. Hohe See and Albatros Offshore Wind Facilities On November 3, 2023, we acquired an additional 24.45% interest in the Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities (the Offshore Wind Facilities), through the acquisition of a 49% interest in Enbridge Renewable Infrastructure Investments S. à r.l (ERII), for $391 million (€267 million) of cash and assumed debt of $524 million (€358 million), bringing our interest in the Offshore Wind Facilities to 49.9%. The Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities are located approximately 100 kilometers off the northern coast of Germany and came into service in 2019 and 2020, respectively. Subsequent to the purchase, our interest in ERII is consolidated and our interest in the Offshore Wind Facilities will continue to be accounted for as an equity method investment included in the Renewable Power Generation segment. DCP Midstream, LLC On August 17, 2022, we completed a joint venture merger transaction with Phillips 66 resulting in a single joint venture, DCP Midstream, LLC, holding both our and Phillips 66's indirect ownership interests in Gray Oak 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 assumed operatorship of Gray Oak in the second quarter of 2023. We determined the fair value of our decrease in economic interest in DCP based on the unadjusted quoted market price of DCP's publicly traded common units on the transaction closing date. The fair value of our increased economic interest in Gray Oak was determined using the fair value prescribed to the change in our economic interest in DCP. As a result of the merger transaction and the realignment of our economic interests in DCP and Gray Oak, we also received cash consideration of approximately $522 million (US$404 million) and recorded an accounting gain of $1.1 billion (US$832 million) to Gain on joint venture merger transaction in the Consolidated Statements of Earnings. Both DCP and Gray Oak continue to be accounted for as equity method investments. 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 was nil as at December 31, 2023 and 2022. Our investment in PennEast formed part of our Gas Transmission and Midstream segment. The impairment loss was recorded within Income from equity investments in the Consolidated Statements of Earnings.

INTANGIBLE ASSETS

INTANGIBLE ASSETS	12 Months Ended
INTANGIBLE ASSETS	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
INTANGIBLE ASSETS	INTANGIBLE ASSETS December 31, 2023 Weighted Average Amortization Rate Cost Accumulated Amortization Net (millions of Canadian dollars) Software 12.0 % 1,921 (1,090) 831 Power purchase agreements 4.3 % 58 (24) 34 Project agreement 1 4.0 % 158 (41) 117 Customer relationships 8.6 % 2,636 (675) 1,961 Other intangible assets 8.2 % 603 (185) 418 Under development — % 176 — 176 5,552 (2,015) 3,537 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 1 Represents a project agreement acquired from the merger of Enbridge and Spectra Energy. For the years ended December 31, 2023, 2022 and 2021, our amortization expense related to intangible assets totaled $535 million, $483 million and $348 million, respectively. Our expected amortization expense associated with existing intangible assets for each of the years 2024 to 2028 is $514 million.

GOODWILL

GOODWILL	12 Months Ended
GOODWILL	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL Liquids Gas Gas Renewable Power Generation Energy Consolidated (millions of Canadian dollars) Balance at January 1, 2022 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 3 — — — 392 — 392 Balance at December 31, 2022 1,2 8,547 18,106 5,397 388 2 32,440 Foreign exchange and other (205) (425) — (8) — (638) Acquisition 4 — 46 — — — 46 Balance at December 31, 2023 1,2 8,342 17,727 5,397 380 2 31,848 1 Gross goodwill as at December 31, 2023 and 2022 was $35.9 billion and $36.5 billion, respectively. 2 Accumulated impairment as at December 31, 2023 and 2022 was $4.1 billion. 3 In 2022, we recorded $392 million of goodwill related to the acquisition of TGE. Refer to Note 8 - Acquisitions and Dispositions . 4 In 2023, we recorded $46 million of goodwill related to the acquisition of Aitken Creek. 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. No impairment was recorded for the year ended December 31, 2023.

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES	12 Months Ended
OTHER CURRENT LIABILITIES	Dec. 31, 2023
Payables and Accruals [Abstract]
OTHER LONG-TERM LIABILITIES	OTHER CURRENT LIABILITIES December 31, 2023 2022 (millions of Canadian dollars) Dividends payable 1,975 1,825 Deferred credits 1,313 1,056 Derivative liabilities (Note 23) 738 898 Taxes payable 596 683 Other 1,037 758 5,659 5,220

DEBT

DEBT	12 Months Ended
DEBT	Dec. 31, 2023
Debt Disclosure [Abstract]
DEBT	DEBT December 31, Weighted Average Interest Rate 10 Maturity 2023 2022 (millions of Canadian dollars) Enbridge Inc. US dollar senior notes 4.6 % 2024 - 2053 14,636 12,060 Medium-term notes 4.5 % 2024 - 2064 8,598 8,223 Sustainability-linked bonds 4.7 % 2032 - 2033 6,751 3,355 Fixed-to-fixed subordinated term notes 1 7.5 % 2080 - 2084 7,156 3,596 Fixed-to-floating rate subordinated term notes 2 5.8 % 2077 - 2078 5,828 6,736 Floating rate notes 3 2024 791 1,491 Fixed-to-floating non-call notes 6.0 % 2026 923 — Commercial paper and credit facility draws 4.7 % 2024 - 2028 3,177 7,984 Other 4 17 15 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 5.6 % 2025 - 2028 670 4,199 Other 4 263 7 Enbridge Energy Partners, L.P. Senior notes 6.5 % 2025 - 2045 3,231 3,320 Enbridge Gas Inc. Medium-term notes 4.2 % 2024 - 2053 10,185 9,535 Debentures 9.1 % 2024 - 2025 210 210 Commercial paper and credit facility draws 5.2 % 2025 400 2,000 Other 4 2 1 Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 4.0 % 2040 791 921 Enbridge Pipelines Inc. Medium-term notes 5 4.3 % 2024 - 2053 5,425 5,425 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 5.4 % 2025 449 312 Other 4 4 — Enbridge Southern Lights LP Senior notes 4.0 % 2040 214 222 Spectra Energy Capital, LLC Senior notes 7.0 % 2032 - 2038 228 234 Algonquin Gas Transmission, LLC Senior notes 3.3 % 2024 - 2029 1,121 1,152 East Tennessee Natural Gas, LLC Senior notes 3.1 % 2024 251 258 Texas Eastern Transmission, LP Senior notes 4.7 % 2028 - 2048 3,362 3,455 Spectra Energy Partners, LP Senior notes 4.3 % 2024 - 2045 4,220 4,336 Tri Global Energy, LLC Senior notes — 18 Blauracke GmbH 6 Senior notes 2.1 % 2032 521 — Westcoast Energy Inc. Medium-term notes 4.9 % 2024 - 2041 1,225 1,225 Debentures 8.1 % 2025 - 2026 275 275 Fair value adjustment 514 608 Other 7 (439) (393) Total debt 8 81,199 80,980 Current maturities (6,084) (6,045) Short-term borrowings 9 (400) (1,996) Long-term debt 74,715 72,939 1 For an initial five 2 For an initial five 3 The notes carry an interest rate equal to 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 In November 2023, as a part of the acquisition of an additional 49% interest in ERII, we assumed debt of $524 million (€358 million). As at December 31, 2023 $61 million (€42 million) and $460 million (€316 million) are recorded within Current portion of long-term debt and Long-term debt, respectively, on the Consolidated Statements of Financial Position. Refer to Note 13 - Long-Term Investments for further details on the transaction. 7 Primarily unamortized discounts, premiums and debt issuance costs. 8 2023 - $37 billion, US$33 billion and €359 million; 2022 - $38 billion, US$31 billion and nil. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment. 9 Weighted average interest rates on outstanding commercial paper were 5.2% as at December 31, 2023 (2022 - 4.5%). 10 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2023. As at December 31, 2023, all outstanding debt was unsecured. CREDIT FACILITIES The following table provides details of our committed credit facilities as at December 31, 2023: Maturity 1 Total Facilities Draws 2 Available (millions of Canadian dollars) Enbridge Inc. 2024-2028 8,876 3,177 5,699 Enbridge (U.S.) Inc. 2025-2028 8,373 670 7,703 Enbridge Pipelines Inc. 2025 2,000 449 1,551 Enbridge Gas Inc. 2025 2,500 400 2,100 Total committed credit facilities 21,749 4,696 17,053 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. In March 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to 2.5 billion and in July 21, 2023, the facility's maturity date was extended to July 2025, which includes a one-year term out provision from July 2024. In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024. In July 2023, we renewed approximately $6.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2025, which includes a one-year term out provision from July 2024. We also renewed approximately $7.6 billion of our five-year credit facilities, extending the maturity dates to July 2028. Further, we extended our three-year credit facilities, extending the maturity dates to July 2026. In September 2023, we obtained commitments for a US$9.4 billion senior unsecured bridge term loan credit facility to support the Acquisitions. The commitment for this facility was subsequently reduced to nil as at December 31, 2023 as a result of the September 2023 $4.6 billion equity offering, the September 2023 subordinated long-term debt issuances, and the November 2023 senior notes long-term debt issuances. In addition to the committed credit facilities noted above, we maintain $1.1 billion of uncommitted demand letter of credit facilities, of which $572 million was unutilized as at December 31, 2023. As at December 31, 2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $689 million was unutilized. Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2024 to 2028. As at December 31, 2023 and 2022, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $3.8 billion and $10.5 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt. LONG-TERM DEBT ISSUANCES During the year ended December 31, 2023, we completed the following long-term debt issuances totaling US$8.5 billion and $3.9 billion: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. March 2023 5.70% sustainability-linked senior notes due March 2033 1 US$2,300 March 2023 5.97% senior notes due March 2026 2 US$700 May 2023 4.90% medium-term notes due May 2028 $600 May 2023 5.36% sustainability-linked medium-term notes due May 2033 3 $400 May 2023 5.76% medium-term notes due May 2053 $500 September 2023 8.50% fixed-to-fixed subordinated notes due January 2084 4 US$1,250 September 2023 8.25% fixed-to-fixed subordinated notes due January 2084 5 US$750 September 2023 8.75% fixed-to-fixed subordinated notes due January 2084 6 $700 September 2023 8.50% fixed-to-fixed subordinated notes due January 2084 7 $300 November 2023 5.90% senior notes due November 2026 US$750 November 2023 6.00% senior notes due November 2028 US$750 November 2023 6.20% senior notes due November 2030 US$750 November 2023 6.70% senior notes due November 2053 US$1,250 Enbridge Gas Inc. October 2023 5.46% medium-term notes due October 2028 $250 October 2023 5.70% medium-term notes due October 2033 $400 October 2023 5.67% medium-term notes due October 2053 $350 Enbridge Pipelines Inc. August 2023 5.82% medium-term notes due August 2053 $350 1 The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on September 8, 2031, the interest rate will be set to equal 5.70% plus 50 basis points. 2 We have the option to call the notes at par after one year from issuance. Refer to Note 23 - Risk Management and Financial Instruments . 3 The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on November 26, 2031, the interest rate will be set to equal 5.36% plus 50 basis points. 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 4.43%. Subsequent to year 10, every five years, the Five-year US treasury rate is reset. At year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.18%. 5 For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 3.79%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 4.04%. Subsequent to year 10, every five years, the Five-Year US Treasury rate is reset. At year 25, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.79%. 6 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 4.96%. Subsequent to year 10, every five years, the Government of Canada bond yield rate is reset. At year 30, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 5.71%. 7 For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.30%. At year 10, the interest rate will be reset to equal the Five-Year Government of Canada bond yield plus a margin of 4.55%. Subsequent to year 10, every five years, the Five-Year Government of Canada bond yield is reset. At year 25, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 5.30%. LONG-TERM DEBT REPAYMENTS During the year ended December 31, 2023, we completed the following long-term debt repayments totaling $1.4 billion and US$2.5 billion, respectively: Company Repayment Date Principal Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. January 2023 3.94% medium-term notes $275 February 2023 Floating rate notes 1 US$500 April 2023 6.38% fixed-to-floating rate subordinated notes 2 US$600 June 2023 3.94% medium-term notes $450 October 2023 4.00% senior notes US$800 October 2023 0.55% senior notes US$500 Enbridge Gas Inc. July 2023 6.05% medium-term notes $100 July 2023 3.79 % medium-term notes $250 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2023 3.98% senior notes US$80 Enbridge Pipelines Inc. August 2023 3.79% medium-term notes $250 November 2023 6.35% medium-term notes $100 Enbridge Southern Lights LP June 2023 4.01% senior notes $9 Tri Global Energy, LLC January 2023 10.00% senior notes US$4 January 2023 14.00% senior notes US$9 1 Notes carried an interest rate set to equal the SOFR plus a margin of 40 basis points. 2 The five-year callable notes, with an original maturity date of April 2078, were all redeemed at par. 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, 2023, we were in compliance with all debt covenants. ANNUAL DEBT MATURITIES As at December 31, 2023, 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 80,438 6,067 6,405 5,630 3,377 5,307 53,652 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. INTEREST EXPENSE Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Debentures and term notes 3,439 2,910 2,806 Commercial paper and credit facility draws 519 388 114 Amortization of fair value adjustment (45) (45) (50) Capitalized interest (101) (74) (215) 3,812 3,179 2,655

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
ASSET RETIREMENT OBLIGATIONS	Dec. 31, 2023
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 years ended December 31, 2023 and 2022 ranged from 1.5% to 9.0%. A reconciliation of movements in our ARO liabilities is as follows: December 31, 2023 2022 (millions of Canadian dollars) Obligations at beginning of year 488 502 Liabilities acquired 1 — Liabilities incurred — 30 Liabilities settled (23) (126) Change in estimate and other 5 51 Foreign currency translation adjustment (6) 24 Accretion expense 28 7 Obligations at end of year 493 488 Presented as follows: Other current liabilities 136 83 Other long-term liabilities 357 405 493 488

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	12 Months Ended
NONCONTROLLING INTERESTS	Dec. 31, 2023
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, 2023 2022 (millions of Canadian dollars) Algonquin Gas Transmission, LLC 384 400 Enbridge Athabasca Midstream Investor Limited Partnership 1 1,086 1,106 Maritimes & Northeast Pipeline, L.L.C. 559 582 Renewable energy assets 885 1,302 Maritimes & Northeast Pipeline Limited Partnership 111 117 Other 4 4 3,029 3,511 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 .

SHARE CAPITAL

SHARE CAPITAL	12 Months Ended
SHARE CAPITAL	Dec. 31, 2023
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 2023 2022 2021 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 2,025 64,760 2,026 64,799 2,026 64,768 Shares issued, net of issue costs 103 4,485 — — — — Shares issued on exercise of stock options — 3 2 53 — 31 Shares issued on vesting of RSUs, net of tax — 12 — — — — Share purchases at stated value 1 (3) (80) (3) (88) — — Other — — — (4) — — Balance at end of year 2,125 69,180 2,025 64,760 2,026 64,799 1 Reflects the repurchase and cancellation of common shares under our normal course issuer bid. PREFERENCE SHARES 2023 2022 2021 December 31, Number of Shares Amount Number of Shares Amount Number 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 20 500 18 457 Preference Shares, Series C 1 — — — — 2 43 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 18 454 20 500 20 500 Preference Shares, Series G 2 2 46 — — — — Preference Shares, Series H 12 291 14 350 14 350 Preference Shares, Series I 3 2 59 — — — — Preference Shares, Series J 4 — — — — 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 5 — — — — 30 750 Preference Shares, Series 19 20 500 20 500 20 500 Issuance costs (135) (135) (155) Balance at end of year 6,818 6,818 7,747 1 On June 1, 2022, all outstanding Preference Shares, Series C were converted to Preference Shares, Series B. 2 On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G. 3 On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I. 4 On June 1, 2022, we redeemed our US$200 million outstanding Cumulative Redeemable Preference Shares, Series J. 5 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 5.20 % $1.30052 $25 June 1, 2027 Series C Preference Shares, Series D 5 5.41 % $1.35300 $25 March 1, 2028 Series E Preference Shares, Series F 6 5.54 % $1.38452 $25 June 1, 2028 Series G Preference Shares, Series G 7 6.96 % $1.90704 $25 June 1, 2028 Series F Preference Shares, Series H 8 6.11 % $1.52800 $25 September 1, 2028 Series I Preference Shares, Series I 9 7.19 % $1.81004 $25 September 1, 2028 Series H Preference Shares, Series L 5.86 % US$1.46448 US$25 September 1, 2027 Series M Preference Shares, Series N 10 6.70 % $1.67400 $25 December 1, 2028 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 11 6.70 % US$1.67592 US$25 June 1, 2028 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 12 6.21 % $1.55300 $25 March 1, 2028 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. Preference Shares, Series G and I contain a feature where the dividend rate resets on a quarterly basis. 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 Per Share Base Redemption Value 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 Per Share Base Redemption Value. 4 With the exception of Preference Shares, Series A, after the Redemption and Conversion Option Date, 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 D was increased to $0.33825 from $0.27875 on March 1, 2023 due to reset of the annual dividend on March 1, 2023. 6 The quarterly dividend per share paid on Preference Shares, Series F was increased to $0.34613 from $0.29306 on June 1, 2023 due to reset of the annual dividend on June 1, 2023. 7 On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G. The quarterly dividend per share paid on Preference Shares, Series G was increased to $0.47676 from $0.47245 on December 1, 2023 due to reset on a quarterly basis. 8 The quarterly dividend per share paid on Preference Shares, Series H was increased to $0.38200 from $0.27350 on September 1, 2023 due to reset of the annual dividend on September 1, 2023. 9 On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I. The quarterly dividend per share paid on Preference Shares, Series I was increased to $0.45251 from $0.44814 on December 1, 2023 due to reset on a quarterly basis following the date of issuance. 10 The quarterly dividend per share paid on Preference Shares, Series N was increased to $0.41850 from $0.31788 on December 1, 2023 due to reset of the annual dividend on December 1, 2023. 11 The quarterly dividend per share paid on Preference Shares, Series 1 was increased to US$0.41898 from US$0.37182 on June 1, 2023 due to reset of the annual dividend on June 1, 2023. 12 The quarterly dividend per share paid on Preference Shares, Series 19 was increased to $0.38825 from $0.30625 on March 1, 2023 due to reset of the annual dividend on March 1, 2023. 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
STOCK OPTION AND STOCK UNIT PLANS	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
STOCK OPTION AND STOCK UNIT PLANS	STOCK OPTION AND STOCK UNIT PLANS We maintain three primary vehicles under our long-term incentive plan (the Plan): ISOs, PSUs and RSUs. Total stock-based compensation expense recorded for the years ended December 31, 2023, 2022 and 2021 was $154 million, $260 million and $157 million, respectively. The number of common shares authorized for share-settled awards under the Plan was 181 million as at December 31, 2023, 2022 and 2021. 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, 2023 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (number of options in thousands; weighted average exercise price in Canadian dollars; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 27,624 48.46 Options granted 3,053 53.11 Options exercised 1 (648) 45.70 Options cancelled or expired (1,300) 53.84 Options outstanding at end of year 28,729 50.79 5.3 45 Options vested at end of year 2 20,235 50.64 4.1 36 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2023, 2022 and 2021 was $2 million, $66 million and $24 million, respectively, and cash received on exercise was nil, $3 million and $2 million, respectively. 2 The total fair value of ISOs vested during the years ended December 31, 2023, 2022 and 2021 was $20 million, $21 million and $25 million, respectively. Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton model are as follows: Year ended December 31, 2023 2022 2021 Fair value per option (Canadian dollars) 1 6.05 5.07 4.10 Valuation assumptions Expected option term (years) 2 6 6 6 Expected volatility 3 22.2 % 21.9 % 25.5 % Expected dividend yield 4 6.7 % 6.5 % 7.6 % Risk-free interest rate 5 3.5 % 1.8 % 0.7 % 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 value per option for the years ended December 31, 2023, 2022 and 2021 were $5.38, $4.78 and $3.91, respectively, for Canadian employees and US$5.23, US$4.62 and US$3.65, 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, 2023, 2022 and 2021 for ISOs was $18 million, $15 million and $16 million, respectively. As at December 31, 2023, unrecognized compensation expense related to non-vested ISOs was $11 million. The expense is expected to be fully recognized over a weighted average period of approximately two years. PERFORMANCE STOCK UNITS PSUs are granted to certain key employees where 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 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. Beginning in 2023, the performance multiplier also includes a greenhouse gas reduction component. To calculate the 2023 expense, a multiplier of 1.0 was used for 2023 PSU grants, 1.25 for 2022 PSU grants and 1.25 for the 2021 PSU grants. December 31, 2023 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (number of units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 3,249 Units granted 2,128 Units cancelled (214) Units matured 1 (2,218) Dividend reinvestment 235 Units outstanding at end of year 3,180 1.1 175 1 The total amount paid during the years ended December 31, 2023, 2022 and 2021 for PSUs was $123 million, $90 million and $70 million, respectively. Compensation expense recorded for the years ended December 31, 2023, 2022 and 2021 for PSUs was $59 million, $169 million and $56 million, respectively. As at December 31, 2023, unrecognized compensation expense related to non-vested PSUs was $54 million. The expense is expected to be fully recognized over a weighted average period of approximately two years. RESTRICTED STOCK UNITS Employees may also be granted cash-settled or share-settled RSUs under the Plan. Cash-settled RSUs are paid to certain key employees, vesting in equal installments on each of the first, second and third anniversaries of the grant date. Share-settled awards are given to non-executive senior management employees and vest following a three-year maturity period. Beginning in 2023, share-settled units were granted to non-senior management employees. These units vest on each of the first, second and third anniversaries of the grant date. RSU holders receive cash or shares equal to Enbridge's weighted average share price for 20 days prior to the maturity of the grant multiplied by the number of units outstanding on the maturity date. December 31, 2023 Number Weighted Average Grant Date Fair Value 2 Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (number of units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 3,565 49.64 Units granted 1,373 52.05 Units cancelled (246) 52.06 Units matured 1 (1,401) 51.05 Dividend reinvestment 280 50.88 Units outstanding at end of year 3,571 50.69 0.9 177 1 The total amount paid during the years ended December 31, 2023, 2022 and 2021 for RSUs was $56 million, $32 million and $72 million, respectively. 2 Weighted average grant date fair value excludes cash-settled units. Compensation expense recorded for the years ended December 31, 2023, 2022 and 2021 for RSUs was $77 million, $76 million and $85 million, respectively. As at December 31, 2023, unrecognized compensation expense related to non-vested RSUs was $60 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.

COMPONENTS OF ACCUMULATED OTHER

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	12 Months Ended
COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	Dec. 31, 2023
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) Changes in AOCI attributable to our common shareholders for the years ended December 31, 2023, 2022 and 2021 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, 2023 121 (35) (1,137) 4,348 5 218 3,520 Other comprehensive income/(loss) retained in AOCI 232 62 409 (1,695) 6 (158) (1,144) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 28 — — — — — 28 Foreign exchange contracts 2 — (47) — — — — (47) Amortization of pension and OPEB actuarial gain 3 — — — — — (24) (24) 260 15 409 (1,695) 6 (182) (1,187) Tax impact Income tax on amounts retained in AOCI (47) (14) — — — 28 (33) Income tax on amounts reclassified to earnings (14) 11 — — — 6 3 (61) (3) — — — 34 (30) Balance as at December 31, 2023 320 (23) (728) 2,653 11 70 2,303 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 (income)/loss reclassified to earnings Interest rate contracts 1 186 — — — — — 186 Foreign exchange contracts 2 (4) — — — — — (4) Other contracts 4 4 — — — — — 4 Amortization of pension and OPEB actuarial gain 3 — — — — — (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 (income)/loss reclassified to earnings Interest rate contracts 1 296 — — — — — 296 Commodity contracts 5 1 — — — — — 1 Foreign exchange contracts 2 5 — — — — — 5 Other contracts 4 2 — — — — — 2 Equity investment disposal — — — — (66) — (66) Amortization of pension and OPEB actuarial loss and prior service costs 3 — — — — — 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) 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 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. 4 Reported within Operating and administrative 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
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS MARKET RISK Our earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risks). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk We generate certain revenues, incur expenses and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in US dollar-denominated investments and subsidiaries using foreign currency derivatives and US dollar-denominated debt. The foreign exchange risks inherent within the CTS framework are not present in MTS. Accordingly, our foreign exchange hedging program related to the Canadian Mainline is no longer required, and the related derivatives were terminated in the first quarter of 2023 for a realized loss of $638 million. Interest Rate Risk Our earnings, cash flows and OCI are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors' approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps and costless collars. These swaps have an average fixed rate of 4.1%. On March 8, 2023, we issued US$700 million of three-year fixed rate notes, which include the right for us to call at par after the first year. A corresponding fixed-to-floating cancellable swap was also executed which gives the swap counterparty a similar right to cancel the swap after the first year. This swap has a fixed rate of 6.0%. Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via execution of floating-to-fixed interest rate swaps with an average swap rate of 3.5%. Commodity Price Risk Our earnings, cash flows and OCI 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 the revaluation of outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, RSUs. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk. TOTAL DERIVATIVE INSTRUMENTS We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. (ISDA) agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances. The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments, as well as the maximum potential settlement amounts, in the event of the specific circumstances described above. All amounts are presented gross in the Consolidated Statements of Financial Position. December 31, 2023 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) Other current assets Foreign exchange contracts — 41 98 139 (32) 107 Interest rate contracts 31 — 34 65 (32) 33 Commodity contracts — — 418 418 (270) 148 Other contracts — — 1 1 (1) — 31 41 551 623 (335) 288 Deferred amounts and other assets Foreign exchange contracts — 16 319 335 (122) 213 Interest rate contracts 51 — 2 53 (21) 32 Commodity contracts — — 75 75 (41) 34 51 16 396 463 (184) 279 Other current liabilities Foreign exchange contracts — (44) (84) (128) 32 (96) Interest rate contracts (183) — (3) (186) 32 (154) Commodity contracts (11) — (412) (423) 270 (153) Other contracts — — (1) (1) 1 — (194) (44) (500) (738) 335 (403) Other long-term liabilities Foreign exchange contracts — (17) (481) (498) 122 (376) Interest rate contracts (3) — (85) (88) 21 (67) Commodity contracts (7) — (159) (166) 41 (125) (10) (17) (725) (752) 184 (568) Total net derivative liability Foreign exchange contracts — (4) (148) (152) — (152) Interest rate contracts (104) — (52) (156) — (156) Commodity contracts (18) — (78) (96) — (96) Other contracts — — — — — — (122) (4) (278) (404) — (404) December 31, 2022 Derivative Derivative Instruments Used as Fair Value Hedges Non- Total Gross Amounts Total Net Derivative Instruments (millions of Canadian dollars) Other current assets Foreign exchange contracts — — 46 46 (41) 5 Interest rate contracts 649 — 11 660 — 660 Commodity contracts — — 302 302 (182) 120 Other contracts — — 7 7 — 7 649 — 366 1,015 (223) 792 Deferred amounts and other assets Foreign exchange contracts — 156 153 309 (138) 171 Interest rate contracts 254 — — 254 — 254 Commodity contracts — — 61 61 (25) 36 Other contracts 1 — 2 3 — 3 255 156 216 627 (163) 464 Other current liabilities Foreign exchange contracts — (42) (524) (566) 41 (525) Commodity contracts (48) — (284) (332) 182 (150) (48) (42) (808) (898) 223 (675) Other long-term liabilities Foreign exchange contracts — — (1,116) (1,116) 138 (978) Interest rate contracts (3) — (1) (4) — (4) Commodity contracts (37) — (133) (170) 25 (145) (40) — (1,250) (1,290) 163 (1,127) Total net derivative asset/(liability) Foreign exchange contracts — 114 (1,441) (1,327) — (1,327) Interest rate contracts 900 — 10 910 — 910 Commodity contracts (85) — (54) (139) — (139) Other contracts 1 — 9 10 — 10 816 114 (1,476) (546) — (546) The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments: 2023 2022 As at December 31, 2024 2025 2026 2027 2028 Thereafter Total Total Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) 1,360 500 — — — 1,860 2,155 Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) 6,582 5,327 4,697 4,091 3,162 888 24,747 27,610 Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) 30 30 28 32 — — 120 149 Foreign exchange contracts - Euro forwards - sell (millions of Euro) 141 126 121 81 67 195 731 697 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) — 84,800 — — — — 84,800 84,800 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 5,903 1,881 1,122 74 25 13 9,018 9,356 Interest rate contracts - short-term debt receive fixed rate (millions of Canadian dollars) 918 923 174 — — — 2,015 — Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 1 4,582 580 — — — — 5,162 7,851 Interest rate contracts - costless collar (millions of Canadian dollars) — 1,098 41 — — — 1,139 — Equity contracts (millions of Canadian dollars) 34 13 — — — — 47 80 Commodity contracts - natural gas (billions of cubic feet) 31 32 13 10 — — 86 93 Commodity contracts - crude oil (millions of barrels) 6 — — — — — 6 16 Commodity contracts - power (megawatt per hour (MW/H)) 49 (14) (26) (53) (57) (30) (22) 2 (14) 2 1 Represents the notional of long-term debt issuances hedged 2 Total is an average net purchase/(sale) of power. Derivatives Designated as Fair Value Hedges The following table presents foreign exchange derivative instruments that are designated and qualify as fair value hedges, the realized and unrealized 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, 2023 2022 (millions of Canadian dollars) Unrealized gain/(loss) on derivative (132) 262 Unrealized gain/(loss) on hedged item 131 (254) Realized loss on derivative (47) (110) Realized gain on hedged item — 85 The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income The following table presents the effect of cash flow hedges and fair value hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes: Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts — 3 (29) Interest rate contracts 201 1,151 252 Commodity contracts 68 (53) (28) Other contracts (2) (4) 1 Fair value hedges Foreign exchange contracts 15 (35) (5) 282 1,062 191 Amount of loss reclassified from AOCI to earnings Foreign exchange contracts 1 — 13 5 Interest rate contracts 2 28 186 296 Commodity contracts 3 — — 1 Other contracts 3 — 4 2 28 203 304 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 loss of $18 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 2 years as at December 31, 2023. Non-Qualifying Derivatives The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Foreign exchange contracts 1 1,292 (1,344) 92 Interest rate contracts 2 (63) 10 2 Commodity contracts 3 (41) 50 71 Other contracts 4 (8) 4 8 Total unrealized derivative fair value gain/(loss), net 1,180 (1,280) 173 1 For the respective years ended, reported within Transportation and other services revenues (2023 - $645 million gain; 2022 - $238 million loss; 2021 - $98 million gain) and Other income/(expense) (2023 - $647 million gain; 2022 - $1,106 million loss; 2021 - $6 million loss) in the Consolidated Statements of Earnings. 2 Reported as an increase within Interest expense in the Consolidated Statements of Earnings. 3 For the respective years ended, reported within Transportation and other services revenues (2023 - $35 million loss; 2022 - $13 million gain; 2021 - $9 million gain), Commodity sales (2023 - $153 million gain; 2022 - $89 million gain; 2021 - $160 million gain), Commodity costs (2023 - $94 million loss; 2022 - $102 million loss; 2021 - $105 million loss) and Operating and administrative expense (2023 - $65 million loss; 2022 - $50 million gain; 2021 - $7 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 were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2023. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities. We also identify a variety of other potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances. CREDIT RISK Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through the maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools. We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2023 2022 (millions of Canadian dollars) Canadian financial institutions 457 644 US financial institutions 252 277 European financial institutions 107 334 Asian financial institutions 121 224 Other 1 125 105 1,062 1,584 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. As at December 31, 2023, we did not provide any letters of credit in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on derivative asset exposures as at December 31, 2023 and 2022. Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation. Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, the assessment of credit ratings and netting arrangements. Within Enbridge Gas, credit risk is mitigated by the utility's large and diversified customer base and the ability to recover an estimate for expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value. FAIR VALUE MEASUREMENTS Our financial assets and liabilities measured at fair value on a recurring basis include derivatives and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. FAIR VALUE OF FINANCIAL INSTRUMENTS We categorize our financial instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 Level 1 includes financial instruments measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a financial instrument is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations, US and Canadian treasury bills, investments in exchange-traded funds held by our captive insurance subsidiaries, as well as restricted long-term investments in exchange-traded funds that are held in trust in accordance with the CER's regulatory requirements under the LMCI. Level 2 Level 2 includes financial instrument valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Financial instruments in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the financial instrument. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross-currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained. We have also categorized the fair value of our long-term debt, investments in debt securities held by our captive insurance subsidiaries, and restricted long-term investments in Canadian government bonds held in trust in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. When possible, the fair value of our restricted long-term investments is based on quoted market prices for similar instruments and, if not available, based on broker quotes. Level 3 Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivative's fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on the extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power, NGL and natural gas contracts, basis swaps, commodity swaps, and power and energy swaps, as well as physical forward commodity contracts. We do not have any other financial instruments categorized in Level 3. We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third-party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread, as well as the credit default swap spreads associated with our counterparties, in our estimation of fair value. Fair Value of Derivatives We have categorized our derivative assets and liabilities measured at fair value as follows: December 31, 2023 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 139 — 139 Interest rate contracts — 65 — 65 Commodity contracts 142 103 173 418 Other contracts — 1 — 1 142 308 173 623 Long-term derivative assets Foreign exchange contracts — 335 — 335 Interest rate contracts — 53 — 53 Commodity contracts — 24 51 75 — 412 51 463 Financial liabilities Current derivative liabilities Foreign exchange contracts — (128) — (128) Interest rate contracts — (186) — (186) Commodity contracts (136) (76) (211) (423) Other contracts — (1) — (1) . (136) (391) (211) (738) Long-term derivative liabilities Foreign exchange contracts — (498) — (498) Interest rate contracts — (88) — (88) Commodity contracts — (22) (144) (166) — (608) (144) (752) Total net financial asset/(liability) Foreign exchange contracts — (152) — (152) Interest rate contracts — (156) — (156) Commodity contracts 6 29 (131) (96) Other contracts — — — — 6 (279) (131) (404) December 31, 2022 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 46 — 46 Interest rate contracts — 660 — 660 Commodity contracts 65 90 147 302 Other contracts — 7 — 7 65 803 147 1,015 Long-term derivative assets Foreign exchange contracts — 309 — 309 Interest rate contracts — 254 — 254 Commodity contracts — 17 44 61 Other contracts — 3 — 3 — 583 44 627 Financial liabilities Current derivative liabilities Foreign exchange contracts — (566) — (566) Commodity contracts (60) (77) (195) (332) (60) (643) (195) (898) Long-term derivative liabilities Foreign exchange contracts — (1,116) — (1,116) Interest rate contracts — (4) — (4) Commodity contracts — (38) (132) (170) — (1,158) (132) (1,290) Total net financial asset/(liability) Foreign exchange contracts — (1,327) — (1,327) Interest rate contracts — 910 — 910 Commodity contracts 5 (8) (136) (139) Other contracts — 10 — 10 5 (415) (136) (546) The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2023 Fair Value Unobservable Input Minimum Price Maximum Price Weighted Average Price Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas (6) Forward gas price 2.66 8.29 3.78 $/mmbtu 2 Crude (7) Forward crude price 69.01 92.76 80.35 $/barrel Power (87) Forward power price 29.75 145.24 59.21 $/MW/H Commodity contracts - physical 1 Natural gas 14 Forward gas price 0.86 11.85 3.42 $/mmbtu 2 Crude (7) Forward crude price 64.51 98.11 82.85 $/barrel Power (38) Forward power price 18.20 164.84 58.46 $/MW/H (131) 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 the net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 31, 2023 2022 (millions of Canadian dollars) Level 3 net derivative liability at beginning of period (136) (108) Total gain/(loss), unrealized Included in earnings 1 (48) 6 Included in OCI 67 (54) Settlements (14) 20 Level 3 net derivative liability at end of year (131) (136) 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, 2023 or 2022. Net Investment Hedges We currently have designated a portion of our US dollar-denominated debt as a hedge of our net investment in US dollar-denominated investments and subsidiaries. During the years ended December 31, 2023 and 2022, we recognized unrealized foreign exchange gains of $645 million and losses of $954 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, 2023 and 2022. No realized gains or losses associated with the settlement of foreign exchange forward contracts were recognized in OCI during the years ended December 31, 2023 and 2022. During the years ended December 31, 2023 and 2022, we recognized a realized loss of $236 million and $21 million, 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 $173 million and $102 million as at December 31, 2023 and 2022, respectively. We have wholly-owned captive insurance subsidiaries whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. As at December 31, 2023 , the fair value of investment s in equity funds and debt securities held by our captive insurance subsidiaries was $287 million and $284 million, respectively (2022 - $335 million and $298 million, respectively). Our investments in debt securities had a cost basis of $279 million as at December 31, 2023 (2022 - $295 million). These investments in equity funds and debt securities are recognized at fair value, classified as Level 1 and Level 2 in the fair value hierarchy, respectively, and are recorded in Other current assets and Long-term investments in the Consolidated Statements of Financial Position. There were unrealized holding gains of $34 million for the year ended December 31, 2023 (2022 - losses of $26 million). As at December 31, 2023 and 2022, our long-term debt had a carrying value of $81.2 billion and $79.3 billion, respectively, before debt issuance costs and a fair value of $78.1 billion and $73.5 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at December 31, 2023 and 2022, the non-current notes receivable had a carrying value of $53 million and $752 million, respectively, which also approximates their fair value. As at December 31, 2023 and 2022, we had investments with a fair value of $717 million and $593 million, respectively, included in Restricted long-term investments in the Consolidated Statements of Financial Position. These securities are classified as available-for-sale and represent restricted funds which are collected from customers and held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements. We had restricted long-term investments held in trust totaling $263 million and $236 million as at December 31, 2023 and 2022, respectively, which are classified as Level 1 in the fair value hierarchy. We also had restricted long-term investments held in trust totaling $454 million (cost basis - $486 million) and $357 million (cost basis - $437 million) as at December 31, 2023 and 2022, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding gains of $51 million and losses $122 million on these investments for the years ended December 31, 2023 and 2022, respectively. Within Other long-term liabilities we had estimated future abandonment costs related to LMCI of $745 million and $610 million as at December 31, 2023 and 2022, respectively (Note 7) . The fair value of financial assets and liabilities other than derivative instruments, certain long-term investments in other entities, restricted long-term investments, investments held by our captive insurance subsidiaries, long-term debt and non-current notes receivable described above approximate their carrying value due to the short period to maturity.

INCOME TAXES

INCOME TAXES	12 Months Ended
INCOME TAXES	Dec. 31, 2023
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES INCOME TAX RATE RECONCILIATION Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Earnings before income taxes 7,879 4,542 7,729 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 1,182 681 1,159 Increase/(decrease) resulting from: Provincial and state income taxes 1 411 108 228 Foreign and other statutory rate differentials 2 187 295 134 Effects of rate-regulated accounting 3 (106) (122) (139) Write-off of regulatory deferrals 3,4 115 — — Part VI.1 tax, net of federal Part I deduction 3,5 66 76 73 US Minimum Tax 6 100 107 — Non-taxable portion of gain on sale of investmen t 3,7 — — (23) Valuation allowance 3 (12) 6 5 Accounting impairment of non-deductible goodwill 3,8 — 370 — Noncontrolling interests 3,9 19 9 (17) Investment and production tax credits (47) — — Other 3 (94) 74 (5) Income tax expense 1,821 1,604 1,415 Effective income tax rate 23.1 % 35.3 % 18.3 % 1 The change in provincial and state income taxes from 2022 to 2023 reflects the decrease in earnings from Canadian operations and changes to the state tax apportionment partially offset by a reduction in earnings from US operations before considering the 2022 non-deductible goodwill impairment. Refer to Note 15 - Goodwill. 2 The change in foreign and other statutory rate differentials from 2022 to 2023 reflects the decrease in earnings from US operations before considering the 2022 non-deductible goodwill impairment. Refer to Note 15 - Goodwill. 3 The provincial and state tax component of these items is included in the Provincial and state income taxes above. 4 The amount in 2023 includes the federal tax impact of the de-recognition of rate regulated accounting for income tax relating to Southern Lights Canada and portions of the Canadian Mainline including Line 9 and L3R. Refer to Note 7 - Regulatory Matters. 5 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada. 6 There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation. 7 The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco. 8 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 15 - Goodwill. 9 The amount includes the federal tax impact of impairment to Chapman Ranch in 2023 and Magic Valley in 2022 attributable to noncontrolling interests. Refer to Note 11 - Property, Plant and Equipment. COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Earnings before income taxes Canada 2,233 583 3,399 US 4,620 2,865 3,336 Other 1,026 1,094 994 7,879 4,542 7,729 Current income taxes Canada 100 360 162 US 191 201 80 Other 110 86 82 401 647 324 Deferred income taxes Canada 456 (358) 344 US 974 1,309 741 Other (10) 6 6 1,420 957 1,091 Income tax expense 1,821 1,604 1,415 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, 2023 2022 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (9,202) (9,096) Investments (7,765) (7,099) Regulatory assets (1,338) (1,291) Other (52) (46) Total deferred income tax liabilities (18,357) (17,532) Deferred income tax assets Financial instruments 271 456 Loss carryforwards 1,745 2,259 Other 1,798 1,723 Total deferred income tax assets 3,814 4,438 Less valuation allowance (147) (215) Total deferred income tax assets, net 3,667 4,223 Net deferred income tax liabilities (14,690) (13,309) Presented as follows: Total deferred income tax assets 341 472 Total deferred income tax liabilities (15,031) (13,781) Net deferred income tax liabilities (14,690) (13,309) 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, 2023, we recognized the benefit of unused tax loss carryforwards of $1.3 billion (2022 - $2.1 billion) in Canada which expire in 2030 and beyond. As at December 31, 2023, we recognized the benefit of unused tax loss carryforwards of $6.4 billion (2022 - $8.1 billion) in the US. Unused tax loss carryforwards of $0.1 billion (2022 - $0.2 billion) begin to expire in 2024, and unused tax loss carryforwards of $6.3 billion (2022 - $7.9 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 $6.6 billion and $8.0 billion for the periods ended December 31, 2023 and 2022, 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 2016 to 2023 tax years and by US tax authorities for the 2020 to 2023 tax years. We are currently under examination for income tax matters in Canada for the 2017 to 2020 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, 2023 2022 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 55 76 Gross decreases for tax positions of prior year (2) (17) Change in translation of foreign currency (1) 1 Lapses of statute of limitations (7) (5) Unrecognized tax benefits at end of year 45 55 The unrecognized tax benefits as at December 31, 2023, 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 both years ended December 31, 2023 and 2022 were a $1 million expense. As at December 31, 2023 and 2022, interest and penalties of $14 million and $13 million, respectively, have been accrued.

PENSION AND OTHER POSTRETIREMEN

PENSION AND OTHER POSTRETIREMENT BENEFITS	12 Months Ended
PENSION AND OTHER POSTRETIREMENT BENEFITS	Dec. 31, 2023
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, 2023 2022 2023 2022 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 3,630 4,600 1,029 1,184 Service cost 81 131 40 43 Interest cost 184 127 47 24 Participant contributions 31 29 — — Actuarial (gain)/loss 1 359 (1,069) 31 (201) Benefits paid (193) (187) (76) (94) Foreign currency exchange rate changes — — (29) 77 Other — (1) (6) (4) Projected benefit obligation at end of year 2 4,092 3,630 1,036 1,029 Change in plan assets Fair value of plan assets at beginning of year 4,234 4,536 1,080 1,160 Actual return/(loss) on plan assets 427 (235) 78 (64) Employer contributions 27 91 5 4 Participant contributions 31 29 — — Benefits paid (193) (187) (76) (94) Foreign currency exchange rate changes — — (29) 78 Other 2 — (6) (4) Fair value of plan assets at end of year 3 4,528 4,234 1,052 1,080 Overfunded status at end of year 436 604 16 51 Presented as follows: Deferred amounts and other assets 636 764 116 141 Other current liabilities (8) (9) (5) (5) Other long-term liabilities (192) (151) (95) (85) 436 604 16 51 1 Primarily due to the decrease in the discount rate used to measure the defined benefit obligations (2022 - primarily due to increase in the discount rate used to measure the defined benefit obligations). 2 The accumulated benefit obligation for our Canadian pension plans was $3.8 billion and $3.4 billion as at December 31, 2023 and 2022, respectively. The accumulated benefit obligation for our US pension plans was $1.0 billion as at December 31, 2023 and 2022. 3 Assets in the amount of $14 million (2022 - $10 million) and $62 million (2022 - $58 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, 2023 2022 2023 2022 (millions of Canadian dollars) Accumulated benefit obligation 394 360 99 89 Fair value of plan assets 243 218 — — 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, 2023 2022 2023 2022 (millions of Canadian dollars) Projected benefit obligation 416 377 99 90 Fair value of plan assets 243 218 — — 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, 2023 2022 2023 2022 (millions of Canadian dollars) Net actuarial (gain)/loss 51 (64) 74 40 Prior service cost — — 1 1 Total amount recognized in AOCI 1 51 (64) 75 41 1 Excludes amounts related to CTA. Net Periodic Benefit (Credit)/Cost and Other Amounts Recognized in Comprehensive Income The components of net periodic benefit (credit)/cost and other amounts recognized in pre-tax Comprehensive income related to our pension plans are as follows: Canada US Year ended December 31, 2023 2022 2021 2023 2022 2021 (millions of Canadian dollars) Service cost 81 131 139 40 43 44 Interest cost 1 184 127 101 47 24 17 Expected return on plan assets 1 (271) (295) (252) (77) (85) (73) Amortization/settlement of net actuarial (gain)/loss 1 — 8 54 (4) — 11 Amortization/curtailment of prior service credit 1 — — — — (2) — Net periodic benefit (credit)/cost (6) (29) 42 6 (20) (1) Defined contribution benefit cost 12 10 7 — — — Net pension (credit)/cost recognized in Earnings 6 (19) 49 6 (20) (1) Amount recognized in OCI: Amortization/settlement of net actuarial (gain)/loss — (2) (25) 4 — (11) Amortization/curtailment of prior service credit — — — — 2 — Net actuarial (gain)/loss arising during the year 115 (288) (291) 30 (52) (99) Total amount recognized in OCI 115 (290) (316) 34 (50) (110) Total amount recognized in Comprehensive income 121 (309) (267) 40 (70) (111) 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 2023 2022 2021 2023 2022 2021 Projected benefit obligation Discount rate 4.6 % 5.1 % 3.2 % 4.7 % 4.9 % 2.6 % Rate of salary increase 3.0 % 2.9 % 2.9 % 2.6 % 2.8 % 2.8 % Cash balance interest credit rate N/A N/A N/A 4.5 % 4.3 % 4.3 % Net periodic benefit cost Discount rate 5.3 % 3.2 % 2.6 % 4.9 % 2.6 % 2.2 % Rate of return on plan assets 6.5 % 6.6 % 6.2 % 7.4 % 7.4 % 7.3 % 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 % 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, 2023 2022 2023 2022 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 211 274 136 173 Service cost 3 4 1 1 Interest cost 11 7 6 3 Participant contributions — — 5 6 Actuarial (gain)/loss 1 13 (66) 4 (37) Benefits paid (10) (8) (20) (21) Foreign currency exchange rate changes — — (3) 11 Accumulated postretirement benefit obligation at end of year 228 211 129 136 Change in plan assets Fair value of plan assets at beginning of year — — 185 201 Actual return/(loss) on plan assets — — 14 (21) Employer contributions 10 8 7 7 Participant contributions — — 5 6 Benefits paid (10) (8) (20) (21) Foreign currency exchange rate changes — — (4) 13 Fair value of plan assets at end of year — — 187 185 Overfunded/(underfunded) status at end of year (228) (211) 58 49 Presented as follows: Deferred amounts and other assets — — 73 75 Other current liabilities (12) (12) — — Other long-term liabilities (216) (199) (15) (26) (228) (211) 58 49 1 Primarily due to the decrease in the discount rate used to measure the defined benefit obligations (2022 - primarily due to increase in the discount rate 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, 2023 2022 2023 2022 (millions of Canadian dollars) Accumulated benefit obligation 228 211 78 76 Fair value of plan assets — — 63 50 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, 2023 2022 2023 2022 (millions of Canadian dollars) Net actuarial gain (82) (101) (96) (102) Prior service credit (1) (1) (22) (30) Total amount recognized in AOCI 1 (83) (102) (118) (132) 1 Excludes amounts related to CTA. Net Periodic Benefit (Credit)/Cost and Other Amounts Recognized in Comprehensive Income The components of net periodic benefit (credit)/cost and other amounts recognized in pre-tax Comprehensive income related to our OPEB plans are as follows: Canada US Year ended December 31, 2023 2022 2021 2023 2022 2021 (millions of Canadian dollars) Service cost 3 4 6 1 1 1 Interest cost 1 11 7 7 6 3 3 Expected return on plan assets 1 — — — (11) (12) (10) Amortization/settlement of net actuarial gain 1 (6) (1) — (6) (6) (1) Amortization/curtailment of prior service credit 1 — — — (8) (7) (7) Net periodic benefit (credit)/cost recognized in Earnings 8 10 13 (18) (21) (14) Amount recognized in OCI: Amortization/settlement of net actuarial gain 6 1 — 6 6 1 Amortization/curtailment of prior service credit — — — 8 7 7 Net actuarial (gain)/loss arising during the year 13 (67) (50) — (4) (80) Total amount recognized in OCI 19 (66) (50) 14 9 (72) Total amount recognized in Comprehensive income 27 (56) (37) (4) (12) (86) 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 2023 2022 2021 2023 2022 2021 Accumulated postretirement benefit obligation Discount rate 4.6 % 5.3 % 3.2 % 4.7 % 4.9 % 2.4 % Net periodic benefit cost Discount rate 5.3 % 3.2 % 2.6 % 4.9 % 2.4 % 2.0 % Rate of return on plan assets N/A N/A N/A 5.9 % 6.0 % 6.0 % 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 2023 2022 2023 2022 Health care cost trend rate assumed for next year 4.0 % 4.0 % 4.7 % 4.7 % Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.0 % 4.0 % 3.3 % 3.3 % Year that the rate reaches the ultimate trend rate N/A N/A 2022 - 2045 2021 - 2045 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 2023 2022 Allocation 2023 2022 Equity securities 46.0 % 41.4 % 38.2 % 45.0 % 39.5 % 38.3 % Fixed income securities 23.2 % 29.6 % 31.7 % 20.0 % 19.4 % 20.5 % Alternatives 1 30.8 % 29.0 % 30.1 % 35.0 % 41.1 % 41.2 % 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, 2023 Cash and cash equivalents 227 — — 227 8 — — 8 Equity securities 4 Canada — 3 — 3 — — — — Global — 1,871 — 1,871 — 416 — 416 Fixed income securities 4 Government — 446 — 446 — 46 — 46 Corporate — 667 — 667 — 149 — 149 Alternatives 5 — — 1,290 1,290 — — 433 433 Forward currency contracts — 24 — 24 — — — — Total pension plan assets at fair value 227 3,011 1,290 4,528 8 611 433 1,052 December 31, 2022 Cash and cash equivalents 272 — — 272 13 — — 13 Equity securities 4 Canada — 355 — 355 — — — — Global — 1,263 — 1,263 — 414 — 414 Fixed income securities 4 Government 201 435 — 636 — 87 — 87 Corporate — 433 — 433 — 121 — 121 Alternatives 5 — — 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 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 Pension plan assets include $61 million (2022 - $32 million) of equity and fixed income securities investments held with related parties. 5 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, 2023 2022 2023 2022 (millions of Canadian dollars) Balance at beginning of year 1,291 1,064 445 337 Unrealized and realized gains/(losses) (41) 155 (12) 78 Purchases and settlements, net 40 72 — 30 Balance at end of year 1,290 1,291 433 445 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, 2023 Cash and cash equivalents 3 — — 3 Equity securities US — 36 — 36 Global — 62 — 62 Fixed income securities Government 42 3 — 45 Corporate — 12 — 12 Alternatives 4 — — 29 29 Total OPEB plan assets at fair value 45 113 29 187 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 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, 2023 2022 (millions of Canadian dollars) Balance at beginning of year 28 22 Unrealized and realized gains 1 4 Purchases and settlements, net — 2 Balance at end of year 29 28 EXPECTED BENEFIT PAYMENTS Year ending December 31, 2024 2025 2026 2027 2028 2029-2033 (millions of Canadian dollars) Pension Canada 207 213 219 224 230 1,234 US 87 87 87 86 81 393 OPEB Canada 13 13 13 13 13 70 US 16 15 14 13 12 49 EXPECTED EMPLOYER CONTRIBUTIONS In 2024, we expect to contribute approximately $18 million and $5 million to the Canadian and US pension plans, respectively, and $13 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, 2023, pre-tax employer matching contribution costs were $33 million ($30 million in 2022 and $27 million in 2021).

LEASES

LEASES	12 Months Ended
LEASES	Dec. 31, 2023
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 35 years as at December 31, 2023. For the years ended December 31, 2023, 2022 and 2021, we incurred operating lease expenses of $131 million, $118 million and $95 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings. For the years ended December 31, 2023, 2022 and 2021, operating lease payments to settle lease liabilities were $129 million, $123 million and $118 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, 2023 December 31, 2022 (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 669 680 Operating lease liabilities - current 3 98 87 Operating lease liabilities - long-term 3 652 677 Total operating lease liabilities 750 764 Finance leases Finance lease right-of-use assets, net 4 287 62 Finance lease liabilities - current 5 19 17 Finance lease liabilities - long-term 5 264 39 Total finance lease liabilities 283 56 Weighted average remaining lease term Operating leases 12 years 12 years Finance leases 31 years 5 years Weighted average discount rate Operating leases 4.5 % 4.2 % Finance leases 5.7 % 4.4 % 1 Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2023 were $42 million (December 31, 2022 - $47 million), $5 million (December 31, 2022 - $5 million) and $38 million (December 31, 2022 - $43 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 lease liabilities are reported under Other current liabilities 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 and long-term finance lease liabilities are reported under Current portion of long-term debt and Long-term debt in the Consolidated Statements of Financial Position. As at December 31, 2023, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance (millions of Canadian dollars) 2024 130 31 2025 120 25 2026 106 25 2027 96 18 2028 75 18 Thereafter 459 502 Total undiscounted lease payments 986 619 Less imputed interest (236) (336) Total 750 283 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 3 month to 28 years as at December 31, 2023. Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Operating lease income 241 266 263 Variable lease income 299 321 333 Total lease income 1 540 587 596 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings. As at December 31, 2023, 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) 2024 225 2025 206 2026 201 2027 199 2028 201 Thereafter 1,612 Future lease payments 2,644
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 35 years as at December 31, 2023. For the years ended December 31, 2023, 2022 and 2021, we incurred operating lease expenses of $131 million, $118 million and $95 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings. For the years ended December 31, 2023, 2022 and 2021, operating lease payments to settle lease liabilities were $129 million, $123 million and $118 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, 2023 December 31, 2022 (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 669 680 Operating lease liabilities - current 3 98 87 Operating lease liabilities - long-term 3 652 677 Total operating lease liabilities 750 764 Finance leases Finance lease right-of-use assets, net 4 287 62 Finance lease liabilities - current 5 19 17 Finance lease liabilities - long-term 5 264 39 Total finance lease liabilities 283 56 Weighted average remaining lease term Operating leases 12 years 12 years Finance leases 31 years 5 years Weighted average discount rate Operating leases 4.5 % 4.2 % Finance leases 5.7 % 4.4 % 1 Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2023 were $42 million (December 31, 2022 - $47 million), $5 million (December 31, 2022 - $5 million) and $38 million (December 31, 2022 - $43 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 lease liabilities are reported under Other current liabilities 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 and long-term finance lease liabilities are reported under Current portion of long-term debt and Long-term debt in the Consolidated Statements of Financial Position. As at December 31, 2023, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance (millions of Canadian dollars) 2024 130 31 2025 120 25 2026 106 25 2027 96 18 2028 75 18 Thereafter 459 502 Total undiscounted lease payments 986 619 Less imputed interest (236) (336) Total 750 283 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 3 month to 28 years as at December 31, 2023. Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Operating lease income 241 266 263 Variable lease income 299 321 333 Total lease income 1 540 587 596 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings. As at December 31, 2023, 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) 2024 225 2025 206 2026 201 2027 199 2028 201 Thereafter 1,612 Future lease payments 2,644

OTHER INCOME_(EXPENSE)

OTHER INCOME/(EXPENSE)	12 Months Ended
OTHER INCOME/(EXPENSE)	Dec. 31, 2023
Other Income and Expenses [Abstract]
OTHER INCOME/(EXPENSE)	OTHER INCOME/(EXPENSE) Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Gain/(loss) on dispositions 15 (12) 319 Realized foreign currency gain/(loss) (129) 92 126 Unrealized foreign currency gain/(loss) 821 (1,094) 160 Net defined pension and OPEB credit 135 239 150 Other 382 186 224 1,224 (589) 979

CHANGES IN OPERATING ASSETS AND

CHANGES IN OPERATING ASSETS AND LIABILITIES	12 Months Ended
CHANGES IN OPERATING ASSETS AND LIABILITIES	Dec. 31, 2023
CHANGES IN OPERATING ASSETS AND LIABILITIES
CHANGES IN OPERATING ASSETS AND LIABILITIES	CHANGES IN OPERATING ASSETS AND LIABILITIES Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Trade receivables and unbilled revenues 1,125 (572) (1,030) Other current assets 1,278 (395) (198) Accounts receivable from affiliates 18 17 (38) Inventory 763 (599) (118) Deferred amounts and other assets 23 1 (195) Trade payables and accrued liabilities (1,542) 585 652 Other current liabilities 339 515 (565) Accounts payable to affiliates (66) 16 52 Interest payable 199 58 43 Other long-term liabilities 174 362 (69) 2,311 (12) (1,466)

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
RELATED PARTY TRANSACTIONS	Dec. 31, 2023
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, 2023 2022 2021 (millions of Canadian dollars) Transportation and other revenues 169 185 237 Commodity sales — 51 20 Operating and administrative 1 625 503 380 Commodity costs 2 63 778 790 Gas distribution costs 140 136 131 1 During the years ended December 31, 2023, 2022 and 2021, we had Operating and administrative costs from the Seaway Crude Pipeline System of $632 million, $495 million and $389 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, 2023, 2022 and 2021, we had Commodity costs from Aux Sable Canada LP of $2 million, $571 million and $447 million, respectively. LONG-TERM NOTES RECEIVABLE FROM AFFILIATES As at December 31, 2023, amounts receivable from affiliates include a series of notes totaling $54 million (2022 - $752 million). This change in balance is primarily due to notes receivable from ERII which, beginning November 2023, eliminated upon consolidation. Refer to the Other Equity Investment Transactions section of Note 13 - Long-Term Investments for further details on the Offshore Wind Facilities transaction. The remaining loans which require quarterly or semi-annual interest payments at annual interest rates ranging from 4% to 8%. Interest income recognized from these notes totaled $21 million, $30 million and $39 million for the years ended December 31, 2023, 2022 and 2021, 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
COMMITMENTS AND CONTINGENCIES	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS As at December 31, 2023, we have commitments as detailed below: Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Purchase of services, pipe and other materials, including transportation 1 11,018 4,193 1,421 1,206 1,039 996 2,163 Maintenance agreements 2 473 51 52 52 53 34 231 Right-of-ways commitments 3 1,328 44 45 45 45 45 1,104 Total 12,819 4,288 1,518 1,303 1,137 1,075 3,498 1 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. 2 Consists primarily of maintenance service contracts for our wind and solar assets. 3 Our right-of-way obligations primarily consist of non-lease agreements that existed at the time of adopting Topic 842 Leases, at which time we elected a practical expedient that allowed us to continue our historical treatment. 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 The previously reported claim filed against Aux Sable by a counterparty to an NGL supply agreement was settled and discontinued during the fourth quarter of 2023. A provision was recognized for this claim in the third quarter of 2023. 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 an insurance program for us, our subsidiaries and certain of our affiliates to mitigate a certain portion of our risks. However, not all potential risks arising from our operations are insurable, or are insured by us as a result of availability, high premiums and for various other reasons. We self-insure a significant portion of certain risks through our wholly-owned captive insurance subsidiaries, which require certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices and the selection of estimated loss among estimates derived using different methods. Our insurance coverage is also subject to terms and conditions, exclusions and large deductibles or self-insured retentions which may reduce or eliminate coverage in certain circumstances. Our insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, terms, policy limits and/or deductibles can vary substantially. We can give no assurance that we will be able to maintenance adequate insurance in the future at rates or on other terms we consider commercially reasonable. In such case, we may decide to self-insure additional risks.

GUARANTEES

GUARANTEES	12 Months Ended
GUARANTEES	Dec. 31, 2023
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. The likelihood of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We cannot reasonably estimate the total maximum potential amounts that could become payable to third parties and affiliates under such agreements described above; however, historically, we have not made any significant payments under guarantee or indemnification provisions. While these agreements may specify a maximum potential exposure, or a specified duration to the guarantee or indemnification obligation, there are circumstances where the amount and duration are unlimited. As at December 31, 2023, guarantees and indemnifications have not had, and are not reasonably likely to have, a material effect on our financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources.

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
QUARTERLY FINANCIAL DATA (UNAUDITED)	Dec. 31, 2023
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) 2023 Operating revenues 12,075 10,432 9,844 11,298 43,649 Operating income 2,662 2,350 1,794 1,845 8,651 Earnings 1,866 2,001 623 1,568 6,058 Earnings attributable to controlling interests 1,817 1,935 621 1,818 6,191 Earnings attributable to common shareholders 1,733 1,848 532 1,726 5,839 Earnings per common share Basic 0.86 0.91 0.26 0.81 2.84 Diluted 0.85 0.91 0.26 0.81 2.84 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

SUBSEQUENT EVENT

SUBSEQUENT EVENT	12 Months Ended
SUBSEQUENT EVENT	Dec. 31, 2023
Subsequent Events [Abstract]
SUBSEQUENT EVENT	SUBSEQUENT EVENT Acquisition of RNG Facilities On January 2, 2024, through a wholly-owned US subsidiary, we acquired the first six Morrow Renewables operating landfill gas-to-RNG production facilities located in Texas and Arkansas for total consideration of $1.4 billion (US$1.1 billion), of which $0.5 billion (US$0.4 billion) was paid at close and $0.9 billion (US$0.7 billion) is payable within two years (the RNG Facilities Acquisition). The total consideration for all seven facilities is $1.6 billion (US$1.2 billion). The acquired assets align with and advance our low-carbon strategy. We will account for the RNG Facilities Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations . The acquired assets and assumed liabilities will be recorded at their estimated fair values as at the date of acquisition, with any remaining amount allocated to goodwill. Due to the proximity of the acquisition date to the release date of our annual consolidated financial statements, we have not performed our initial accounting for the RNG Facilities Acquisition. The preliminary purchase price allocation will be disclosed in the first quarter of 2024 after asset and liability valuations become available.

SIGNIFICANT ACCOUNTING POLICI_2

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Policies)	Dec. 31, 2023
Accounting Policies [Abstract]
Basis Of Presentation	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.
Use of Estimates	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 14) ; measurement of goodwill (Note 15) ; fair value of asset retirement obligations (ARO) (Note 18) ; valuation of stock-based compensation (Note 21) ; fair value of financial instruments (Note 23) ; provisions for income taxes (Note 24) ; assumptions used to measure retirement benefits and OPEB (Note 25) ; commitments and contingencies (Note 30) ; and estimates of losses related to environmental remediation obligations (Note 30) . 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 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 BC Energy Regulator, the Ontario Energy Board (OEB) and the Québec Régie de l’énergie. 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, amounts collected from customers in advance of costs being incurred, or to be paid to cover future abandonment costs in relation to the CER's Land Matters Consultation Initiative (LMCI) and for future removal and site restoration costs as approved by the regulator. If there are changes in our assessment of the probability of recovery for a regulatory asset, we reduce its carrying amount to the balance that we expect to recover from customers in future periods through rates. If a regulator later excludes from allowable costs all or a part of costs that were capitalized as a regulatory asset, we reduce the carrying amount of the asset by the excluded amounts. 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. During the fourth quarter of 2023, Southern Lights Pipeline completed an open season to negotiate new transportation service agreements. We do not expect to renew the agreements under a cost-of-service toll methodology, therefore Southern Lights Pipeline is no longer subject to rate-regulated accounting. As a result, the related regulatory liabilities, regulatory tax assets and associated regulatory deferred tax liabilities were derecognized. We believe that the recovery of our remaining regulatory assets as at December 31, 2023 is probable over the periods described in Note 7 - Regulatory Matters . 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 regulatory requirements under the 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. An 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 and 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, 2023, 2022 and 2021, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $210 million, $238 million and $127 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 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 revenues, 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. 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.
Cans 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 and debt 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. Trade receivables and unbilled revenues 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
Inventory	INVENTORY Inventory is comprised of natural gas held in storage by Enbridge Gas, crude oil and natural gas held primarily by businesses in our 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 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 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. The lease term may include periods associated with options to extend or terminate the lease if it is reasonably certain the options will be exercised.
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 for certain regulated entities; 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 for Enbridge Gas.
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 discounted cash flow technique. 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 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, 2023, we performed our annual goodwill impairment assessment which consisted of a qualitative assessment for the Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation reporting units and did not identify impairment indicators. Due to an impairment recorded in 2022 for the Gas Transmission reporting unit and the OEB decision on Phase 1 for Enbridge Gas, we performed a quantitative assessment for the Gas Transmission and Gas Distribution and Storage reporting units as at December 1, 2023, which did not result in the recognition of an impairment charge for either reporting unit. Also, we did not identify any indicators of goodwill impairment during the remainder of 2023.
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. 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 investment.
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Other current liabilities 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 is 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 Post Retirement 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 certain RSUs are cash-settled awards for which the related liability is remeasured each reporting period. These 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 Other current liabilities 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 to certain senior management employees which vest at the completion of a three-year term. Beginning in 2023, share-settled units were granted to other employees, which vest one-third annually from the grant date. 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. There is no associated liability recorded for share-settled awards.
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 Other current liabilities 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, 2023. FUTURE ACCOUNTING POLICY CHANGES Segment Reporting Accounting Standards Update (ASU) 2023-07 was issued in November 2023 to improve reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and to require in interim period financial statements all disclosures about a reportable segment's profit or loss and assets that are currently required annually. The new ASU requires entities to disclose the title and position of the individual or the name of the group or committee identified as the chief operating decision-maker (CODM) of each segment. ASU 2023-07 is effective January 1, 2024, with interim period disclosure requirements effective after January 1, 2025 and should be applied retrospectively to all prior periods presented in the financial statements. We are currently assessing the impact of the new standard on our consolidated financial statements. Income Tax Disclosures ASU 2023-09 was issued in December 2023 to improve income tax disclosures by requiring specified categories in the annual rate reconciliation that meet quantitative thresholds and further disaggregation on income taxes paid by jurisdiction. ASU 2023-09 is effective January 1, 2025 and should be applied prospectively, with retrospective application being permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
REVENUE (Tables)	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Schedule of Disaggregation of Revenue	Major Products and Services Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2023 (millions of Canadian dollars) Transportation revenue 11,875 5,302 814 — — — 17,991 Storage and other revenue 257 461 355 — — — 1,073 Gas distribution revenue — — 4,859 — — — 4,859 Electricity and transmission revenue — — — 259 — — 259 Commodity sales — 17 — — — — 17 Total revenue from contracts with customers 12,132 5,780 6,028 259 — — 24,199 Commodity sales — — — — 18,964 — 18,964 Other revenue 1,2 257 72 (58) 215 — — 486 Intersegment revenue 474 2 6 3 25 (510) — Total revenue 12,863 5,854 5,976 477 18,989 (510) 43,649 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 1 Includes realized and unrealized gains and losses 2 Includes revenues from lease contracts. Refer to Note 26 - Leases .
Schedule of Contract Balances	Contract Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at December 31, 2023 2,802 400 2,591 Balance as at December 31, 2022 3,183 230 2,241
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, 2023 (millions of Canadian dollars) Revenue from products transferred at a point in time — 17 138 — 155 Revenue from products and services transferred over time 1 12,132 5,763 5,890 259 24,044 Total revenue from contracts with customers 12,132 5,780 6,028 259 24,199 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 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
SEGMENTED INFORMATION (Tables)	Dec. 31, 2023
Segment Reporting [Abstract]
Schedule of Reporting Information by Segment	Year ended December 31, 2023 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Operating revenues (Note 4) 12,863 5,854 5,976 477 18,989 (510) 43,649 Commodity and gas distribution costs — (15) (2,871) (20) (18,975) 515 (21,366) Operating and administrative (4,629) (2,380) (1,285) (261) (52) 7 (8,600) Impairment of long-lived assets 1 145 — (281) (283) — — (419) Income/(loss) from equity investments (Note 13) 1,007 688 2 140 — (21) 1,816 Other income (Note 27) 113 117 51 96 1 846 1,224 Earnings/(loss) before interest, income taxes and depreciation and amortization 9,499 4,264 1,592 149 (37) 837 16,304 Depreciation and amortization (4,613) Interest expense (Note 17) (3,812) Income tax expense (Note 24) (1,821) Earnings 6,058 Capital expenditures 2 1,158 1,944 1,451 100 — 55 4,708 Total property, plant and equipment, net (Note 11) 51,851 31,016 18,766 2,706 4 298 104,641 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) Operating 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 15) — (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 27) 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 17) (3,179) Income tax expense (Note 24) (1,604) Earnings 2,938 Capital expenditures 2 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) Operating 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) 759 702 42 101 — (4) 1,600 Other income/(expense) (Note 27) 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 17) (2,655) Income tax expense (Note 24) (1,415) Earnings 6,314 Capital expenditures 2 4,051 2,420 1,343 16 1 54 7,885 Total property, plant and equipment, net 52,530 27,028 16,904 3,315 23 267 100,067 1 The Liquids Pipelines segment includes the impact of a gain resulting from the derecognition of a net regulatory liability due to the discontinuance of regulatory accounting for our Southern Lights Pipeline (Note 7). 2 Includes equity component of AFUDC.
Schedule of Revenues by Geographical Segments	Revenues 1 Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Canada 23,781 27,498 20,474 US 19,868 25,811 26,597 43,649 53,309 47,071 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, 2023 2022 (millions of Canadian dollars) Canada 48,570 47,602 US 56,071 56,858 104,641 104,460 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
EARNINGS PER COMMON SHARE (Tables)	Dec. 31, 2023
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, 2023 2022 2021 (number of shares in millions) Weighted average shares outstanding 2,056 2,025 2,023 Effect of dilutive options and RSUs 2 4 2 Diluted weighted average shares outstanding 2,058 2,029 2,025

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
REGULATORY MATTERS (Tables)	Dec. 31, 2023
Regulated Operations [Abstract]
Schedule of Regulatory Assets	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, 2023 2022 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Purchase gas variance 15 190 2024 Under-recovery of fuel costs 75 109 2024 Other current regulatory assets 380 305 2024 Total current regulatory assets 1 (Note 9) 470 604 Long-term regulatory assets Deferred income taxes 2 4,456 4,473 Various Long-term debt 3 348 378 2032-2046 Negative salvage 4 180 265 Various Purchase gas variance — 244 2024 Accounting policy changes 5 — 219 2024 Pension plan receivable 6 1 40 Various Other long-term regulatory assets 252 244 Various Total long-term regulatory assets 1 5,237 5,863 Total regulatory assets 5,707 6,467 Current regulatory liabilities Purchase gas variance 31 — 2024 Other current regulatory liabilities 276 167 2024 Total current regulatory liabilities 7 307 167 Long-term regulatory liabilities Future removal and site restoration reserves 8 1,693 1,615 Various Regulatory liability related to US income taxes 9 854 918 2050-2072 Pipeline future abandonment costs (Note 23) 745 610 Various Pension plan payable 6 143 231 Various Other long-term regulatory liabilities 86 250 Various Total long-term regulatory liabilities 7 3,521 3,624 Total regulatory liabilities 3,828 3,791 1 Current regulatory assets are included in Other current assets, 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. The balance as at December 31, 2023 is net of regulatory deferred tax write-offs. 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 In 2022, this deferral primarily consisted 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. The Phase 1 Decision disallowed recovery of the remaining balance related to pre-2017 pension amounts and was impaired with a nil balance as at December 31, 2023. The residual balance in this account pertains to the impact of other accounting changes during the deferred rebasing period and were approved for disposition in 2024 in the Phase 1 Decision and subsequently transferred to Other current regulatory assets as at December 31, 2023. 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 Other current liabilities, 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	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, 2023 2022 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Purchase gas variance 15 190 2024 Under-recovery of fuel costs 75 109 2024 Other current regulatory assets 380 305 2024 Total current regulatory assets 1 (Note 9) 470 604 Long-term regulatory assets Deferred income taxes 2 4,456 4,473 Various Long-term debt 3 348 378 2032-2046 Negative salvage 4 180 265 Various Purchase gas variance — 244 2024 Accounting policy changes 5 — 219 2024 Pension plan receivable 6 1 40 Various Other long-term regulatory assets 252 244 Various Total long-term regulatory assets 1 5,237 5,863 Total regulatory assets 5,707 6,467 Current regulatory liabilities Purchase gas variance 31 — 2024 Other current regulatory liabilities 276 167 2024 Total current regulatory liabilities 7 307 167 Long-term regulatory liabilities Future removal and site restoration reserves 8 1,693 1,615 Various Regulatory liability related to US income taxes 9 854 918 2050-2072 Pipeline future abandonment costs (Note 23) 745 610 Various Pension plan payable 6 143 231 Various Other long-term regulatory liabilities 86 250 Various Total long-term regulatory liabilities 7 3,521 3,624 Total regulatory liabilities 3,828 3,791 1 Current regulatory assets are included in Other current assets, 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. The balance as at December 31, 2023 is net of regulatory deferred tax write-offs. 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 In 2022, this deferral primarily consisted 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. The Phase 1 Decision disallowed recovery of the remaining balance related to pre-2017 pension amounts and was impaired with a nil balance as at December 31, 2023. The residual balance in this account pertains to the impact of other accounting changes during the deferred rebasing period and were approved for disposition in 2024 in the Phase 1 Decision and subsequently transferred to Other current regulatory assets as at December 31, 2023. 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 Other current liabilities, 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
ACQUISITIONS AND DISPOSITIONS (Tables)	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Summary of Estimated Fair Values Assigned to Net Assets and Final Purchase Price Allocation	The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Aitken Creek: November 1, 2023 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 105 Property, plant and equipment (b) 466 Current liabilities 20 Long-term liabilities (c) 130 Goodwill (d) 46 Purchase price: Cash 397 Additional consideration (e) 70 467 a) Current assets consist primarily of inventory which is short-term in nature and represents natural gas held in storage. Fair value was determined using the market price of natural gas at the date of acquisition. b) Aitken Creek's property, plant and equipment constitutes an integrated system of cavern storage facilities, associated header pipeline, and land and right-of-ways. The depreciated replacement cost approach was adopted as the primary valuation methodology to determine the fair value of property, plant and equipment, excluding the reservoir storage asset. 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. Fair value of the reservoir storage asset was determined using a residual approach whereby the adjusted purchase price was allocated to the fair value of the net tangible assets, excluding the reservoir storage asset, with the remaining value allocated to the reservoir storage asset. The income approach was also utilized to corroborate that the cash flows attributable to the reservoir storage asset support the residual value. c) Long-term liabilities consist primarily of a deferred income tax liability arising from temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes at the date of acquisition. d) Goodwill is primarily attributable to the recognition of a deferred income tax liability. The goodwill balance recognized has been assigned to our Gas Transmission and Midstream segment and is not tax deductible. e) The $70 million of additional consideration recognized in the purchase price represents the fair value of derivative contracts and working gas as at March 31, 2023. The following table summarizes the estimated fair values that were assigned to the net assets of TGE: September 27, 2022 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 5 Property, plant and equipment 3 Long-term investments 8 Intangible assets (a) 117 Long-term assets 3 Current liabilities 61 Long-term debt 18 Long-term liabilities (b) 105 Goodwill (c) 392 Purchase price: Cash 295 Contingent consideration (d) 49 344 a) Intangible assets consist of compensation expected to be earned by TGE on existing development contracts once certain project development milestones are met. Fair value was determined using a discounted cash flow method which is an income-based approach to valuation that estimates the present value of future projected benefits from the contracts. The intangible assets will be amortized on a straight-line basis over an expected useful life of three and a half years. b) Long-term liabilities consist primarily of obligations payable to third parties which are contingent on milestones being met for certain projects. Fair value represents the present value of the future cash flow payments at the date of the TGE Acquisition. c) Goodwill is primarily attributable to expected future returns from new opportunities to develop wind and solar projects, as well as enhanced scale and operational diversity of our renewable projects portfolio. The goodwill balance recognized has been assigned to our Renewable Power Generation segment and is tax deductible over 15 years. d) We agreed to pay additional contingent consideration of up to US$53 million to TGE's former common unit holders if performance milestones are met on certain projects. The US$36 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition. The fair value was determined using an income-based approach. 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 year ended December 31, 2021, 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 (unaudited; millions of Canadian dollars) Operating revenues 47,339 Earnings attributable to common shareholders 1,2 5,771 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. 2 Includes the amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets of $193 million (after-tax of $145 million) for the year ended December 31, 2021.

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
OTHER CURRENT ASSETS (Tables)	Dec. 31, 2023
Receivables [Abstract]
Schedule of Other Current Assets	December 31, 2023 2022 (millions of Canadian dollars) Derivative assets (Note 23) 623 1,015 Regulatory assets (Note 7) 470 604 Gas imbalances 209 461 Income taxes receivable 347 323 Other 791 852 2,440 3,255

INVENTORY (Tables)

INVENTORY (Tables)	12 Months Ended
INVENTORY (Tables)	Dec. 31, 2023
Inventory Disclosure [Abstract]
Schedule of Inventory	December 31, 2023 2022 (millions of Canadian dollars) Natural gas 938 1,491 Crude oil 413 652 Other 128 112 1,479 2,255

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
PROPERTY, PLANT AND EQUIPMENT (Tables)	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant And Equipment	Weighted Average December 31, Depreciation Rate 2023 2022 (millions of Canadian dollars) Pipelines 2.9 % 66,698 66,528 Facilities and equipment 3.1 % 37,634 37,028 Land and right-of-way 1 2.3 % 3,600 3,637 Gas mains, services and other 2.6 % 15,346 14,491 Storage 2.5 % 4,929 3,477 Wind turbines, solar panels and other 4.1 % 4,511 4,912 Other 10.1 % 1,652 1,611 Under construction — % 2,829 2,316 Total property, plant and equipment 137,199 134,000 Total accumulated depreciation (32,558) (29,540) Property, plant and equipment, net 104,641 104,460 1 The measurement of weighted average depreciation rate excludes non-depreciable assets.

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
VARIABLE INTEREST ENTITIES (Tables)	Dec. 31, 2023
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, 2023 2022 (millions of Canadian dollars) Assets Cash and cash equivalents 442 426 Restricted cash 9 12 Trade receivables and unbilled revenue 144 185 Other current assets 8 14 Accounts receivable from affiliates 5 23 Inventory 11 12 619 672 Property, plant and equipment, net 7,105 7,707 Long-term investments 14 14 Restricted long-term investments 106 98 Deferred amounts and other assets 148 158 Intangible assets, net 84 102 8,076 8,751 Liabilities Trade payables and accrued liabilities 83 99 Other current liabilities 145 152 Accounts payable to affiliates 4 21 232 272 Long-term debt 1 — Other long-term liabilities 971 859 Deferred income taxes 5 5 1,209 1,136 6,867 7,615
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, 2023 and 2022 are presented below: Carrying Maximum December 31, 2023 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 105 130 Rampion Offshore Wind Limited 2 391 452 Vector Pipeline L.P. 3 191 320 Woodfibre LNG Limited Partnership 4 778 2,854 Fox Squirrel Solar LLC 5 312 661 Other 4 132 230 1,909 4,647 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. 6 37 637 Rampion Offshore Wind Limited 2 413 468 Vector Pipeline L.P. 3 195 325 Woodfibre LNG Limited Partnership 4 635 2,476 Other 4 245 443 1,616 4,466 1 As at December 31, 2023 and 2022, 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, 2023 and 2022, 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. 3 As at December 31, 2023 and 2022, the maximum exposure to loss includes the carrying value of outstanding affiliate loans receivable for $24 million and $25 million held by us as at December 31, 2023 and 2022, respectively, and an outstanding credit facility for $105 million as at December 31, 2023 and 2022. 4 As at December 31, 2023 and 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. 5 In November 2023, Enbridge acquired a 50% interest in Fox Squirrel JV, LLC (Fox Squirrel Solar LLC). Refer to Note 13 - Long-Term Investments. Fox Squirrel Solar LLC 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 Fox Squirrel Solar LLC's activities that most significantly impacts its economic performance. As at December 31, 2023, 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. 6 As at December 31, 2023, EIH S.á r.l no longer met the requirements of a VIE as a result of a VIE reconsideration event. As at December 31, 2022, 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.

LONG-TERM INVESTMENTS (Tables)

LONG-TERM INVESTMENTS (Tables)	12 Months Ended
LONG-TERM INVESTMENTS (Tables)	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Long-Term Investments	Ownership December 31, Interest 2023 2022 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines MarEn Bakken Company LLC 1 75.0 % 1,819 1,968 DCP Midstream, LLC (Class B Units) 2 90.0 % 1,486 1,394 Seaway Crude Holdings LLC 50.0 % 2,661 2,744 Illinois Extension Pipeline Company, L.L.C. 3 65.0 % 584 622 Cactus II Pipeline LLC 4 30.0 % 618 658 Other 30.0% - 43.8% 84 76 Gas Transmission and Midstream Alliance Pipeline 5, 7 50.0 % 359 430 Aux Sable 6, 7 42.7% - 50.0% 229 214 DCP Midstream, LLC (Class A Units) 8 23.4 % 367 317 Gulfstream Natural Gas System, L.L.C. 50.0 % 1,224 1,274 NEXUS Gas Transmission, LLC 50.0 % 1,220 1,813 Sabal Trail Transmission, LLC 50.0 % 1,467 1,535 Southeast Supply Header, LLC 50.0 % 80 86 Steckman Ridge, LP 50.0 % 87 91 Vector Pipeline 9 60.0 % 191 195 Woodfibre LNG Limited Partnership 10 30.0 % 777 635 Offshore - various joint ventures 22.0% - 74.3% 217 314 Gas Distribution and Storage Other 30.0% - 50.0% 22 20 Renewable Power Generation EIH S.à r.l. 11 51.0 % 52 37 Hohe See and Albatros Offshore Wind Facilities 49.9 % 1,701 163 Rampion Offshore Wind Limited 24.9 % 391 413 East-West Tie Limited Partnership 24.1 % 132 241 Fox Squirrel Solar LLC 50.0 % 312 — Other 16.4% - 50.0% 110 107 OTHER LONG-TERM INVESTMENTS Gas Transmission and Midstream Ara Divert HoldCo, Inc. 106 — Other 22 22 Gas Distribution and Storage Other 24 48 Renewable Power Generation Other 21 31 Eliminations and Other Other 12 430 488 16,793 15,936 1 Owns a 49.0% interest in Bakken Pipeline Investments LLC. Bakken Pipeline Investments LLC 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. On January 9, 2023, we acquired an additional 10.0% direct interest in Gray Oak for cash consideration of $230 million (US$172 million), bringing our effective interest to 68.5%. 3 Owns the Southern Access Extension Project. 4 On October 12, 2021, we acquired a 20.0% equity interest in Cactus II through the Moda Acquisition (Note 8). On November 2, 2022, we acquired an additional 10.0% ownership in Cactus II for cash consideration 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 L.P. and Aux Sable Midstream LLC in the US. 7 On December 13, 2023, we announced that Enbridge had entered into a definitive agreement to sell its 50.0% interest in the Alliance Pipeline and interest in Aux Sable to Pembina Pipeline Corporation for $3.1 billion, including approximately $0.3 billion of non-recourse debt, subject to customary closing adjustments. 8 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. 9 Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US. 10 On November 29, 2022, we acquired an effective 30.0% interest in Woodfibre LNG Limited Partnership (Woodfibre) for cash consideration of $533 million (US$392 million). Woodfibre will operate a LNG export facility in BC being constructed by us and our partners. 11 Owns a 50.0% interest in Éolien Maritime France SAS (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%). 12 Consists of investments in exchange-traded funds and debt securities held by our wholly-owned captive insurance subsidiaries. Refer to Note 23 - Risk Management and Financial Instruments.
Schedule of Combined Financial Information	Summarized combined financial information of our unconsolidated equity investments (presented at 100%) is as follows: Year ended December 31, 2023 2022 1 2021 1 (millions of Canadian dollars) Operating revenues 22,586 30,026 22,551 Operating expenses 17,111 23,835 17,446 Earnings 4,818 5,123 3,656 Earnings attributable to Enbridge 1,816 2,056 1,600 December 31, 2023 2022 1 (millions of Canadian dollars) Current assets 5,842 5,328 Non-current assets 61,141 61,393 Current liabilities 6,194 5,631 Non-current liabilities 23,957 23,208 Noncontrolling interests 4,124 4,640 1 Balances have been updated to reflect the impact of revisions made to conform to the current year's presentation. These revisions do not have an effect on our previously reported consolidated statements of earnings, comprehensive income, changes in equity, cash flows or financial position.

INTANGIBLE ASSETS (Tables)

INTANGIBLE ASSETS (Tables)	12 Months Ended
INTANGIBLE ASSETS (Tables)	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Intangible Assets	December 31, 2023 Weighted Average Amortization Rate Cost Accumulated Amortization Net (millions of Canadian dollars) Software 12.0 % 1,921 (1,090) 831 Power purchase agreements 4.3 % 58 (24) 34 Project agreement 1 4.0 % 158 (41) 117 Customer relationships 8.6 % 2,636 (675) 1,961 Other intangible assets 8.2 % 603 (185) 418 Under development — % 176 — 176 5,552 (2,015) 3,537 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 1 Represents a project agreement acquired from the merger of Enbridge and Spectra Energy.

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
GOODWILL (Tables)	Dec. 31, 2023
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, 2022 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 3 — — — 392 — 392 Balance at December 31, 2022 1,2 8,547 18,106 5,397 388 2 32,440 Foreign exchange and other (205) (425) — (8) — (638) Acquisition 4 — 46 — — — 46 Balance at December 31, 2023 1,2 8,342 17,727 5,397 380 2 31,848 1 Gross goodwill as at December 31, 2023 and 2022 was $35.9 billion and $36.5 billion, respectively. 2 Accumulated impairment as at December 31, 2023 and 2022 was $4.1 billion. 3 In 2022, we recorded $392 million of goodwill related to the acquisition of TGE. Refer to Note 8 - Acquisitions and Dispositions . 4 In 2023, we recorded $46 million of goodwill related to the acquisition of Aitken Creek. Refer to Note 8 - Acquisitions and Dispositions .

OTHER CURRENT LIABILITIES (Tabl

OTHER CURRENT LIABILITIES (Tables)	12 Months Ended
OTHER CURRENT LIABILITIES (Tables)	Dec. 31, 2023
Payables and Accruals [Abstract]
Schedule of Other Current Liabilities	December 31, 2023 2022 (millions of Canadian dollars) Dividends payable 1,975 1,825 Deferred credits 1,313 1,056 Derivative liabilities (Note 23) 738 898 Taxes payable 596 683 Other 1,037 758 5,659 5,220

DEBT (Tables)

DEBT (Tables)	12 Months Ended
DEBT (Tables)	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of Debt	December 31, Weighted Average Interest Rate 10 Maturity 2023 2022 (millions of Canadian dollars) Enbridge Inc. US dollar senior notes 4.6 % 2024 - 2053 14,636 12,060 Medium-term notes 4.5 % 2024 - 2064 8,598 8,223 Sustainability-linked bonds 4.7 % 2032 - 2033 6,751 3,355 Fixed-to-fixed subordinated term notes 1 7.5 % 2080 - 2084 7,156 3,596 Fixed-to-floating rate subordinated term notes 2 5.8 % 2077 - 2078 5,828 6,736 Floating rate notes 3 2024 791 1,491 Fixed-to-floating non-call notes 6.0 % 2026 923 — Commercial paper and credit facility draws 4.7 % 2024 - 2028 3,177 7,984 Other 4 17 15 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 5.6 % 2025 - 2028 670 4,199 Other 4 263 7 Enbridge Energy Partners, L.P. Senior notes 6.5 % 2025 - 2045 3,231 3,320 Enbridge Gas Inc. Medium-term notes 4.2 % 2024 - 2053 10,185 9,535 Debentures 9.1 % 2024 - 2025 210 210 Commercial paper and credit facility draws 5.2 % 2025 400 2,000 Other 4 2 1 Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 4.0 % 2040 791 921 Enbridge Pipelines Inc. Medium-term notes 5 4.3 % 2024 - 2053 5,425 5,425 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 5.4 % 2025 449 312 Other 4 4 — Enbridge Southern Lights LP Senior notes 4.0 % 2040 214 222 Spectra Energy Capital, LLC Senior notes 7.0 % 2032 - 2038 228 234 Algonquin Gas Transmission, LLC Senior notes 3.3 % 2024 - 2029 1,121 1,152 East Tennessee Natural Gas, LLC Senior notes 3.1 % 2024 251 258 Texas Eastern Transmission, LP Senior notes 4.7 % 2028 - 2048 3,362 3,455 Spectra Energy Partners, LP Senior notes 4.3 % 2024 - 2045 4,220 4,336 Tri Global Energy, LLC Senior notes — 18 Blauracke GmbH 6 Senior notes 2.1 % 2032 521 — Westcoast Energy Inc. Medium-term notes 4.9 % 2024 - 2041 1,225 1,225 Debentures 8.1 % 2025 - 2026 275 275 Fair value adjustment 514 608 Other 7 (439) (393) Total debt 8 81,199 80,980 Current maturities (6,084) (6,045) Short-term borrowings 9 (400) (1,996) Long-term debt 74,715 72,939 1 For an initial five 2 For an initial five 3 The notes carry an interest rate equal to 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 In November 2023, as a part of the acquisition of an additional 49% interest in ERII, we assumed debt of $524 million (€358 million). As at December 31, 2023 $61 million (€42 million) and $460 million (€316 million) are recorded within Current portion of long-term debt and Long-term debt, respectively, on the Consolidated Statements of Financial Position. Refer to Note 13 - Long-Term Investments for further details on the transaction. 7 Primarily unamortized discounts, premiums and debt issuance costs. 8 2023 - $37 billion, US$33 billion and €359 million; 2022 - $38 billion, US$31 billion and nil. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment. 9 Weighted average interest rates on outstanding commercial paper were 5.2% as at December 31, 2023 (2022 - 4.5%). 10 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2023.
Schedule of Committed Credit Facilities	The following table provides details of our committed credit facilities as at December 31, 2023: Maturity 1 Total Facilities Draws 2 Available (millions of Canadian dollars) Enbridge Inc. 2024-2028 8,876 3,177 5,699 Enbridge (U.S.) Inc. 2025-2028 8,373 670 7,703 Enbridge Pipelines Inc. 2025 2,000 449 1,551 Enbridge Gas Inc. 2025 2,500 400 2,100 Total committed credit facilities 21,749 4,696 17,053 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	During the year ended December 31, 2023, we completed the following long-term debt issuances totaling US$8.5 billion and $3.9 billion: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. March 2023 5.70% sustainability-linked senior notes due March 2033 1 US$2,300 March 2023 5.97% senior notes due March 2026 2 US$700 May 2023 4.90% medium-term notes due May 2028 $600 May 2023 5.36% sustainability-linked medium-term notes due May 2033 3 $400 May 2023 5.76% medium-term notes due May 2053 $500 September 2023 8.50% fixed-to-fixed subordinated notes due January 2084 4 US$1,250 September 2023 8.25% fixed-to-fixed subordinated notes due January 2084 5 US$750 September 2023 8.75% fixed-to-fixed subordinated notes due January 2084 6 $700 September 2023 8.50% fixed-to-fixed subordinated notes due January 2084 7 $300 November 2023 5.90% senior notes due November 2026 US$750 November 2023 6.00% senior notes due November 2028 US$750 November 2023 6.20% senior notes due November 2030 US$750 November 2023 6.70% senior notes due November 2053 US$1,250 Enbridge Gas Inc. October 2023 5.46% medium-term notes due October 2028 $250 October 2023 5.70% medium-term notes due October 2033 $400 October 2023 5.67% medium-term notes due October 2053 $350 Enbridge Pipelines Inc. August 2023 5.82% medium-term notes due August 2053 $350 1 The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on September 8, 2031, the interest rate will be set to equal 5.70% plus 50 basis points. 2 We have the option to call the notes at par after one year from issuance. Refer to Note 23 - Risk Management and Financial Instruments . 3 The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on November 26, 2031, the interest rate will be set to equal 5.36% plus 50 basis points. 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 4.43%. Subsequent to year 10, every five years, the Five-year US treasury rate is reset. At year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.18%. 5 For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 3.79%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 4.04%. Subsequent to year 10, every five years, the Five-Year US Treasury rate is reset. At year 25, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.79%. 6 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 4.96%. Subsequent to year 10, every five years, the Government of Canada bond yield rate is reset. At year 30, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 5.71%. 7 For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.30%. At year 10, the interest rate will be reset to equal the Five-Year Government of Canada bond yield plus a margin of 4.55%. Subsequent to year 10, every five years, the Five-Year Government of Canada bond yield is reset. At year 25, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 5.30%.
Schedule of Long-Term Debt Repayments	During the year ended December 31, 2023, we completed the following long-term debt repayments totaling $1.4 billion and US$2.5 billion, respectively: Company Repayment Date Principal Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. January 2023 3.94% medium-term notes $275 February 2023 Floating rate notes 1 US$500 April 2023 6.38% fixed-to-floating rate subordinated notes 2 US$600 June 2023 3.94% medium-term notes $450 October 2023 4.00% senior notes US$800 October 2023 0.55% senior notes US$500 Enbridge Gas Inc. July 2023 6.05% medium-term notes $100 July 2023 3.79 % medium-term notes $250 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2023 3.98% senior notes US$80 Enbridge Pipelines Inc. August 2023 3.79% medium-term notes $250 November 2023 6.35% medium-term notes $100 Enbridge Southern Lights LP June 2023 4.01% senior notes $9 Tri Global Energy, LLC January 2023 10.00% senior notes US$4 January 2023 14.00% senior notes US$9 1 Notes carried an interest rate set to equal the SOFR plus a margin of 40 basis points. 2 The five-year callable notes, with an original maturity date of April 2078, were all redeemed at par.
Schedule of Maturities	As at December 31, 2023, 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 80,438 6,067 6,405 5,630 3,377 5,307 53,652 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.
Schedule of Interest Expense	INTEREST EXPENSE Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Debentures and term notes 3,439 2,910 2,806 Commercial paper and credit facility draws 519 388 114 Amortization of fair value adjustment (45) (45) (50) Capitalized interest (101) (74) (215) 3,812 3,179 2,655

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
ASSET RETIREMENT OBLIGATIONS (Tables)	Dec. 31, 2023
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, 2023 2022 (millions of Canadian dollars) Obligations at beginning of year 488 502 Liabilities acquired 1 — Liabilities incurred — 30 Liabilities settled (23) (126) Change in estimate and other 5 51 Foreign currency translation adjustment (6) 24 Accretion expense 28 7 Obligations at end of year 493 488 Presented as follows: Other current liabilities 136 83 Other long-term liabilities 357 405 493 488

NONCONTROLLING INTERESTS (Table

NONCONTROLLING INTERESTS (Tables)	12 Months Ended
NONCONTROLLING INTERESTS (Tables)	Dec. 31, 2023
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, 2023 2022 (millions of Canadian dollars) Algonquin Gas Transmission, LLC 384 400 Enbridge Athabasca Midstream Investor Limited Partnership 1 1,086 1,106 Maritimes & Northeast Pipeline, L.L.C. 559 582 Renewable energy assets 885 1,302 Maritimes & Northeast Pipeline Limited Partnership 111 117 Other 4 4 3,029 3,511 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 .

SHARE CAPITAL (Tables)

SHARE CAPITAL (Tables)	12 Months Ended
SHARE CAPITAL (Tables)	Dec. 31, 2023
Equity [Abstract]
Schedule of Common Shares	COMMON SHARES 2023 2022 2021 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 2,025 64,760 2,026 64,799 2,026 64,768 Shares issued, net of issue costs 103 4,485 — — — — Shares issued on exercise of stock options — 3 2 53 — 31 Shares issued on vesting of RSUs, net of tax — 12 — — — — Share purchases at stated value 1 (3) (80) (3) (88) — — Other — — — (4) — — Balance at end of year 2,125 69,180 2,025 64,760 2,026 64,799 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 2023 2022 2021 December 31, Number of Shares Amount Number of Shares Amount Number 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 20 500 18 457 Preference Shares, Series C 1 — — — — 2 43 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 18 454 20 500 20 500 Preference Shares, Series G 2 2 46 — — — — Preference Shares, Series H 12 291 14 350 14 350 Preference Shares, Series I 3 2 59 — — — — Preference Shares, Series J 4 — — — — 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 5 — — — — 30 750 Preference Shares, Series 19 20 500 20 500 20 500 Issuance costs (135) (135) (155) Balance at end of year 6,818 6,818 7,747 1 On June 1, 2022, all outstanding Preference Shares, Series C were converted to Preference Shares, Series B. 2 On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G. 3 On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I. 4 On June 1, 2022, we redeemed our US$200 million outstanding Cumulative Redeemable Preference Shares, Series J. 5 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 5.20 % $1.30052 $25 June 1, 2027 Series C Preference Shares, Series D 5 5.41 % $1.35300 $25 March 1, 2028 Series E Preference Shares, Series F 6 5.54 % $1.38452 $25 June 1, 2028 Series G Preference Shares, Series G 7 6.96 % $1.90704 $25 June 1, 2028 Series F Preference Shares, Series H 8 6.11 % $1.52800 $25 September 1, 2028 Series I Preference Shares, Series I 9 7.19 % $1.81004 $25 September 1, 2028 Series H Preference Shares, Series L 5.86 % US$1.46448 US$25 September 1, 2027 Series M Preference Shares, Series N 10 6.70 % $1.67400 $25 December 1, 2028 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 11 6.70 % US$1.67592 US$25 June 1, 2028 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 12 6.21 % $1.55300 $25 March 1, 2028 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. Preference Shares, Series G and I contain a feature where the dividend rate resets on a quarterly basis. 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 Per Share Base Redemption Value 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 Per Share Base Redemption Value. 4 With the exception of Preference Shares, Series A, after the Redemption and Conversion Option Date, 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 D was increased to $0.33825 from $0.27875 on March 1, 2023 due to reset of the annual dividend on March 1, 2023. 6 The quarterly dividend per share paid on Preference Shares, Series F was increased to $0.34613 from $0.29306 on June 1, 2023 due to reset of the annual dividend on June 1, 2023. 7 On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G. The quarterly dividend per share paid on Preference Shares, Series G was increased to $0.47676 from $0.47245 on December 1, 2023 due to reset on a quarterly basis. 8 The quarterly dividend per share paid on Preference Shares, Series H was increased to $0.38200 from $0.27350 on September 1, 2023 due to reset of the annual dividend on September 1, 2023. 9 On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I. The quarterly dividend per share paid on Preference Shares, Series I was increased to $0.45251 from $0.44814 on December 1, 2023 due to reset on a quarterly basis following the date of issuance. 10 The quarterly dividend per share paid on Preference Shares, Series N was increased to $0.41850 from $0.31788 on December 1, 2023 due to reset of the annual dividend on December 1, 2023. 11 The quarterly dividend per share paid on Preference Shares, Series 1 was increased to US$0.41898 from US$0.37182 on June 1, 2023 due to reset of the annual dividend on June 1, 2023. 12 The quarterly dividend per share paid on Preference Shares, Series 19 was increased to $0.38825 from $0.30625 on March 1, 2023 due to reset of the annual dividend on March 1, 2023.

STOCK OPTION AND STOCK UNIT P_2

STOCK OPTION AND STOCK UNIT PLANS (Tables)	12 Months Ended
STOCK OPTION AND STOCK UNIT PLANS (Tables)	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Schedule of Outstanding Stock Options	December 31, 2023 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (number of options in thousands; weighted average exercise price in Canadian dollars; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 27,624 48.46 Options granted 3,053 53.11 Options exercised 1 (648) 45.70 Options cancelled or expired (1,300) 53.84 Options outstanding at end of year 28,729 50.79 5.3 45 Options vested at end of year 2 20,235 50.64 4.1 36 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2023, 2022 and 2021 was $2 million, $66 million and $24 million, respectively, and cash received on exercise was nil, $3 million and $2 million, respectively. 2 The total fair value of ISOs vested during the years ended December 31, 2023, 2022 and 2021 was $20 million, $21 million and $25 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 model are as follows: Year ended December 31, 2023 2022 2021 Fair value per option (Canadian dollars) 1 6.05 5.07 4.10 Valuation assumptions Expected option term (years) 2 6 6 6 Expected volatility 3 22.2 % 21.9 % 25.5 % Expected dividend yield 4 6.7 % 6.5 % 7.6 % Risk-free interest rate 5 3.5 % 1.8 % 0.7 % 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 value per option for the years ended December 31, 2023, 2022 and 2021 were $5.38, $4.78 and $3.91, respectively, for Canadian employees and US$5.23, US$4.62 and US$3.65, 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, 2023 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (number of units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 3,249 Units granted 2,128 Units cancelled (214) Units matured 1 (2,218) Dividend reinvestment 235 Units outstanding at end of year 3,180 1.1 175 1 The total amount paid during the years ended December 31, 2023, 2022 and 2021 for PSUs was $123 million, $90 million and $70 million, respectively.
Schedule of Outstanding Stock Units	December 31, 2023 Number Weighted Average Grant Date Fair Value 2 Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (number of units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 3,565 49.64 Units granted 1,373 52.05 Units cancelled (246) 52.06 Units matured 1 (1,401) 51.05 Dividend reinvestment 280 50.88 Units outstanding at end of year 3,571 50.69 0.9 177 1 The total amount paid during the years ended December 31, 2023, 2022 and 2021 for RSUs was $56 million, $32 million and $72 million, respectively. 2 Weighted average grant date fair value excludes cash-settled units.

COMPONENTS OF ACCUMULATED OTH_2

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023, 2022 and 2021 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, 2023 121 (35) (1,137) 4,348 5 218 3,520 Other comprehensive income/(loss) retained in AOCI 232 62 409 (1,695) 6 (158) (1,144) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 28 — — — — — 28 Foreign exchange contracts 2 — (47) — — — — (47) Amortization of pension and OPEB actuarial gain 3 — — — — — (24) (24) 260 15 409 (1,695) 6 (182) (1,187) Tax impact Income tax on amounts retained in AOCI (47) (14) — — — 28 (33) Income tax on amounts reclassified to earnings (14) 11 — — — 6 3 (61) (3) — — — 34 (30) Balance as at December 31, 2023 320 (23) (728) 2,653 11 70 2,303 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 (income)/loss reclassified to earnings Interest rate contracts 1 186 — — — — — 186 Foreign exchange contracts 2 (4) — — — — — (4) Other contracts 4 4 — — — — — 4 Amortization of pension and OPEB actuarial gain 3 — — — — — (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 (income)/loss reclassified to earnings Interest rate contracts 1 296 — — — — — 296 Commodity contracts 5 1 — — — — — 1 Foreign exchange contracts 2 5 — — — — — 5 Other contracts 4 2 — — — — — 2 Equity investment disposal — — — — (66) — (66) Amortization of pension and OPEB actuarial loss and prior service costs 3 — — — — — 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) 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 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. 4 Reported within Operating and administrative 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
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of the Consolidated Statements of Financial Position Location And Carrying Value of Derivative Instruments	The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments, as well as the maximum potential settlement amounts, in the event of the specific circumstances described above. All amounts are presented gross in the Consolidated Statements of Financial Position. December 31, 2023 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) Other current assets Foreign exchange contracts — 41 98 139 (32) 107 Interest rate contracts 31 — 34 65 (32) 33 Commodity contracts — — 418 418 (270) 148 Other contracts — — 1 1 (1) — 31 41 551 623 (335) 288 Deferred amounts and other assets Foreign exchange contracts — 16 319 335 (122) 213 Interest rate contracts 51 — 2 53 (21) 32 Commodity contracts — — 75 75 (41) 34 51 16 396 463 (184) 279 Other current liabilities Foreign exchange contracts — (44) (84) (128) 32 (96) Interest rate contracts (183) — (3) (186) 32 (154) Commodity contracts (11) — (412) (423) 270 (153) Other contracts — — (1) (1) 1 — (194) (44) (500) (738) 335 (403) Other long-term liabilities Foreign exchange contracts — (17) (481) (498) 122 (376) Interest rate contracts (3) — (85) (88) 21 (67) Commodity contracts (7) — (159) (166) 41 (125) (10) (17) (725) (752) 184 (568) Total net derivative liability Foreign exchange contracts — (4) (148) (152) — (152) Interest rate contracts (104) — (52) (156) — (156) Commodity contracts (18) — (78) (96) — (96) Other contracts — — — — — — (122) (4) (278) (404) — (404) December 31, 2022 Derivative Derivative Instruments Used as Fair Value Hedges Non- Total Gross Amounts Total Net Derivative Instruments (millions of Canadian dollars) Other current assets Foreign exchange contracts — — 46 46 (41) 5 Interest rate contracts 649 — 11 660 — 660 Commodity contracts — — 302 302 (182) 120 Other contracts — — 7 7 — 7 649 — 366 1,015 (223) 792 Deferred amounts and other assets Foreign exchange contracts — 156 153 309 (138) 171 Interest rate contracts 254 — — 254 — 254 Commodity contracts — — 61 61 (25) 36 Other contracts 1 — 2 3 — 3 255 156 216 627 (163) 464 Other current liabilities Foreign exchange contracts — (42) (524) (566) 41 (525) Commodity contracts (48) — (284) (332) 182 (150) (48) (42) (808) (898) 223 (675) Other long-term liabilities Foreign exchange contracts — — (1,116) (1,116) 138 (978) Interest rate contracts (3) — (1) (4) — (4) Commodity contracts (37) — (133) (170) 25 (145) (40) — (1,250) (1,290) 163 (1,127) Total net derivative asset/(liability) Foreign exchange contracts — 114 (1,441) (1,327) — (1,327) Interest rate contracts 900 — 10 910 — 910 Commodity contracts (85) — (54) (139) — (139) Other contracts 1 — 9 10 — 10 816 114 (1,476) (546) — (546)
Schedule of The Maturity And Notional Principal or Quantity Outstanding Related to Derivative Instruments	The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments: 2023 2022 As at December 31, 2024 2025 2026 2027 2028 Thereafter Total Total Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) 1,360 500 — — — 1,860 2,155 Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) 6,582 5,327 4,697 4,091 3,162 888 24,747 27,610 Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) 30 30 28 32 — — 120 149 Foreign exchange contracts - Euro forwards - sell (millions of Euro) 141 126 121 81 67 195 731 697 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) — 84,800 — — — — 84,800 84,800 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 5,903 1,881 1,122 74 25 13 9,018 9,356 Interest rate contracts - short-term debt receive fixed rate (millions of Canadian dollars) 918 923 174 — — — 2,015 — Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 1 4,582 580 — — — — 5,162 7,851 Interest rate contracts - costless collar (millions of Canadian dollars) — 1,098 41 — — — 1,139 — Equity contracts (millions of Canadian dollars) 34 13 — — — — 47 80 Commodity contracts - natural gas (billions of cubic feet) 31 32 13 10 — — 86 93 Commodity contracts - crude oil (millions of barrels) 6 — — — — — 6 16 Commodity contracts - power (megawatt per hour (MW/H)) 49 (14) (26) (53) (57) (30) (22) 2 (14) 2 1 Represents the notional of long-term debt issuances hedged 2 Total is an average net purchase/(sale) of power.
Schedule of Effect of Cash Flow Hedges and Net Investment Hedges on Consolidated Earnings and Consolidated Comprehensive Income, Before Income Taxes	The following table presents foreign exchange derivative instruments that are designated and qualify as fair value hedges, the realized and unrealized 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, 2023 2022 (millions of Canadian dollars) Unrealized gain/(loss) on derivative (132) 262 Unrealized gain/(loss) on hedged item 131 (254) Realized loss on derivative (47) (110) Realized gain on hedged item — 85 The following table presents the effect of cash flow hedges and fair value hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes: Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts — 3 (29) Interest rate contracts 201 1,151 252 Commodity contracts 68 (53) (28) Other contracts (2) (4) 1 Fair value hedges Foreign exchange contracts 15 (35) (5) 282 1,062 191 Amount of loss reclassified from AOCI to earnings Foreign exchange contracts 1 — 13 5 Interest rate contracts 2 28 186 296 Commodity contracts 3 — — 1 Other contracts 3 — 4 2 28 203 304 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, 2023 2022 2021 (millions of Canadian dollars) Foreign exchange contracts 1 1,292 (1,344) 92 Interest rate contracts 2 (63) 10 2 Commodity contracts 3 (41) 50 71 Other contracts 4 (8) 4 8 Total unrealized derivative fair value gain/(loss), net 1,180 (1,280) 173 1 For the respective years ended, reported within Transportation and other services revenues (2023 - $645 million gain; 2022 - $238 million loss; 2021 - $98 million gain) and Other income/(expense) (2023 - $647 million gain; 2022 - $1,106 million loss; 2021 - $6 million loss) in the Consolidated Statements of Earnings. 2 Reported as an increase within Interest expense in the Consolidated Statements of Earnings. 3 For the respective years ended, reported within Transportation and other services revenues (2023 - $35 million loss; 2022 - $13 million gain; 2021 - $9 million gain), Commodity sales (2023 - $153 million gain; 2022 - $89 million gain; 2021 - $160 million gain), Commodity costs (2023 - $94 million loss; 2022 - $102 million loss; 2021 - $105 million loss) and Operating and administrative expense (2023 - $65 million loss; 2022 - $50 million gain; 2021 - $7 million gain) in the Consolidated Statements of Earnings. 4
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, 2023 2022 (millions of Canadian dollars) Canadian financial institutions 457 644 US financial institutions 252 277 European financial institutions 107 334 Asian financial institutions 121 224 Other 1 125 105 1,062 1,584 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, 2023 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 139 — 139 Interest rate contracts — 65 — 65 Commodity contracts 142 103 173 418 Other contracts — 1 — 1 142 308 173 623 Long-term derivative assets Foreign exchange contracts — 335 — 335 Interest rate contracts — 53 — 53 Commodity contracts — 24 51 75 — 412 51 463 Financial liabilities Current derivative liabilities Foreign exchange contracts — (128) — (128) Interest rate contracts — (186) — (186) Commodity contracts (136) (76) (211) (423) Other contracts — (1) — (1) . (136) (391) (211) (738) Long-term derivative liabilities Foreign exchange contracts — (498) — (498) Interest rate contracts — (88) — (88) Commodity contracts — (22) (144) (166) — (608) (144) (752) Total net financial asset/(liability) Foreign exchange contracts — (152) — (152) Interest rate contracts — (156) — (156) Commodity contracts 6 29 (131) (96) Other contracts — — — — 6 (279) (131) (404) December 31, 2022 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 46 — 46 Interest rate contracts — 660 — 660 Commodity contracts 65 90 147 302 Other contracts — 7 — 7 65 803 147 1,015 Long-term derivative assets Foreign exchange contracts — 309 — 309 Interest rate contracts — 254 — 254 Commodity contracts — 17 44 61 Other contracts — 3 — 3 — 583 44 627 Financial liabilities Current derivative liabilities Foreign exchange contracts — (566) — (566) Commodity contracts (60) (77) (195) (332) (60) (643) (195) (898) Long-term derivative liabilities Foreign exchange contracts — (1,116) — (1,116) Interest rate contracts — (4) — (4) Commodity contracts — (38) (132) (170) — (1,158) (132) (1,290) Total net financial asset/(liability) Foreign exchange contracts — (1,327) — (1,327) Interest rate contracts — 910 — 910 Commodity contracts 5 (8) (136) (139) Other contracts — 10 — 10 5 (415) (136) (546)
Schedule of Significant Unobservable Inputs Used in The Fair Value Measurement of Level 3 Derivative Instruments	The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2023 Fair Value Unobservable Input Minimum Price Maximum Price Weighted Average Price Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas (6) Forward gas price 2.66 8.29 3.78 $/mmbtu 2 Crude (7) Forward crude price 69.01 92.76 80.35 $/barrel Power (87) Forward power price 29.75 145.24 59.21 $/MW/H Commodity contracts - physical 1 Natural gas 14 Forward gas price 0.86 11.85 3.42 $/mmbtu 2 Crude (7) Forward crude price 64.51 98.11 82.85 $/barrel Power (38) Forward power price 18.20 164.84 58.46 $/MW/H (131) 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 the net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 31, 2023 2022 (millions of Canadian dollars) Level 3 net derivative liability at beginning of period (136) (108) Total gain/(loss), unrealized Included in earnings 1 (48) 6 Included in OCI 67 (54) Settlements (14) 20 Level 3 net derivative liability at end of year (131) (136) 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
INCOME TAXES (Tables)	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Income Tax Rate Reconciliation	INCOME TAX RATE RECONCILIATION Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Earnings before income taxes 7,879 4,542 7,729 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 1,182 681 1,159 Increase/(decrease) resulting from: Provincial and state income taxes 1 411 108 228 Foreign and other statutory rate differentials 2 187 295 134 Effects of rate-regulated accounting 3 (106) (122) (139) Write-off of regulatory deferrals 3,4 115 — — Part VI.1 tax, net of federal Part I deduction 3,5 66 76 73 US Minimum Tax 6 100 107 — Non-taxable portion of gain on sale of investmen t 3,7 — — (23) Valuation allowance 3 (12) 6 5 Accounting impairment of non-deductible goodwill 3,8 — 370 — Noncontrolling interests 3,9 19 9 (17) Investment and production tax credits (47) — — Other 3 (94) 74 (5) Income tax expense 1,821 1,604 1,415 Effective income tax rate 23.1 % 35.3 % 18.3 % 1 The change in provincial and state income taxes from 2022 to 2023 reflects the decrease in earnings from Canadian operations and changes to the state tax apportionment partially offset by a reduction in earnings from US operations before considering the 2022 non-deductible goodwill impairment. Refer to Note 15 - Goodwill. 2 The change in foreign and other statutory rate differentials from 2022 to 2023 reflects the decrease in earnings from US operations before considering the 2022 non-deductible goodwill impairment. Refer to Note 15 - Goodwill. 3 The provincial and state tax component of these items is included in the Provincial and state income taxes above. 4 The amount in 2023 includes the federal tax impact of the de-recognition of rate regulated accounting for income tax relating to Southern Lights Canada and portions of the Canadian Mainline including Line 9 and L3R. Refer to Note 7 - Regulatory Matters. 5 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada. 6 There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation. 7 The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco. 8 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 15 - Goodwill. 9 The amount includes the federal tax impact of impairment to Chapman Ranch in 2023 and Magic Valley in 2022 attributable to noncontrolling interests. Refer to Note 11 - Property, Plant and Equipment.
Schedule of Components of Pretax Earnings and Income Taxes	COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Earnings before income taxes Canada 2,233 583 3,399 US 4,620 2,865 3,336 Other 1,026 1,094 994 7,879 4,542 7,729 Current income taxes Canada 100 360 162 US 191 201 80 Other 110 86 82 401 647 324 Deferred income taxes Canada 456 (358) 344 US 974 1,309 741 Other (10) 6 6 1,420 957 1,091 Income tax expense 1,821 1,604 1,415
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, 2023 2022 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (9,202) (9,096) Investments (7,765) (7,099) Regulatory assets (1,338) (1,291) Other (52) (46) Total deferred income tax liabilities (18,357) (17,532) Deferred income tax assets Financial instruments 271 456 Loss carryforwards 1,745 2,259 Other 1,798 1,723 Total deferred income tax assets 3,814 4,438 Less valuation allowance (147) (215) Total deferred income tax assets, net 3,667 4,223 Net deferred income tax liabilities (14,690) (13,309) Presented as follows: Total deferred income tax assets 341 472 Total deferred income tax liabilities (15,031) (13,781) Net deferred income tax liabilities (14,690) (13,309)
Schedule of Unrecognized Tax Benefits	UNRECOGNIZED TAX BENEFITS Year ended December 31, 2023 2022 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 55 76 Gross decreases for tax positions of prior year (2) (17) Change in translation of foreign currency (1) 1 Lapses of statute of limitations (7) (5) Unrecognized tax benefits at end of year 45 55

PENSION AND OTHER POSTRETIREM_2

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	12 Months Ended
PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	Dec. 31, 2023
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, 2023 2022 2023 2022 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 3,630 4,600 1,029 1,184 Service cost 81 131 40 43 Interest cost 184 127 47 24 Participant contributions 31 29 — — Actuarial (gain)/loss 1 359 (1,069) 31 (201) Benefits paid (193) (187) (76) (94) Foreign currency exchange rate changes — — (29) 77 Other — (1) (6) (4) Projected benefit obligation at end of year 2 4,092 3,630 1,036 1,029 Change in plan assets Fair value of plan assets at beginning of year 4,234 4,536 1,080 1,160 Actual return/(loss) on plan assets 427 (235) 78 (64) Employer contributions 27 91 5 4 Participant contributions 31 29 — — Benefits paid (193) (187) (76) (94) Foreign currency exchange rate changes — — (29) 78 Other 2 — (6) (4) Fair value of plan assets at end of year 3 4,528 4,234 1,052 1,080 Overfunded status at end of year 436 604 16 51 Presented as follows: Deferred amounts and other assets 636 764 116 141 Other current liabilities (8) (9) (5) (5) Other long-term liabilities (192) (151) (95) (85) 436 604 16 51 1 Primarily due to the decrease in the discount rate used to measure the defined benefit obligations (2022 - primarily due to increase in the discount rate used to measure the defined benefit obligations). 2 The accumulated benefit obligation for our Canadian pension plans was $3.8 billion and $3.4 billion as at December 31, 2023 and 2022, respectively. The accumulated benefit obligation for our US pension plans was $1.0 billion as at December 31, 2023 and 2022. 3 Assets in the amount of $14 million (2022 - $10 million) and $62 million (2022 - $58 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, 2023 2022 2023 2022 (millions of Canadian dollars) Accumulated benefit obligation 394 360 99 89 Fair value of plan assets 243 218 — — Canada US December 31, 2023 2022 2023 2022 (millions of Canadian dollars) Projected benefit obligation 416 377 99 90 Fair value of plan assets 243 218 — —
Schedule of Amounts Recognized in AOCI	The amount of pre-tax AOCI relating to our pension plans are as follows: Canada US December 31, 2023 2022 2023 2022 (millions of Canadian dollars) Net actuarial (gain)/loss 51 (64) 74 40 Prior service cost — — 1 1 Total amount recognized in AOCI 1 51 (64) 75 41 1 Excludes amounts related to CTA. The amount of pre-tax AOCI relating to our OPEB plans are as follows: Canada US December 31, 2023 2022 2023 2022 (millions of Canadian dollars) Net actuarial gain (82) (101) (96) (102) Prior service credit (1) (1) (22) (30) Total amount recognized in AOCI 1 (83) (102) (118) (132) 1 Excludes amounts related to CTA.
Schedule of Net Benefit Costs Recognized	The components of net periodic benefit (credit)/cost and other amounts recognized in pre-tax Comprehensive income related to our pension plans are as follows: Canada US Year ended December 31, 2023 2022 2021 2023 2022 2021 (millions of Canadian dollars) Service cost 81 131 139 40 43 44 Interest cost 1 184 127 101 47 24 17 Expected return on plan assets 1 (271) (295) (252) (77) (85) (73) Amortization/settlement of net actuarial (gain)/loss 1 — 8 54 (4) — 11 Amortization/curtailment of prior service credit 1 — — — — (2) — Net periodic benefit (credit)/cost (6) (29) 42 6 (20) (1) Defined contribution benefit cost 12 10 7 — — — Net pension (credit)/cost recognized in Earnings 6 (19) 49 6 (20) (1) Amount recognized in OCI: Amortization/settlement of net actuarial (gain)/loss — (2) (25) 4 — (11) Amortization/curtailment of prior service credit — — — — 2 — Net actuarial (gain)/loss arising during the year 115 (288) (291) 30 (52) (99) Total amount recognized in OCI 115 (290) (316) 34 (50) (110) Total amount recognized in Comprehensive income 121 (309) (267) 40 (70) (111) 1 Reported within Other income/(expense) in the Consolidated Statements of Earnings. The components of net periodic benefit (credit)/cost and other amounts recognized in pre-tax Comprehensive income related to our OPEB plans are as follows: Canada US Year ended December 31, 2023 2022 2021 2023 2022 2021 (millions of Canadian dollars) Service cost 3 4 6 1 1 1 Interest cost 1 11 7 7 6 3 3 Expected return on plan assets 1 — — — (11) (12) (10) Amortization/settlement of net actuarial gain 1 (6) (1) — (6) (6) (1) Amortization/curtailment of prior service credit 1 — — — (8) (7) (7) Net periodic benefit (credit)/cost recognized in Earnings 8 10 13 (18) (21) (14) Amount recognized in OCI: Amortization/settlement of net actuarial gain 6 1 — 6 6 1 Amortization/curtailment of prior service credit — — — 8 7 7 Net actuarial (gain)/loss arising during the year 13 (67) (50) — (4) (80) Total amount recognized in OCI 19 (66) (50) 14 9 (72) Total amount recognized in Comprehensive income 27 (56) (37) (4) (12) (86) 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 2023 2022 2021 2023 2022 2021 Projected benefit obligation Discount rate 4.6 % 5.1 % 3.2 % 4.7 % 4.9 % 2.6 % Rate of salary increase 3.0 % 2.9 % 2.9 % 2.6 % 2.8 % 2.8 % Cash balance interest credit rate N/A N/A N/A 4.5 % 4.3 % 4.3 % Net periodic benefit cost Discount rate 5.3 % 3.2 % 2.6 % 4.9 % 2.6 % 2.2 % Rate of return on plan assets 6.5 % 6.6 % 6.2 % 7.4 % 7.4 % 7.3 % 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 % 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 2023 2022 2021 2023 2022 2021 Accumulated postretirement benefit obligation Discount rate 4.6 % 5.3 % 3.2 % 4.7 % 4.9 % 2.4 % Net periodic benefit cost Discount rate 5.3 % 3.2 % 2.6 % 4.9 % 2.4 % 2.0 % Rate of return on plan assets N/A N/A N/A 5.9 % 6.0 % 6.0 %
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, 2023 2022 2023 2022 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 211 274 136 173 Service cost 3 4 1 1 Interest cost 11 7 6 3 Participant contributions — — 5 6 Actuarial (gain)/loss 1 13 (66) 4 (37) Benefits paid (10) (8) (20) (21) Foreign currency exchange rate changes — — (3) 11 Accumulated postretirement benefit obligation at end of year 228 211 129 136 Change in plan assets Fair value of plan assets at beginning of year — — 185 201 Actual return/(loss) on plan assets — — 14 (21) Employer contributions 10 8 7 7 Participant contributions — — 5 6 Benefits paid (10) (8) (20) (21) Foreign currency exchange rate changes — — (4) 13 Fair value of plan assets at end of year — — 187 185 Overfunded/(underfunded) status at end of year (228) (211) 58 49 Presented as follows: Deferred amounts and other assets — — 73 75 Other current liabilities (12) (12) — — Other long-term liabilities (216) (199) (15) (26) (228) (211) 58 49 1 Primarily due to the decrease in the discount rate used to measure the defined benefit obligations (2022 - primarily due to increase in the discount rate used to measure the benefit obligations).
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, 2023 2022 2023 2022 (millions of Canadian dollars) Accumulated benefit obligation 228 211 78 76 Fair value of plan assets — — 63 50
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 2023 2022 2023 2022 Health care cost trend rate assumed for next year 4.0 % 4.0 % 4.7 % 4.7 % Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.0 % 4.0 % 3.3 % 3.3 % Year that the rate reaches the ultimate trend rate N/A N/A 2022 - 2045 2021 - 2045 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 2023 2022 Allocation 2023 2022 Equity securities 46.0 % 41.4 % 38.2 % 45.0 % 39.5 % 38.3 % Fixed income securities 23.2 % 29.6 % 31.7 % 20.0 % 19.4 % 20.5 % Alternatives 1 30.8 % 29.0 % 30.1 % 35.0 % 41.1 % 41.2 % 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, 2023 Cash and cash equivalents 227 — — 227 8 — — 8 Equity securities 4 Canada — 3 — 3 — — — — Global — 1,871 — 1,871 — 416 — 416 Fixed income securities 4 Government — 446 — 446 — 46 — 46 Corporate — 667 — 667 — 149 — 149 Alternatives 5 — — 1,290 1,290 — — 433 433 Forward currency contracts — 24 — 24 — — — — Total pension plan assets at fair value 227 3,011 1,290 4,528 8 611 433 1,052 December 31, 2022 Cash and cash equivalents 272 — — 272 13 — — 13 Equity securities 4 Canada — 355 — 355 — — — — Global — 1,263 — 1,263 — 414 — 414 Fixed income securities 4 Government 201 435 — 636 — 87 — 87 Corporate — 433 — 433 — 121 — 121 Alternatives 5 — — 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 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 Pension plan assets include $61 million (2022 - $32 million) of equity and fixed income securities investments held with related parties. 5 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, 2023 2022 2023 2022 (millions of Canadian dollars) Balance at beginning of year 1,291 1,064 445 337 Unrealized and realized gains/(losses) (41) 155 (12) 78 Purchases and settlements, net 40 72 — 30 Balance at end of year 1,290 1,291 433 445 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, 2023 Cash and cash equivalents 3 — — 3 Equity securities US — 36 — 36 Global — 62 — 62 Fixed income securities Government 42 3 — 45 Corporate — 12 — 12 Alternatives 4 — — 29 29 Total OPEB plan assets at fair value 45 113 29 187 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 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, 2023 2022 (millions of Canadian dollars) Balance at beginning of year 28 22 Unrealized and realized gains 1 4 Purchases and settlements, net — 2 Balance at end of year 29 28
Schedule of Expected Benefit Payments and Employer Contributions	Year ending December 31, 2024 2025 2026 2027 2028 2029-2033 (millions of Canadian dollars) Pension Canada 207 213 219 224 230 1,234 US 87 87 87 86 81 393 OPEB Canada 13 13 13 13 13 70 US 16 15 14 13 12 49

LEASES (Tables)

LEASES (Tables)	12 Months Ended
LEASES (Tables)	Dec. 31, 2023
Leases [Abstract]
Schedule of Assets and Liabilities, Lessee	Supplemental Statements of Financial Position Information December 31, 2023 December 31, 2022 (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 669 680 Operating lease liabilities - current 3 98 87 Operating lease liabilities - long-term 3 652 677 Total operating lease liabilities 750 764 Finance leases Finance lease right-of-use assets, net 4 287 62 Finance lease liabilities - current 5 19 17 Finance lease liabilities - long-term 5 264 39 Total finance lease liabilities 283 56 Weighted average remaining lease term Operating leases 12 years 12 years Finance leases 31 years 5 years Weighted average discount rate Operating leases 4.5 % 4.2 % Finance leases 5.7 % 4.4 % 1 Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2023 were $42 million (December 31, 2022 - $47 million), $5 million (December 31, 2022 - $5 million) and $38 million (December 31, 2022 - $43 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 lease liabilities are reported under Other current liabilities 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 and long-term finance lease liabilities are reported under Current portion of long-term debt and Long-term debt in the Consolidated Statements of Financial Position.
Schedule of Lessee, Operating Lease Liability, Maturity	As at December 31, 2023, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance (millions of Canadian dollars) 2024 130 31 2025 120 25 2026 106 25 2027 96 18 2028 75 18 Thereafter 459 502 Total undiscounted lease payments 986 619 Less imputed interest (236) (336) Total 750 283
Schedule of Lessee, Finance Lease Liability, Maturity	As at December 31, 2023, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance (millions of Canadian dollars) 2024 130 31 2025 120 25 2026 106 25 2027 96 18 2028 75 18 Thereafter 459 502 Total undiscounted lease payments 986 619 Less imputed interest (236) (336) Total 750 283
Schedule of Operating Lease, Lease Income	Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Operating lease income 241 266 263 Variable lease income 299 321 333 Total lease income 1 540 587 596 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, 2023, 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) 2024 225 2025 206 2026 201 2027 199 2028 201 Thereafter 1,612 Future lease payments 2,644

OTHER INCOME_(EXPENSE) (Tables)

OTHER INCOME/(EXPENSE) (Tables)	12 Months Ended
OTHER INCOME/(EXPENSE) (Tables)	Dec. 31, 2023
Other Income and Expenses [Abstract]
Schedule of Other Income and Expenses	Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Gain/(loss) on dispositions 15 (12) 319 Realized foreign currency gain/(loss) (129) 92 126 Unrealized foreign currency gain/(loss) 821 (1,094) 160 Net defined pension and OPEB credit 135 239 150 Other 382 186 224 1,224 (589) 979

CHANGES IN OPERATING ASSETS A_2

CHANGES IN OPERATING ASSETS AND LIABILITIES (Tables)	12 Months Ended
CHANGES IN OPERATING ASSETS AND LIABILITIES (Tables)	Dec. 31, 2023
CHANGES IN OPERATING ASSETS AND LIABILITIES
Schedule of Changes in Operating Assets and Liabilities	Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Trade receivables and unbilled revenues 1,125 (572) (1,030) Other current assets 1,278 (395) (198) Accounts receivable from affiliates 18 17 (38) Inventory 763 (599) (118) Deferred amounts and other assets 23 1 (195) Trade payables and accrued liabilities (1,542) 585 652 Other current liabilities 339 515 (565) Accounts payable to affiliates (66) 16 52 Interest payable 199 58 43 Other long-term liabilities 174 362 (69) 2,311 (12) (1,466)

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
RELATED PARTY TRANSACTIONS (Tables)	Dec. 31, 2023
Related Party Transactions [Abstract]
Schedule of Our Transactions with Equity Investees	Our transactions with significantly influenced investees are as follows: Year ended December 31, 2023 2022 2021 (millions of Canadian dollars) Transportation and other revenues 169 185 237 Commodity sales — 51 20 Operating and administrative 1 625 503 380 Commodity costs 2 63 778 790 Gas distribution costs 140 136 131 1 During the years ended December 31, 2023, 2022 and 2021, we had Operating and administrative costs from the Seaway Crude Pipeline System of $632 million, $495 million and $389 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

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
COMMITMENTS AND CONTINGENCIES (Tables)	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Schedule of Commitments	As at December 31, 2023, we have commitments as detailed below: Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Purchase of services, pipe and other materials, including transportation 1 11,018 4,193 1,421 1,206 1,039 996 2,163 Maintenance agreements 2 473 51 52 52 53 34 231 Right-of-ways commitments 3 1,328 44 45 45 45 45 1,104 Total 12,819 4,288 1,518 1,303 1,137 1,075 3,498 1 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. 2 Consists primarily of maintenance service contracts for our wind and solar assets. 3 Our right-of-way obligations primarily consist of non-lease agreements that existed at the time of adopting Topic 842 Leases, at which time we elected a practical expedient that allowed us to continue our historical treatment.

QUARTERLY FINANCIAL DATA (UNA_2

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	Dec. 31, 2023
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2023 Operating revenues 12,075 10,432 9,844 11,298 43,649 Operating income 2,662 2,350 1,794 1,845 8,651 Earnings 1,866 2,001 623 1,568 6,058 Earnings attributable to controlling interests 1,817 1,935 621 1,818 6,191 Earnings attributable to common shareholders 1,733 1,848 532 1,726 5,839 Earnings per common share Basic 0.86 0.91 0.26 0.81 2.84 Diluted 0.85 0.91 0.26 0.81 2.84 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

BUSINESS OVERVIEW (Details)

BUSINESS OVERVIEW (Details)	12 Months Ended
BUSINESS OVERVIEW (Details)	Dec. 31, 2023 segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments	5

SIGNIFICANT ACCOUNTING POLICI_3

SIGNIFICANT ACCOUNTING POLICIES - Revenue Recognition (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 246
Largest Non-Affiliated Customer \| Sales Revenue, Net \| Customer Concentration Risk
Disaggregation of Revenue [Line Items]
Concentration (percent)	10%	10%	13.50%
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 210	$ 238	$ 127

SIGNIFICANT ACCOUNTING POLICI_4

SIGNIFICANT ACCOUNTING POLICIES - Current Expected Credit Losses (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Allowance for doubtful accounts receivable	$ 100	$ 92

SIGNIFICANT ACCOUNTING POLICI_5

SIGNIFICANT ACCOUNTING POLICIES - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2023 depreciation_method
Accounting Policies [Abstract]
Number of primary methods of depreciation which are utilized	2

SIGNIFICANT ACCOUNTING POLICI_6

SIGNIFICANT ACCOUNTING POLICIES - Stock-Based Compensation (Details)	12 Months Ended
	Dec. 31, 2023
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 - Major Products and Se

REVENUE - Major Products and Services (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									$ 24,199	$ 23,916	$ 19,432
Total revenue	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 43,649	53,309	47,071
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]									Total revenue
Realized (loss) gain on derivative									$ (97)	(431)	59
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									155	127	70
Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									24,044	23,789	19,362
Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									17,991	17,077	14,532
Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									1,073	893	648
Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers										22	49
Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,859	5,643	4,026
Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									259	281	177
Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									17
Revenue not from contract with customers									18,964	29,150	26,873
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									486	243	766
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									12,132	11,518	9,639
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									12,132	11,518	9,639
Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,780	5,384	4,668
Gas Transmission and Midstream \| Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									17	0	0
Gas Transmission and Midstream \| Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,763	5,384	4,668
Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									6,028	6,733	4,948
Gas Distribution and Storage \| Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									138	127	70
Gas Distribution and Storage \| Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,890	6,606	4,878
Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									259	281	177
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									259	281	177
Business Segments \| Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									12,132	11,518	9,639
Total revenue									12,863	12,052	10,581
Business Segments \| Liquids Pipelines \| Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									11,875	11,283	9,492
Business Segments \| Liquids Pipelines \| Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									257	235	147
Business Segments \| Liquids Pipelines \| Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers										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]
Total revenue from contracts with customers									0
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									257	(81)	375
Business Segments \| Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,780	5,384	4,668
Total revenue									5,854	5,426	4,711
Business Segments \| Gas Transmission and Midstream \| Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,302	5,012	4,364
Business Segments \| Gas Transmission and Midstream \| Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									461	350	255
Business Segments \| Gas Transmission and Midstream \| Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers										22	49
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]
Total revenue from contracts with customers									17
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									72	39	42
Business Segments \| Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									6,028	6,733	4,948
Total revenue									5,976	6,729	4,980
Business Segments \| Gas Distribution and Storage \| Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									814	782	676
Business Segments \| Gas Distribution and Storage \| Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									355	308	246
Business Segments \| Gas Distribution and Storage \| Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers										0	0
Business Segments \| Gas Distribution and Storage \| Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,859	5,643	4,026
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]
Total revenue from contracts with customers									0
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									(58)	(20)	13
Business Segments \| Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									259	281	177
Total revenue									477	582	512
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
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									259	281	177
Business Segments \| Renewable Power Generation \| Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
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									215	305	336
Business Segments \| Energy Services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Total revenue									18,989	29,175	26,917
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
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]
Total revenue from contracts with customers									0
Revenue not from contract with customers									18,964	29,150	26,873
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 revenue									(510)	(655)	(630)
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
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]
Total revenue from contracts with customers									0
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	0
Intersegment revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(510)	(655)	(630)
Intersegment revenue \| Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									474	615	567
Intersegment revenue \| Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									2	3	1
Intersegment revenue \| Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									6	16	19
Intersegment revenue \| Renewable Power Generation
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									3	(4)	(1)
Intersegment revenue \| Energy Services
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									$ 25	$ 25	$ 44

REVENUE - Contract Balances (De

REVENUE - Contract Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Contract Receivables	$ 2,802	$ 3,183
Contract Assets	400	230
Contract Liabilities	$ 2,591	$ 2,241

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) $ in Millions	12 Months Ended
REVENUE - Narrative (Details) $ in Millions	Dec. 31, 2023 CAD ($)
Revenue from Contract with Customer [Abstract]
Contract with customer, liability, revenue recognized	$ (246)
Increase (decrease) in contract with customers, liability	632
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be fulfilled in future periods	$ 59,100
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period	1 year
Performance obligations expected to be fulfilled in future periods	$ 7,500

SEGMENTED INFORMATION - Schedul

SEGMENTED INFORMATION - Schedule of Segment (Details) $ in Millions, $ in Millions			3 Months Ended								12 Months Ended
	Aug. 17, 2022 CAD ($)	Aug. 17, 2022 USD ($)	Dec. 31, 2023 CAD ($)	Sep. 30, 2023 CAD ($)	Jun. 30, 2023 CAD ($)	Mar. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Sep. 30, 2022 CAD ($)	Jun. 30, 2022 CAD ($)	Mar. 31, 2022 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Segmented Information
Operating revenues (Note 4)			$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 43,649	$ 53,309	$ 47,071
Commodity and gas distribution costs											(21,366)	(32,589)	(28,702)
Operating and administrative											(8,600)	(8,219)	(6,712)
Impairment of long-lived assets											(419)	(541)
Impairment of goodwill (Note 15)											0	(2,465)	0
Income/(loss) from equity investments (Note 13)											1,816	2,056	1,600
Gain on joint venture merger transaction (Note 13)	$ 1,100	$ 832									0	1,076	0
Other income (Note 27)											1,224	(589)	979
Earnings/(loss) before interest, income taxes and depreciation and amortization											16,304	12,038	14,236
Depreciation and amortization											(4,613)	(4,317)	(3,852)
Interest expense (Note 17)											(3,812)	(3,179)	(2,655)
Income tax expense (Note 24)											(1,821)	(1,604)	(1,415)
Earnings			1,568	$ 623	$ 2,001	$ 1,866	(1,109)	$ 1,383	$ 607	$ 2,057	6,058	2,938	6,314
Capital expenditures											4,708	4,690	7,885
Property, plant and equipment, net			104,641				104,460				104,641	104,460	100,067
Liquids Pipelines
Segmented Information
Impairment of goodwill (Note 15)												0
Gas Transmission and Midstream
Segmented Information
Impairment of goodwill (Note 15)												(2,465)
Gas Distribution and Storage
Segmented Information
Impairment of goodwill (Note 15)												0
Business Segments \| Liquids Pipelines
Segmented Information
Operating revenues (Note 4)											12,863	12,052	10,581
Commodity and gas distribution costs											0	0	(25)
Operating and administrative											(4,629)	(4,287)	(3,431)
Impairment of long-lived assets											145	(245)
Impairment of goodwill (Note 15)												0
Income/(loss) from equity investments (Note 13)											1,007	785	759
Gain on joint venture merger transaction (Note 13)												0
Other income (Note 27)											113	59	13
Earnings/(loss) before interest, income taxes and depreciation and amortization											9,499	8,364	7,897
Capital expenditures											1,158	1,418	4,051
Property, plant and equipment, net			51,851				53,567				51,851	53,567	52,530
Business Segments \| Gas Transmission and Midstream
Segmented Information
Operating revenues (Note 4)											5,854	5,426	4,711
Commodity and gas distribution costs											(15)	0	0
Operating and administrative											(2,380)	(2,254)	(1,877)
Impairment of long-lived assets											0	0
Impairment of goodwill (Note 15)												(2,465)
Income/(loss) from equity investments (Note 13)											688	1,133	702
Gain on joint venture merger transaction (Note 13)												1,076
Other income (Note 27)											117	210	135
Earnings/(loss) before interest, income taxes and depreciation and amortization											4,264	3,126	3,671
Capital expenditures											1,944	1,690	2,420
Property, plant and equipment, net			31,016				29,666				31,016	29,666	27,028
Business Segments \| Gas Distribution and Storage
Segmented Information
Operating revenues (Note 4)											5,976	6,729	4,980
Commodity and gas distribution costs											(2,871)	(3,693)	(2,147)
Operating and administrative											(1,285)	(1,289)	(1,143)
Impairment of long-lived assets											(281)	0
Impairment of goodwill (Note 15)												0
Income/(loss) from equity investments (Note 13)											2	1	42
Gain on joint venture merger transaction (Note 13)												0
Other income (Note 27)											51	79	385
Earnings/(loss) before interest, income taxes and depreciation and amortization											1,592	1,827	2,117
Capital expenditures											1,451	1,499	1,343
Property, plant and equipment, net			18,766				17,857				18,766	17,857	16,904
Business Segments \| Renewable Power Generation
Segmented Information
Operating revenues (Note 4)											477	582	512
Commodity and gas distribution costs											(20)	(16)	0
Operating and administrative											(261)	(255)	(180)
Impairment of long-lived assets											(283)	(235)
Impairment of goodwill (Note 15)												0
Income/(loss) from equity investments (Note 13)											140	141	101
Gain on joint venture merger transaction (Note 13)												0
Other income (Note 27)											96	45	75
Earnings/(loss) before interest, income taxes and depreciation and amortization											149	262	508
Capital expenditures											100	50	16
Property, plant and equipment, net			2,706				3,082				2,706	3,082	3,315
Business Segments \| Energy Services
Segmented Information
Operating revenues (Note 4)											18,989	29,175	26,917
Commodity and gas distribution costs											(18,975)	(29,525)	(27,174)
Operating and administrative											(52)	(49)	(48)
Impairment of long-lived assets											0	(13)
Impairment of goodwill (Note 15)												0
Income/(loss) from equity investments (Note 13)											0	0	0
Gain on joint venture merger transaction (Note 13)												0
Other income (Note 27)											1	(5)	(8)
Earnings/(loss) before interest, income taxes and depreciation and amortization											(37)	(417)	(313)
Capital expenditures											0	0	1
Property, plant and equipment, net			4				6				4	6	23
Eliminations and Other
Segmented Information
Operating revenues (Note 4)											(510)	(655)	(630)
Commodity and gas distribution costs											515	645	644
Operating and administrative											7	(85)	(33)
Impairment of long-lived assets											0	(48)
Impairment of goodwill (Note 15)												0
Income/(loss) from equity investments (Note 13)											(21)	(4)	(4)
Gain on joint venture merger transaction (Note 13)												0
Other income (Note 27)											846	(977)	379
Earnings/(loss) before interest, income taxes and depreciation and amortization											837	(1,124)	356
Capital expenditures											55	33	54
Property, plant and equipment, net			$ 298				$ 282				$ 298	$ 282	$ 267

SEGMENTED INFORMATION - Geograp

SEGMENTED INFORMATION - Geographic Information and Property, Plant and Equipment (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Geographic Information
Operating revenues (Note 4)	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 43,649	$ 53,309	$ 47,071
Property, plant and equipment, net	104,641				104,460				104,641	104,460	100,067
Canada
Geographic Information
Operating revenues (Note 4)									23,781	27,498	20,474
Property, plant and equipment, net	48,570				47,602				48,570	47,602
US
Geographic Information
Operating revenues (Note 4)									19,868	25,811	$ 26,597
Property, plant and equipment, net	$ 56,071				$ 56,858				$ 56,071	$ 56,858

EARNINGS PER COMMON SHARE - Nar

EARNINGS PER COMMON SHARE - Narrative (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Antidilutive securities
Weighted average number of common shares outstanding (in shares)			2
Share options
Antidilutive securities
Anti-dilutive stock options excluded from diluted earnings per common share calculation (in shares)	19.3	10.4	18.6
Weighted average exercise price of antidilutive securities (in Canadian dollars per share)	$ 54.42	$ 56.49	$ 52.89

EARNINGS PER COMMON SHARE - Wei

EARNINGS PER COMMON SHARE - Weighted Average Shares Outstanding (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Weighted average shares outstanding (in shares)	2,056	2,025	2,023
Effect of dilutive options and RSUs (in shares)	2	4	2
Diluted weighted average shares outstanding (in shares)	2,058	2,029	2,025

REGULATORY MATTERS - Liquids Pi

REGULATORY MATTERS - Liquids Pipelines (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Public Utilities, General Disclosures [Line Items]
Regulatory Liabilities	$ 3,828	$ 3,791
Regulatory assets	5,707	6,467
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Regulatory deferred assets	1,900	$ 2,100
Decrease in regulatory tax asset	160
Deferred tax liabilities, regulatory assets	40
Southern Lights Pipeline
Public Utilities, General Disclosures [Line Items]
Deferred tax liabilities, regulatory assets	$ 23
Pre-determined after-tax rate of return on equity (ROE) (as a percent)	10%
Regulatory Liabilities	$ 151
Regulatory assets	$ 92

REGULATORY MATTERS - Enbridge G

REGULATORY MATTERS - Enbridge Gas Distribution Inc. (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Public Utilities, General Disclosures [Line Items]
Deferred amounts and other assets	$ 8,041	$ 9,542
Enbridge Gas Distribution
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%
Undepreciated capital projects	$ 41
Undepreciated integration capital costs	84
Deferred amounts and other assets	$ 156

REGULATORY MATTERS - Schedule o

REGULATORY MATTERS - Schedule of Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	$ 470	$ 604
Total long - term regulatory assets	5,237	5,863
Total regulatory assets	5,707	6,467
Regulatory Liabilities [Line Items]
Total current regulatory liabilities	307	167
Total long - term regulatory liabilities	3,521	3,624
Total regulatory liabilities	3,828	3,791
Purchase gas variance
Regulatory Liabilities [Line Items]
Total current regulatory liabilities	31	0
Other regulatory assets (liabilities)
Regulatory Liabilities [Line Items]
Total current regulatory liabilities	276	167
Total long - term regulatory liabilities	86	250
Future removal and restoration reserves
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities	1,693	1,615
U.S income Taxes
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities	854	918
Pipeline future abandonment costs (Note 23)
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities		610
Pension plans and OPEB
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities	143	231
Purchase gas variance
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	15	190
Total long - term regulatory assets	0	244
Under-recovery of fuel costs
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	75	109
Other regulatory assets (liabilities)
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	380	305
Total long - term regulatory assets	252	244
Deferred income taxes
Regulatory Assets [Line Items]
Total long - term regulatory assets	4,456	4,473
Long-term debt
Regulatory Assets [Line Items]
Total long - term regulatory assets	348	378
Negative salvage
Regulatory Assets [Line Items]
Total long - term regulatory assets	180	265
Accounting policy changes
Regulatory Assets [Line Items]
Total long - term regulatory assets	0	219
Pension plans and OPEB
Regulatory Assets [Line Items]
Total long - term regulatory assets	$ 1	$ 40

ACQUISITIONS AND DISPOSITIONS -

ACQUISITIONS AND DISPOSITIONS - Acquisitions (Narrative) (Details) $ / shares in Units, $ in Millions, $ in Millions											1 Months Ended			3 Months Ended	12 Months Ended
	Nov. 01, 2023 CAD ($)	Sep. 08, 2023 CAD ($) $ / shares shares	Sep. 05, 2023 CAD ($) agreement	Sep. 05, 2023 USD ($) agreement	Apr. 03, 2023 CAD ($)	Apr. 03, 2023 USD ($)	Sep. 27, 2022 CAD ($)	Sep. 27, 2022 USD ($)	Oct. 12, 2021 CAD ($)	Oct. 12, 2021 USD ($)	Nov. 30, 2023 CAD ($) offering	Sep. 30, 2023 CAD ($) offering	Sep. 30, 2023 USD ($) offering	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 CAD ($)	Nov. 01, 2023 USD ($)	Apr. 03, 2023 USD ($)	Sep. 27, 2022 USD ($)	Oct. 12, 2021 USD ($)
Public Offering
Business Acquisition [Line Items]
Stock issued during period, shares, new issues (in shares) \| shares		102,913,500
Sale of stock, price per share (in Canadian dollars per share) \| $ / shares		$ 44.70
Shares issued, net of issue costs		$ 4,600										$ 4,600
Private Placement
Business Acquisition [Line Items]
Number of offerings \| offering											4	2	2
Sale of stock, consideration received on transaction											$ 1,000		$ 5,500
Aitken Creek Gas Storage Facility
Business Acquisition [Line Items]
Ownership interest (as a percent)																93.80%
Aitken Creek North Gas Storage Facility
Business Acquisition [Line Items]
Ownership interest (as a percent)																100%
Aitken Creek Gas Storage Facility And Aitken Creek North Gas Storage Facility
Business Acquisition [Line Items]
Cash	$ 400
The East Ohio Gas Company, Questar Gas Company, And Wexpro Companies
Business Acquisition [Line Items]
Cash			$ 12,800	$ 9,400
Number of agreements \| agreement			3	3
Purchase price			$ 19,100	$ 14,000
Assumed debt			$ 6,300	$ 4,600
Tres Palacios Holdings LLC
Business Acquisition [Line Items]
Cash					$ 451	$ 335
Property, plant and equipment					790												$ 588
Business combination, recognized identifiable assets acquired and liabilities assumed, property, plant, and equipment					254												189
Long-term liabilities					7												5
Long-term debt					$ 248												$ 184
Tri Global Energy, LLC
Business Acquisition [Line Items]
Cash							$ 295	$ 215
Purchase price							344
Property, plant and equipment							3
Long-term liabilities							105
Long-term debt							18
Contingent future payment (up to)							72									$ 53		$ 53
Contingent consideration							$ 49									$ 36
Moda Midstream Operating, LLC (Moda)
Business Acquisition [Line Items]
Cash									$ 3,755	$ 3,000
Purchase price									3,942
Property, plant and equipment									1,480
Long-term liabilities									17
Contingent consideration									$ 187										$ 150
Acquisition-related expenses/transaction costs incurred															$ 21
Revenues generated by acquiree														$ 80
Earnings generated by acquiree														$ 9

ACQUISITIONS AND DISPOSITIONS_2

ACQUISITIONS AND DISPOSITIONS - Summary of Estimated Fair Values Assigned to Net Assets (Details) $ in Millions, $ in Millions	Nov. 01, 2023 CAD ($)	Sep. 27, 2022 CAD ($)	Sep. 27, 2022 USD ($)	Oct. 12, 2021 CAD ($)	Oct. 12, 2021 USD ($)	Dec. 31, 2023 CAD ($)	Nov. 01, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Sep. 27, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Oct. 12, 2021 USD ($)
Fair value of net assets acquired:
Goodwill						$ 31,848		$ 32,440		$ 32,775
Purchase price:
Goodwill expected tax deductible period	15 years
Aitken Creek Gas Storage Facility
Fair value of net assets acquired:
Current assets	$ 105
Property, plant and equipment	466
Current liabilities	20
Long-term liabilities	130
Goodwill	46					$ 46
Purchase price:
Cash	397
Contingent consideration	70
Purchase price	$ 467
Expected useful life	3 years 6 months						3 years 6 months
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		18
Long-term liabilities		105
Goodwill		392						$ 392
Purchase price:
Cash		295	$ 215
Contingent consideration		49					$ 36
Purchase price		$ 344
Expected useful life		3 years 6 months							3 years 6 months
Goodwill expected tax deductible period		15 years	15 years
Contingent future payment (up to)		$ 72					$ 53		$ 53
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

ACQUISITIONS AND DISPOSITIONS_3

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

ACQUISITIONS AND DISPOSITIONS_4

ACQUISITIONS AND DISPOSITIONS - Dispositions (Narrative) (Details) $ in Millions	12 Months Ended
	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
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 \| 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

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Receivables [Abstract]
Derivative assets (Note 23)	$ 623	$ 1,015
Regulatory assets (Note 7)	470	604
Gas imbalances	209	461
Income taxes receivable	347	323
Other	791	852
Other current assets	$ 2,440	$ 3,255

INVENTORY (Details)

INVENTORY (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Inventory Disclosure [Abstract]
Natural gas	$ 938	$ 1,491
Crude oil	413	652
Other	128	112
Total Inventory	$ 1,479	$ 2,255

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 137,199	$ 134,000
Total accumulated depreciation	(32,558)	(29,540)
Property, plant and equipment, net	$ 104,641	104,460
Pipelines
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (percent)	2.90%
Total property, plant and equipment	$ 66,698	66,528
Facilities and equipment
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (percent)	3.10%
Total property, plant and equipment	$ 37,634	37,028
Land and right-of-way
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (percent)	2.30%
Total property, plant and equipment	$ 3,600	3,637
Gas mains, services and other
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (percent)	2.60%
Total property, plant and equipment	$ 15,346	14,491
Storage
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (percent)	2.50%
Total property, plant and equipment	$ 4,929	3,477
Wind turbines, solar panels and other
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (percent)	4.10%
Total property, plant and equipment	$ 4,511	4,912
Other
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (percent)	10.10%
Total property, plant and equipment	$ 1,652	1,611
Under construction
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (percent)	0%
Total property, plant and equipment	$ 2,829	$ 2,316

PROPERTY, PLANT AND EQUIPMENT_2

PROPERTY, PLANT AND EQUIPMENT - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Depreciation expense	$ 4,000	$ 3,800	$ 3,500
Impairment loss	419	541
Magic Valley Wind Farm
Property, Plant and Equipment [Line Items]
Impairment loss		227
Chapman Ranch Wind Farm
Property, Plant and Equipment [Line Items]
Impairment loss	$ 251
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Assets
Cash and cash equivalents	$ 5,901	$ 861
Restricted cash	84	46
Other Assets, Current	2,440	3,255
Inventory	1,479	2,255
Current assets	14,399	12,147
Property, plant and equipment, net	104,641	104,460	$ 100,067
Long-term investments	16,793	15,936
Restricted long-term investments	717	593
Deferred amounts and other assets	8,041	9,542
Intangible assets, net	3,537	4,018
Total assets	180,317	179,608
Liabilities
Other current liabilities	5,659	5,220
Current liabilities	17,435	20,301
Long-term debt	74,715	72,939
Other long-term liabilities	8,653	9,189
Deferred income taxes	15,031	13,781
Liabilities	115,834	116,210
Variable Interest Entity, Primary Beneficiary
Assets
Cash and cash equivalents	442	426
Restricted cash	9	12
Trade receivables and unbilled revenue	144	185
Other Assets, Current	8	14
Inventory	11	12
Current assets	619	672
Property, plant and equipment, net	7,105	7,707
Long-term investments	14	14
Restricted long-term investments	106	98
Deferred amounts and other assets	148	158
Intangible assets, net	84	102
Total assets	8,076	8,751
Liabilities
Other current liabilities	145	152
Current liabilities	232	272
Long-term debt	1	0
Other long-term liabilities	971	859
Deferred income taxes	5	5
Liabilities	1,209	1,136
Net assets	6,867	7,615
Variable Interest Entity, Primary Beneficiary \| Related Party
Assets
Accounts receivable from affiliates	5	23
Liabilities
Trade payables and accrued liabilities	4	21
Variable Interest Entity, Primary Beneficiary \| Nonrelated Party
Liabilities
Trade payables and accrued liabilities	$ 83	$ 99

VARIABLE INTEREST ENTITIES - _2

VARIABLE INTEREST ENTITIES - Schedule of the Carrying Amount of Interest in VIEs (Details) $ in Millions	Dec. 31, 2023 CAD ($)	Nov. 15, 2023	Dec. 31, 2022 CAD ($) project
Fox Squirrel Solar LLC
VARIABLE INTEREST ENTITY
Ownership interest (as a percent)		50%
Variable Interest Entity, Not Primary Beneficiary
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	$ 1,909		$ 1,616
Maximum exposure to loss	4,647		4,466
Variable Interest Entity, Not Primary Beneficiary \| Aux Sable Liquid Products L.P.
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	105		91
Maximum exposure to loss	130		117
Variable Interest Entity, Not Primary Beneficiary \| EIH S.a.r.l.
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE			37
Maximum exposure to loss			$ 637
Number of offshore wind projects \| project			3
Variable Interest Entity, Not Primary Beneficiary \| EIH S.a.r.l. \| Affiliated Entity
VARIABLE INTEREST ENTITY
Affiliate loan receivable			$ 56
Variable Interest Entity, Not Primary Beneficiary \| Rampion Offshore Wind Limited
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	391		413
Maximum exposure to loss	452		468
Variable Interest Entity, Not Primary Beneficiary \| Vector Pipeline L.P.
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	191		195
Maximum exposure to loss	320		325
Credit facility provided	105		105
Variable Interest Entity, Not Primary Beneficiary \| Vector Pipeline L.P. \| Affiliated Entity
VARIABLE INTEREST ENTITY
Affiliate loan receivable	24		25
Variable Interest Entity, Not Primary Beneficiary \| Woodfibre LNG LP
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	778		635
Maximum exposure to loss	2,854		2,476
Variable Interest Entity, Not Primary Beneficiary \| Fox Squirrel Solar LLC
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	312
Maximum exposure to loss	661
Variable Interest Entity, Not Primary Beneficiary \| Other
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	132		245
Maximum exposure to loss	$ 230		$ 443

LONG-TERM INVESTMENTS - Schedul

LONG-TERM INVESTMENTS - Schedule of Long-Term Investments (Details) $ in Millions, $ in Millions

Dec. 13, 2023 CAD ($)

Jan. 09, 2023 CAD ($)

Jan. 09, 2023 USD ($)

Nov. 29, 2022 CAD ($)

Nov. 29, 2022 USD ($)

Nov. 02, 2022 CAD ($)

Nov. 02, 2022 USD ($)

Dec. 31, 2023 CAD ($)

Nov. 30, 2023

Nov. 15, 2023

Dec. 31, 2022 CAD ($)

Aug. 17, 2022

Aug. 16, 2022

Oct. 12, 2021

Mar. 18, 2021 project

LONG-TERM INVESTMENTS

Total long-term investments

$ 16,793

$ 15,936

Woodfibre LNG Limited

LONG-TERM INVESTMENTS

Payments to acquire equity method investments

$ 533

$ 392

DCP Midstream, LLC

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

90%

Fox Squirrel Solar LLC

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

50%

Gray Oak Pipeline, LLC

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

65%

Gray Oak Holdings LLC

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

58.50%

22.80%

DCP Midstream, LP

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

13.20%

Éolien Maritime France SAS

LONG-TERM INVESTMENTS

Number of offshore wind projects | project

Other long-term investments | Gas Distribution and Storage

LONG-TERM INVESTMENTS

Other long-term investments

$ 24

MaRen Bakken Company LLC | MaRen Bakken Company LLC | Liquids Pipelines

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

75%

Equity method investments

$ 1,819

1,968

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 method investments

$ 1,486

1,394

DCP Midstream, LLC | DCP Midstream, LLC | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

23.40%

Equity method investments

$ 367

317

DCP Midstream, LLC | DCP Midstream, LP

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

56.50%

Seaway Crude Holdings LLC | Seaway Crude Holdings LLC | Liquids Pipelines

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

50%

Equity method investments

$ 2,661

2,744

Illinois Extension Pipeline Company, LLC | Illinois Extension Pipeline Company, LLC | Liquids Pipelines

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

65%

Equity method investments

$ 584

622

Cactus II Pipeline, LLC | Cactus II Pipeline, LLC | Liquids Pipelines

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

10%

30%

20%

Equity method investments

$ 618

658

Cash consideration

$ 241

$ 177

Other | Other | Liquids Pipelines

LONG-TERM INVESTMENTS

Equity method investments

Other | Other | Gas Distribution and Storage

LONG-TERM INVESTMENTS

Equity method investments

Other | Other | Renewable Power Generation

LONG-TERM INVESTMENTS

Equity method investments

$ 110

107

Other | Other | Minimum | Liquids Pipelines

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

3,000%

Other | Other | Minimum | Gas Distribution and Storage

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

30%

Other | Other | Minimum | Renewable Power Generation

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

1,640%

Other | Other | Maximum | Liquids Pipelines

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

4,380%

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)

5,000%

Alliance Pipeline | Alliance Pipeline

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 method investments

$ 359

430

Aux Sable | Aux Sable | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Equity method investments

$ 229

214

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%

Pembina Pipeline Corporation | Pembina Pipeline Corporation

LONG-TERM INVESTMENTS

Payments to acquire equity method investments

$ 3,100

Payments on nonrecourse debt

$ 300

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 method investments

$ 1,224

1,274

NEXUS Gas Transmission, LLC | NEXUS Gas Transmission, LLC | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

50%

Equity method investments

$ 1,220

1,813

Sabal Trail Transmission, LLC | Sabal Trail Transmission, LLC | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

50%

Equity method investments

$ 1,467

1,535

Southeast Supply Header, LLC | Southeast Supply Header, LLC | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

50%

Equity method investments

$ 80

Steckman Ridge, LP | Steckman Ridge, LP | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

50%

Equity method investments

$ 87

Vector Pipeline Limited | Vector Pipeline Limited | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

60%

Equity method investments

$ 191

195

Woodfibre LNG Limited Partnership10 | Woodfibre LNG Limited Partnership10 | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

30%

Equity method investments

$ 777

635

Offshore - various joint ventures | Offshore - various joint ventures | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Equity method investments

$ 217

314

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. | Renewable Power Generation

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

51%

Equity method investments

$ 52

Hohe See and Albatros Offshore Wind Facilities | Hohe See and Albatros Offshore Wind Facilities | Renewable Power Generation

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

49.90%

Equity method investments

$ 1,701

163

Rampion Offshore Wind Limited | Rampion Offshore Wind Limited | Renewable Power Generation

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

24.90%

Equity method investments

$ 391

413

East-West Tie Limited Partnership | East-West Tie Limited Partnership | Renewable Power Generation

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

24.10%

Equity method investments

$ 132

241

Fox Squirrel Solar LLC | Fox Squirrel Solar LLC | Renewable Power Generation

LONG-TERM INVESTMENTS

Ownership Interest (as a percent)

50%

Equity method investments

$ 312

Ara Divert HoldCo, Inc. | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Other long-term investments

106

Other long-term investments | Gas Transmission and Midstream

LONG-TERM INVESTMENTS

Other long-term investments

Other long-term investments | Renewable Power Generation

LONG-TERM INVESTMENTS

Other long-term investments

Other long-term investments | Eliminations and Other

LONG-TERM INVESTMENTS

Other long-term investments

$ 430

$ 488

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)

68.50%

58.50%

Cash consideration

$ 230

$ 172

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, $ in Millions										12 Months Ended
	Nov. 15, 2023 CAD ($)	Nov. 15, 2023 USD ($)	Nov. 03, 2023 CAD ($)	Nov. 03, 2023 EUR (€)	Nov. 29, 2022 CAD ($)	Nov. 29, 2022 USD ($)	Aug. 17, 2022 CAD ($)	Aug. 17, 2022 USD ($)	Dec. 30, 2021 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Nov. 03, 2023 EUR (€)	Jan. 09, 2023	Aug. 16, 2022	Jun. 06, 2021
Schedule of Equity Method Investments [Line Items]
Goodwill of investee										$ 3,500		$ 3,400
Amortizable assets of investee										1,700		1,500
Dividends received from equity investments										3,100		2,600	$ 2,200
Long-term debt										80,438
Proceeds from sale of equity method investments							$ 522	$ 404
Gain on joint venture merger transaction							$ 1,100	$ 832		0		1,076	0
Proceeds from joint venture merger transaction (Note 13)										0		522	0
Woodfibre LNG Limited
Schedule of Equity Method Investments [Line Items]
Payments to acquire equity method investments					$ 533	$ 392
Fox Squirrel Solar LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50%	50%
Cash consideration includes an upfront payment	$ 157	$ 115								$ 164	$ 123
Investment company committed capital threshold amount	$ 398	$ 291
Gray Oak Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)										65%
Gray Oak Pipeline, LLC \| Gray Oak Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)										58.50%					68.50%
Equity method investment direct ownership interest (as a percent)															0.100
Woodfibre LNG Limited
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)					30%	30%
Hohe See Offshore And Albatros Offshore Wind Farm
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)			49.90%											49.90%
Ownership interest acquired additionally (as a percent)			24.45%											24.45%
Payments to acquire equity method investments			$ 391	€ 267
Long-term debt			$ 524											€ 358
Gray Oak Holdings LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)							58.50%	58.50%								22.80%
DCP LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)							13.20%	13.20%								28.30%
Noverco Preferred Shares
Schedule of Equity Method Investments [Line Items]
Gain on joint venture merger transaction													303
Proceeds from joint venture merger transaction (Note 13)									$ 1,100
Noverco Preferred Shares \| IPL Systems Inc
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)																	38.90%
PennEast Pipeline Company, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)										20%
Impairment of equity investments													$ 111
Equity investment										$ 0		$ 0

LONG-TERM INVESTMENTS - Summary

LONG-TERM INVESTMENTS - Summary of Combined Financial Information (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income statement information
Operating revenues (Note 4)	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 43,649	$ 53,309	$ 47,071
Earnings	1,568	623	2,001	1,866	(1,109)	1,383	607	2,057	6,058	2,938	6,314
Earnings attributable to controlling interests	1,818	$ 621	$ 1,935	$ 1,817	(983)	$ 1,362	$ 595	$ 2,029	6,191	3,003	6,189
Balance sheet information
Current assets	14,399				12,147				14,399	12,147
Current liabilities	17,435				20,301				17,435	20,301
Noncontrolling interests	3,029				3,511				3,029	3,511
Unconsolidated equity method investments
Income statement information
Operating revenues (Note 4)									22,586	30,026	22,551
Operating expenses									17,111	23,835	17,446
Earnings									4,818	5,123	3,656
Earnings attributable to controlling interests									1,816	2,056	$ 1,600
Balance sheet information
Current assets	5,842				5,328				5,842	5,328
Non-current assets	61,141				61,393				61,141	61,393
Current liabilities	6,194				5,631				6,194	5,631
Non-current liabilities	23,957				23,208				23,957	23,208
Noncontrolling interests	$ 4,124				$ 4,640				$ 4,124	$ 4,640

INTANGIBLE ASSETS (Details)

INTANGIBLE ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
INTANGIBLE ASSETS
Cost	$ 5,552	$ 5,726
Accumulated Amortization	(2,015)	(1,708)
Net	$ 3,537	$ 4,018
Software
INTANGIBLE ASSETS
Weighted Average Amortization Rate	12%	10.90%
Cost	$ 1,921	$ 2,019
Accumulated Amortization	(1,090)	(1,042)
Net	$ 831	$ 977
Power purchase agreements
INTANGIBLE ASSETS
Weighted Average Amortization Rate	4.30%	4.20%
Cost	$ 58	$ 64
Accumulated Amortization	(24)	(23)
Net	$ 34	$ 41
Project agreement
INTANGIBLE ASSETS
Weighted Average Amortization Rate	4%	4%
Cost	$ 158	$ 163
Accumulated Amortization	(41)	(36)
Net	$ 117	$ 127
Customer relationships
INTANGIBLE ASSETS
Weighted Average Amortization Rate	8.60%	8.60%
Cost	$ 2,636	$ 2,701
Accumulated Amortization	(675)	(459)
Net	$ 1,961	$ 2,242
Other intangible assets
INTANGIBLE ASSETS
Weighted Average Amortization Rate	8.20%	5.90%
Cost	$ 603	$ 621
Accumulated Amortization	(185)	(148)
Net	$ 418	$ 473
Under development
INTANGIBLE ASSETS
Weighted Average Amortization Rate	0%	0%
Cost	$ 176	$ 158
Accumulated Amortization	0	0
Net	$ 176	$ 158

INTANGIBLE ASSETS - Narrative (

INTANGIBLE ASSETS - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense for intangible assets	$ 535	$ 483	$ 348
2024	514
2025	514
2026	514
2027	514
2028	$ 514

GOODWILL (Details)

GOODWILL (Details) - CAD ($) $ in Millions	12 Months Ended
GOODWILL (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Sep. 27, 2022	Oct. 12, 2021
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 32,440	$ 32,775
Impairment	0	(2,465)	$ 0
Foreign exchange and other	(638)	1,738
Acquisition	46	392
Goodwill, ending balance	31,848	32,440	32,775
Goodwill [Abstract]
Goodwill, gross at end of period	35,900	36,500
Goodwill accumulated impairment	4,100	4,100
Goodwill	31,848	32,440	32,775
Impairment of goodwill (Note 15)	0	2,465	0
Moda Midstream Operating, LLC (Moda)
Goodwill [Abstract]
Goodwill					$ 268
Tri Global Energy, LLC
Goodwill [Roll Forward]
Goodwill, beginning balance	392
Goodwill, ending balance		392
Goodwill [Abstract]
Goodwill		392		$ 392
Liquids Pipelines
Goodwill [Roll Forward]
Goodwill, beginning balance	8,547	8,041
Impairment		0
Foreign exchange and other	(205)	506
Acquisition	0	0
Goodwill, ending balance	8,342	8,547	8,041
Goodwill [Abstract]
Goodwill	8,342	8,547	8,041
Impairment of goodwill (Note 15)		0
Gas Transmission and Midstream
Goodwill [Roll Forward]
Goodwill, beginning balance	18,106	19,335
Impairment		(2,465)
Foreign exchange and other	(425)	1,236
Acquisition	46	0
Goodwill, ending balance	17,727	18,106	19,335
Goodwill [Abstract]
Goodwill	17,727	18,106	19,335
Impairment of goodwill (Note 15)		2,465
Gas Distribution and Storage
Goodwill [Roll Forward]
Goodwill, beginning balance	5,397	5,397
Impairment		0
Foreign exchange and other	0	0
Acquisition	0	0
Goodwill, ending balance	5,397	5,397	5,397
Goodwill [Abstract]
Goodwill	5,397	5,397	5,397
Impairment of goodwill (Note 15)		0
Renewable Power Generation
Goodwill [Roll Forward]
Goodwill, beginning balance	388	0
Impairment		0
Foreign exchange and other	(8)	(4)
Acquisition	0	392
Goodwill, ending balance	380	388	0
Goodwill [Abstract]
Goodwill	380	388	0
Impairment of goodwill (Note 15)		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 15)		0
Gas Transmission Assets
Goodwill [Roll Forward]
Impairment	0	(2,500)
Goodwill [Abstract]
Impairment of goodwill (Note 15)	$ 0	$ 2,500

OTHER CURRENT LIABILITIES (Deta

OTHER CURRENT LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Payables and Accruals [Abstract]
Dividends payable	$ 1,975	$ 1,825
Deferred credits	1,313	1,056
Derivative liabilities (Note 23)	738	898
Taxes payable	596	683
Other	1,037	758
Other current liabilities	$ 5,659	$ 5,220

DEBT - Schedule of Debt (Detail

DEBT - Schedule of Debt (Details) € in Millions, $ in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 EUR (€)	Dec. 31, 2021 CAD ($)
DEBT
Total debt	$ 81,199		$ 80,980
Fair value adjustment	514		608
Other	(439)		(393)
Current maturities	(6,084)		(6,045)
Short-term borrowings	(400)		(1,996)
Long-term debt	74,715		72,939
Long-term debt	$ 37,000	$ 33	$ 38,000	$ 31	€ 359	$ 0
Weighted average interest rate (as a percent)	5.20%	5.20%	4.50%	4.50%	4.50%
US dollar senior notes \| Enbridge Inc.
DEBT
Weighted average interest rate (percent)	4.60%	4.60%
Total debt	$ 14,636		$ 12,060
Medium-term notes \| Enbridge Gas Inc.
DEBT
Weighted average interest rate (percent)	4.20%	4.20%
Total debt	$ 10,185		9,535
Medium-term notes \| Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (percent)	4.30%	4.30%
Total debt	$ 5,425		5,425
Carrying value	$ 100
Medium-term notes \| Westcoast Energy Inc.
DEBT
Weighted average interest rate (percent)	4.90%	4.90%
Total debt	$ 1,225		1,225
Medium-term notes \| Enbridge Inc.
DEBT
Weighted average interest rate (percent)	4.50%	4.50%
Total debt	$ 8,598		8,223
Sustainability-linked bonds \| Enbridge Inc.
DEBT
Weighted average interest rate (percent)	4.70%	4.70%
Total debt	$ 6,751		3,355
Fixed-to-fixed subordinated term notes \| Enbridge Inc.
DEBT
Weighted average interest rate (percent)	7.50%	7.50%
Total debt	$ 7,156		3,596
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)	5.80%	5.80%
Total debt	$ 5,828		6,736
Fixed-to-floating rate subordinated term notes \| Enbridge Inc. \| Initial Period
DEBT
Term of fixed rate	5 years
Fixed-to-floating rate subordinated term notes \| Enbridge Inc. \| Subsequent period
DEBT
Term of fixed rate	10 years
Floating rate notes \| Enbridge Inc.
DEBT
Total debt	$ 791		1,491
Fixed-to-floating non-call notes \| Enbridge Inc.
DEBT
Weighted average interest rate (percent)	6%	6%
Total debt	$ 923		0
Commercial paper and credit facility draws \| Enbridge (U.S.) Inc.
DEBT
Weighted average interest rate (percent)	5.60%	5.60%
Total debt	$ 670		4,199
Commercial paper and credit facility draws \| Enbridge Gas Inc.
DEBT
Weighted average interest rate (percent)	5.20%	5.20%
Total debt	$ 400		2,000
Commercial paper and credit facility draws \| Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (percent)	5.40%	5.40%
Total debt	$ 449		312
Commercial paper and credit facility draws \| Enbridge Inc.
DEBT
Weighted average interest rate (percent)	4.70%	4.70%
Total debt	$ 3,177		7,984
Senior notes \| Enbridge Energy Partners, L.P.
DEBT
Weighted average interest rate (percent)	6.50%	6.50%
Total debt	$ 3,231		3,320
Senior notes \| Enbridge Pipelines (Southern Lights) L.L.C.
DEBT
Weighted average interest rate (percent)	4%	4%
Total debt	$ 791		921
Senior notes \| Enbridge Southern Lights LP
DEBT
Weighted average interest rate (percent)	4%	4%
Total debt	$ 214		222
Senior notes \| Spectra Energy Capital, LLC
DEBT
Weighted average interest rate (percent)	7%	7%
Total debt	$ 228		234
Senior notes \| Algonquin Gas Transmission, LLC
DEBT
Weighted average interest rate (percent)	3.30%	3.30%
Total debt	$ 1,121		1,152
Senior notes \| East Tennessee Natural Gas, LLC
DEBT
Weighted average interest rate (percent)	3.10%	3.10%
Total debt	$ 251		258
Senior notes \| Texas Eastern Transmission, LP
DEBT
Weighted average interest rate (percent)	4.70%	4.70%
Total debt	$ 3,362		3,455
Senior notes \| Spectra Energy Partners, LP
DEBT
Weighted average interest rate (percent)	4.30%	4.30%
Total debt	$ 4,220		4,336
Senior notes \| Tri Global Energy, LLC
DEBT
Weighted average interest rate (percent)
Total debt	$ 0		18
Senior notes \| Blauracke GmbH6
DEBT
Weighted average interest rate (percent)	2.10%	2.10%
Total debt	$ 521		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	263		7
Other \| Enbridge Gas Inc.
DEBT
Total debt	2		1
Other \| Enbridge Pipelines Inc.
DEBT
Total debt	4		0
Other \| Enbridge Inc.
DEBT
Total debt	$ 17		$ 15
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	12 Months Ended
	Dec. 31, 2023 CAD ($)
Committed credit facilities
DEBT
Total Facilities	$ 21,749
Draws	4,696
Available	$ 17,053
Term out option period	1 year
Enbridge (U.S.) Inc.
DEBT
Total Facilities	$ 8,373
Draws	670
Available	7,703
Enbridge Pipelines Inc.
DEBT
Total Facilities	2,000
Draws	449
Available	1,551
Enbridge Gas Inc.
DEBT
Total Facilities	2,500
Draws	400
Available	2,100
Enbridge Inc.
DEBT
Total Facilities	8,876
Draws	3,177
Available	$ 5,699

DEBT - Credit Facilities Narrat

DEBT - Credit Facilities Narrative (Details)		1 Months Ended			12 Months Ended
DEBT - Credit Facilities Narrative (Details)	Sep. 08, 2023 CAD ($)	Sep. 30, 2023 CAD ($)	Jul. 31, 2023 CAD ($)	Mar. 31, 2023 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 USD ($)	Sep. 30, 2023 USD ($)	Feb. 28, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Line of Credit Facility [Line Items]
Long-term debt					$ 74,715,000,000					$ 72,939,000,000
Principal amount					3,900,000,000		$ 8,500,000,000
Extinguishment of debt					1,400,000,000	$ 2,500,000,000
Public Offering
Line of Credit Facility [Line Items]
Shares issued, net of issue costs	$ 4,600,000,000	$ 4,600,000,000
Enbridge Gas Inc.
Line of Credit Facility [Line Items]
Credit facility capacity					2,500,000,000
Unutilized credit facility					2,100,000,000
Enbridge Pipelines Inc.
Line of Credit Facility [Line Items]
Credit facility capacity					2,000,000,000
Unutilized credit facility					1,551,000,000
Enbridge Inc.
Line of Credit Facility [Line Items]
Credit facility capacity					8,876,000,000
Unutilized credit facility					5,699,000,000
Commercial paper and credit facility draws
Line of Credit Facility [Line Items]
Long-term debt					3,800,000,000					10,500,000,000
Committed credit facilities
Line of Credit Facility [Line Items]
Credit facility capacity					$ 21,749,000,000
Term out option period					1 year	1 year
Unutilized credit facility					$ 17,053,000,000
Committed credit facilities \| 364-Day Extendible Credit Facility \| Enbridge Gas Inc.
Line of Credit Facility [Line Items]
Term of credit facility				364 days
Credit facility capacity				$ 2,500,000,000					$ 2,000,000,000
Term out option period				1 year
Committed credit facilities \| 364-Day Extendible Credit Facility \| Enbridge Pipelines Inc.
Line of Credit Facility [Line Items]
Term of credit facility			364 days
Term out option period			1 year
Committed credit facilities \| Senior Unsecured Bridge Term Loan
Line of Credit Facility [Line Items]
Credit facility capacity								$ 9,400,000,000
Unutilized credit facility							$ 0
Revolving Credit Facility \| 364-Day Extendible Credit Facility
Line of Credit Facility [Line Items]
Term of credit facility			364 days
Credit facility capacity			$ 6,800,000,000
Term out option period			1 year
Revolving Credit Facility \| Sustainability-linked Credit Facility
Line of Credit Facility [Line Items]
Term of credit facility			5 years
Revolving Credit Facility \| Term Loan Maturing In July 2026
Line of Credit Facility [Line Items]
Term of credit facility			3 years
Term Loan Maturing In May 2025 \| Five-Year Credit Facilities
Line of Credit Facility [Line Items]
Credit facility capacity			$ 7,600,000,000
Uncommitted Credit Facilities
Line of Credit Facility [Line Items]
Credit facility capacity					1,100,000,000					1,300,000,000
Unutilized credit facility					$ 572,000,000					$ 689,000,000
Weighted average standby fee (as a percent)					0.10%	0.10%

DEBT - Long-term Debt Issuances

DEBT - Long-term Debt Issuances Narrative (Details) € in Millions, $ in Millions	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 EUR (€)	Nov. 03, 2023
Debt Instrument [Line Items]
Current portion of long-term debt	$ 61	€ 42
Long-term debt	$ 460	€ 316
Enbridge Renewable Infrastructure Investments S a r l (ERII)
Debt Instrument [Line Items]
Ownership interest acquired additionally (as a percent)			49%
Hohe See Offshore And Albatros Offshore Wind Farm
Debt Instrument [Line Items]
Ownership interest acquired additionally (as a percent)			24.45%

DEBT - Schedule of Long-term De

DEBT - Schedule of Long-term Debt Issuances (Details)	12 Months Ended
DEBT - Schedule of Long-term Debt Issuances (Details)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 CAD ($)
Debt Instrument [Line Items]
Principal amount	$ 8,500,000,000	$ 3,900,000,000
Enbridge Gas Inc. \| 5.46% Medium Term Notes Due October 2028
Debt Instrument [Line Items]
Interest rate (as a percent)	5.46%	5.46%
Principal amount		$ 250,000,000
Enbridge Gas Inc. \| 5.70% Medium Term Notes Due October 2033
Debt Instrument [Line Items]
Interest rate (as a percent)	5.70%	5.70%
Principal amount		$ 400,000,000
Enbridge Gas Inc. \| 5.67% Medium Term Notes Due October 2053
Debt Instrument [Line Items]
Interest rate (as a percent)	5.67%	5.67%
Principal amount		$ 350,000,000
Enbridge Pipelines Inc. \| Medium Term Notes Due August 2053
Debt Instrument [Line Items]
Interest rate (as a percent)	5.82%	5.82%
Principal amount		$ 350,000,000
Enbridge Inc. \| 5.70% Sustainability-Linked Senior Notes Due March 2033
Debt Instrument [Line Items]
Interest rate (as a percent)	5.70%	5.70%
Principal amount	$ 2,300,000,000
Enbridge Inc. \| 5.97% Senior Notes Due March 2026
Debt Instrument [Line Items]
Interest rate (as a percent)	5.97%	5.97%
Principal amount	$ 700,000,000
Term of credit facility	1 year
Enbridge Inc. \| 4.90% Medium Term Notes Due May 2028
Debt Instrument [Line Items]
Interest rate (as a percent)	4.90%	4.90%
Principal amount		$ 600,000,000
Enbridge Inc. \| 5.36% Sustainability-Linked Senior Notes Due May 2033
Debt Instrument [Line Items]
Interest rate (as a percent)	5.36%	5.36%
Principal amount		$ 400,000,000
Enbridge Inc. \| 5.76% Medium Term Notes Due May 2053
Debt Instrument [Line Items]
Interest rate (as a percent)	5.76%	5.76%
Principal amount		$ 500,000,000
Enbridge Inc. \| 8.50% Fixed-to-fixed Subordinated Notes Due January 2084
Debt Instrument [Line Items]
Interest rate (as a percent)	8.50%	8.50%
Principal amount	$ 1,250,000,000
Enbridge Inc. \| 8.25% Fixed-to-fixed Subordinated Notes Due January 2084
Debt Instrument [Line Items]
Interest rate (as a percent)	8.25%	8.25%
Principal amount	$ 750,000,000
Enbridge Inc. \| 8.75% Fixed-to-fixed Subordinated Notes Due January 2084
Debt Instrument [Line Items]
Interest rate (as a percent)	8.75%	8.75%
Principal amount		$ 700,000,000
Enbridge Inc. \| 8.50% Fixed-to-fixed Subordinated Notes Due January 2084-1
Debt Instrument [Line Items]
Interest rate (as a percent)	8.50%	8.50%
Principal amount		$ 300,000,000
Enbridge Inc. \| 5.90% Senior Notes Due November 2026
Debt Instrument [Line Items]
Interest rate (as a percent)	5.90%	5.90%
Principal amount	$ 750,000,000
Enbridge Inc. \| 6.00% Senior Notes Due November 2028
Debt Instrument [Line Items]
Interest rate (as a percent)	6%	6%
Principal amount	$ 750,000,000
Enbridge Inc. \| 6.30% Senior Notes Due November 2030
Debt Instrument [Line Items]
Interest rate (as a percent)	6.20%	6.20%
Principal amount	$ 750,000,000
Enbridge Inc. \| 6.70% Senior Notes Due November 2053
Debt Instrument [Line Items]
Interest rate (as a percent)	6.70%	6.70%
Principal amount	$ 1,250,000,000
Enbridge Inc. \| Initial Period \| Fixed-to-fixed subordinated term notes
Debt Instrument [Line Items]
Term of fixed rate	5 years
Enbridge Inc. \| Initial Period \| 5.70% Sustainability-Linked Senior Notes Due March 2033
Debt Instrument [Line Items]
Sustainability performance target (percent)	35%	35%
Enbridge Inc. \| Initial Period \| 5.36% Sustainability-Linked Senior Notes Due May 2033
Debt Instrument [Line Items]
Sustainability performance target (percent)	35%	35%
Enbridge Inc. \| Initial Period \| 8.50% Fixed-to-fixed Subordinated Notes Due January 2084 \| Fixed-to-fixed subordinated term notes \| US Treasury Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	4.43%
Enbridge Inc. \| Initial Period \| 8.25% Fixed-to-fixed Subordinated Notes Due January 2084 \| Fixed-to-fixed subordinated term notes \| US Treasury Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	3.79%
Enbridge Inc. \| Initial Period \| 8.75% Fixed-to-fixed Subordinated Notes Due January 2084 \| Fixed-to-fixed subordinated term notes \| Government Of Canada Bond Yield
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	4.96%
Enbridge Inc. \| Initial Period \| 8.50% Fixed-to-fixed Subordinated Notes Due January 2084-1 \| Fixed-to-fixed subordinated term notes \| Government Of Canada Bond Yield
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	4.30%
Enbridge Inc. \| Subsequent period \| Fixed-to-fixed subordinated term notes
Debt Instrument [Line Items]
Term of fixed rate	10 years
Enbridge Inc. \| Subsequent period \| 5.70% Sustainability-Linked Senior Notes Due March 2033
Debt Instrument [Line Items]
Interest rate (as a percent)	5.70%	5.70%
Basis spread on variable rate (as a percent)	0.50%
Enbridge Inc. \| Subsequent period \| 5.36% Sustainability-Linked Senior Notes Due May 2033
Debt Instrument [Line Items]
Interest rate (as a percent)	5.36%	5.36%
Basis spread on variable rate (as a percent)	0.50%
Enbridge Inc. \| Subsequent period \| 8.50% Fixed-to-fixed Subordinated Notes Due January 2084 \| Fixed-to-fixed subordinated term notes \| US Treasury Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	5.18%
Enbridge Inc. \| Subsequent period \| 8.25% Fixed-to-fixed Subordinated Notes Due January 2084 \| Fixed-to-fixed subordinated term notes \| US Treasury Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	4.04%
Enbridge Inc. \| Subsequent period \| 8.75% Fixed-to-fixed Subordinated Notes Due January 2084 \| Fixed-to-fixed subordinated term notes \| Government Of Canada Bond Yield
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	5.71%
Enbridge Inc. \| Subsequent period \| 8.50% Fixed-to-fixed Subordinated Notes Due January 2084-1 \| Fixed-to-fixed subordinated term notes \| Government Of Canada Bond Yield
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	4.55%
Enbridge Inc. \| Debt Instrument Interest Rate Terms Period Three \| 8.25% Fixed-to-fixed Subordinated Notes Due January 2084 \| Fixed-to-fixed subordinated term notes \| US Treasury Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	4.79%
Enbridge Inc. \| Debt Instrument Interest Rate Terms Period Three \| 8.50% Fixed-to-fixed Subordinated Notes Due January 2084-1 \| Fixed-to-fixed subordinated term notes \| Government Of Canada Bond Yield
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	5.30%

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, 2023 USD ($)

Nov. 30, 2023 CAD ($)

Oct. 31, 2023 USD ($)

Aug. 31, 2023 CAD ($)

Jul. 31, 2023 CAD ($)

Jun. 30, 2023 CAD ($)

Jun. 30, 2023 USD ($)

Apr. 30, 2023 USD ($)

Feb. 28, 2023 USD ($)

Jan. 31, 2023 CAD ($)

Jan. 31, 2023 USD ($)

Dec. 31, 2023 CAD ($)

Dec. 31, 2023 USD ($)

Debt Instrument [Line Items]

Extinguishment of debt

$ 1,400

$ 2,500

Enbridge Gas Inc. | 6.05 Medium Term Notes

Debt Instrument [Line Items]

Interest rate (as a percent)

6.05%

Extinguishment of debt

$ 100

Enbridge Gas Inc. | 3.79 Medium Term Notes

Debt Instrument [Line Items]

Interest rate (as a percent)

3.79%

Extinguishment of debt

$ 250

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

Debt Instrument [Line Items]

Interest rate (as a percent)

3.98%

Extinguishment of debt

$ 80

Enbridge Pipelines Inc. | 3.79 Medium Term Notes

Debt Instrument [Line Items]

Interest rate (as a percent)

3.79%

Extinguishment of debt

$ 250

Enbridge Pipelines Inc. | 6.35 Medium Term Notes

Debt Instrument [Line Items]

Interest rate (as a percent)

6.35%

Extinguishment of debt

$ 100

Enbridge Southern Lights LP | 4.01% Senior Notes Due 2040

Debt Instrument [Line Items]

Interest rate (as a percent)

4.01%

Extinguishment of debt

$ 9

Tri Global Energy, LLC | 10.00% Senior Notes

Debt Instrument [Line Items]

Interest rate (as a percent)

10%

Extinguishment of debt

$ 4

Tri Global Energy, LLC | 14.00% Senior Notes

Debt Instrument [Line Items]

Interest rate (as a percent)

14%

Extinguishment of debt

$ 9

Enbridge Inc. | 3.94% Medium-Term Notes

Debt Instrument [Line Items]

Interest rate (as a percent)

3.94%

394%

Extinguishment of debt

$ 450

$ 275

Enbridge Inc. | Floating Rate Notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 500

Enbridge Inc. | Floating Rate Notes | LIBOR

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

0.40%

Enbridge Inc. | 6.38% Fixed-To-Floating Rate Subordinated Notes

Debt Instrument [Line Items]

Interest rate (as a percent)

6.38%

Extinguishment of debt

$ 600

Enbridge Inc. | 4.00% Senior Notes

Debt Instrument [Line Items]

Interest rate (as a percent)

Extinguishment of debt

$ 800

Enbridge Inc. | 0.55% Senior Notes

Debt Instrument [Line Items]

Interest rate (as a percent)

0.55%

Extinguishment of debt

$ 500

Enbridge Inc. | Callable Notes Maturing 2078

Debt Instrument [Line Items]

Term of credit facility

5 years

DEBT - Schedule of Maturities (

DEBT - Schedule of Maturities (Details) $ in Millions	Dec. 31, 2023 CAD ($)
Debt Disclosure [Abstract]
Total	$ 80,438
Less than 1 year	6,067
2 years	6,405
3 years	5,630
4 years	3,377
5 years	5,307
Thereafter	$ 53,652

DEBT - Schedule of Interest Exp

DEBT - Schedule of Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
DEBT
Capitalized interest	$ (101)	$ (74)	$ (215)
Total interest expense	3,812	3,179	2,655
Spectra Energy Capital, LLC
DEBT
Amortization of fair value adjustment	(45)	(45)	(50)
Debentures and term notes
DEBT
Interest expense on debt	3,439	2,910	2,806
Commercial paper and credit facility draws
DEBT
Interest expense on debt	$ 519	$ 388	$ 114

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of movements in the Company's ARO
Obligations at beginning of year	$ 488	$ 502
Liabilities acquired	1	0
Liabilities incurred	0	30
Liabilities settled	(23)	(126)
Change in estimate and other	5	51
Foreign currency translation adjustment	(6)	24
Accretion expense	28	7
Obligations at end of year	493	488
Other current liabilities	136	83
Other long-term liabilities	357	405
Asset retirement obligations	$ 493	$ 488
Minimum
Asset Retirement Obligations [Line Items]
Discount rate (as a percent)	1.50%
Maximum
Asset Retirement Obligations [Line Items]
Discount rate (as a percent)	9%

NONCONTROLLING INTERESTS (Detai

NONCONTROLLING INTERESTS (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Oct. 05, 2022
NONCONTROLLING INTERESTS
Noncontrolling interests	$ 3,029	$ 3,511
Athabasca Regional Oil Sands System \| Athabasca Regional Oil Sands System
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners			11.60%
Algonquin Gas Transmission, LLC
NONCONTROLLING INTERESTS
Noncontrolling interests	384	400
Enbridge Athabasca Midstream Investor Limited Partnership
NONCONTROLLING INTERESTS
Noncontrolling interests	1,086	1,106
Maritimes & Northeast Pipeline, L.L.C.
NONCONTROLLING INTERESTS
Noncontrolling interests	559	582
Renewable energy assets
NONCONTROLLING INTERESTS
Noncontrolling interests	885	1,302
Maritimes & Northeast Pipeline Limited Partnership
NONCONTROLLING INTERESTS
Noncontrolling interests	111	117
Other
NONCONTROLLING INTERESTS
Noncontrolling interests	$ 4	$ 4

SHARE CAPITAL - Common Shares (

SHARE CAPITAL - Common Shares (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance at beginning of period (in shares)	2,025
Shares issued, net of issue costs (in shares)	103
Shares issued, net of issue costs	$ 4,485
Shares issued on vesting of RSU, net of tax (in shares)	0
Shares issued on vesting of RSUs, net of tax	$ 12
Balance at end of period (in shares)	2,125	2,025
Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance at beginning of period (in shares)	2,025	2,026	2,026
Balance at beginning of period, amount	$ 64,760	$ 64,799	$ 64,768
Shares issued on exercise of stock options (in shares)	0	2	0
Shares issued on exercise of stock options	$ 3	$ 53	$ 31
Share purchases at stated value (in shares)	(3)	(3)	0
Share purchases at stated value	$ (80)	$ (88)	$ 0
Other ( in shares)	0	0	0
Other	$ 0	$ (4)	$ 0
Balance at end of period (in shares)	2,125	2,025	2,026
Balance at end of period, amount	$ 69,180	$ 64,760	$ 64,799

SHARE CAPITAL - Preferred Share

SHARE CAPITAL - Preferred Shares (Details) $ / shares in Units, $ in Millions											1 Months Ended	12 Months Ended
	Dec. 01, 2023 $ / shares	Nov. 30, 2023 $ / shares	Sep. 01, 2023 $ / shares shares	Aug. 31, 2023 $ / shares	Jun. 01, 2023 $ / shares shares	Jun. 01, 2023 $ / shares shares	May 31, 2023 $ / shares	May 31, 2023 $ / shares	Mar. 01, 2023 $ / shares	Feb. 28, 2023 $ / shares	Jun. 30, 2023 shares	Dec. 31, 2023 CAD ($) $ / shares shares	Dec. 31, 2023 CAD ($) $ / shares $ / shares shares	Dec. 31, 2022 CAD ($) shares	Dec. 31, 2021 CAD ($) shares	Dec. 31, 2023 $ / shares	Jun. 01, 2022 CAD ($)	Mar. 01, 2022 CAD ($)
Preferred Shares
Share Capital
Preferred stock, value, outstanding \| $												$ 6,818	$ 6,818	$ 6,818	$ 7,747
Issuance costs \| $												$ (135)		$ (135)	$ (155)
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference shares conversion ratio												1	1
Preference Shares, Series A \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												5,000,000	5,000,000	5,000,000	5,000,000
Preferred stock, value, outstanding \| $												$ 125	$ 125	$ 125	$ 125
Dividend rate (percent)												5.50%
Dividend (in Canadian dollars per share)												$ 1.37500
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Dividend rate reset period												5 years
Preference Shares, Series B \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												20,000,000	20,000,000	20,000,000	18,000,000
Preferred stock, value, outstanding \| $												$ 500	$ 500	$ 500	$ 457
Dividend rate (percent)												5.20%
Dividend (in Canadian dollars per share)												$ 1.30052
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series C \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												0	0	0	2,000,000
Preferred stock, value, outstanding \| $												$ 0	$ 0	$ 0	$ 43
Preference Shares, Series C \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.40%	2.40%
Preference Shares, Series D \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												18,000,000	18,000,000	18,000,000	18,000,000
Preferred stock, value, outstanding \| $												$ 450	$ 450	$ 450	$ 450
Dividend rate (percent)												5.41%
Dividend (in Canadian dollars per share)									$ 0.33825	$ 0.27875		$ 1.35300
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series F \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												18,000,000	18,000,000	20,000,000	20,000,000
Preferred stock, value, outstanding \| $												$ 454	$ 454	$ 500	$ 500
Dividend rate (percent)												5.54%
Dividend (in Canadian dollars per share)					$ 0.34613		$ 0.29306					$ 1.38452
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Conversion of stock, shares converted \| shares					1,827,695	1,827,695
Preference Shares, Series G \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												2,000,000	2,000,000	0	0
Preferred stock, value, outstanding \| $												$ 46	$ 46	$ 0	$ 0
Dividend rate (percent)												6.96%
Dividend (in Canadian dollars per share)	$ 0.47676	$ 0.47245										$ 1.90704
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Conversion of stock, shares converted \| shares											1,827,695
Preference Shares, Series G \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.50%	2.50%
Preference Shares, Series H \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												12,000,000	12,000,000	14,000,000	14,000,000
Preferred stock, value, outstanding \| $												$ 291	$ 291	$ 350	$ 350
Dividend rate (percent)												6.11%
Dividend (in Canadian dollars per share)			$ 0.38200	$ 0.27350								$ 1.52800
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Conversion of stock, shares converted \| shares			2,350,602
Preference Shares, Series I \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												2,000,000	2,000,000	0	0
Preferred stock, value, outstanding \| $												$ 59	$ 59	$ 0	$ 0
Dividend rate (percent)												7.19%
Dividend (in Canadian dollars per share)	0.45251	0.44814										$ 1.81004
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series I \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.10%	2.10%
Preference Shares, Series J
Share Capital
Preferred stock, redemption amount \| $																	$ 200
Preference Shares, Series J \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												0	0	0	8,000,000
Preferred stock, value, outstanding \| $												$ 0	$ 0	$ 0	$ 199
Preference Shares, Series L \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												16,000,000	16,000,000	16,000,000	16,000,000
Preferred stock, value, outstanding \| $												$ 411	$ 411	$ 411	$ 411
Dividend rate (percent)												5.86%
Dividend (in Canadian dollars per share)													$ 1.46448
Per share base redemption value (in Canadian dollars per shares)																$ 25
Preference Shares, Series N \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												18,000,000	18,000,000	18,000,000	18,000,000
Preferred stock, value, outstanding \| $												$ 450	$ 450	$ 450	$ 450
Dividend rate (percent)												6.70%
Dividend (in Canadian dollars per share)	$ 0.41850	$ 0.31788										$ 1.67400
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series P \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												16,000,000	16,000,000	16,000,000	16,000,000
Preferred stock, value, outstanding \| $												$ 400	$ 400	$ 400	$ 400
Dividend rate (percent)												4.38%
Dividend (in Canadian dollars per share)												$ 1.09476
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series R \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												16,000,000	16,000,000	16,000,000	16,000,000
Preferred stock, value, outstanding \| $												$ 400	$ 400	$ 400	$ 400
Dividend rate (percent)												4.07%
Dividend (in Canadian dollars per share)												$ 1.01825
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series 1 \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												16,000,000	16,000,000	16,000,000	16,000,000
Preferred stock, value, outstanding \| $												$ 411	$ 411	$ 411	$ 411
Dividend rate (percent)												6.70%
Dividend (in Canadian dollars per share)						$ 0.41898		$ 0.37182					$ 1.67592
Per share base redemption value (in Canadian dollars per shares)																25
Preference Shares, Series 3 \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												24,000,000	24,000,000	24,000,000	24,000,000
Preferred stock, value, outstanding \| $												$ 600	$ 600	$ 600	$ 600
Dividend rate (percent)												3.74%
Dividend (in Canadian dollars per share)												$ 0.93425
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series 5 \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												8,000,000	8,000,000	8,000,000	8,000,000
Preferred stock, value, outstanding \| $												$ 206	$ 206	$ 206	$ 206
Dividend rate (percent)												5.38%
Dividend (in Canadian dollars per share)													$ 1.34383
Per share base redemption value (in Canadian dollars per shares)																$ 25
Preference Shares, Series 7 \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												10,000,000	10,000,000	10,000,000	10,000,000
Preferred stock, value, outstanding \| $												$ 250	$ 250	$ 250	$ 250
Dividend rate (percent)												4.45%
Dividend (in Canadian dollars per share)												$ 1.11224
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series 9 \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												11,000,000	11,000,000	11,000,000	11,000,000
Preferred stock, value, outstanding \| $												$ 275	$ 275	$ 275	$ 275
Dividend rate (percent)												4.10%
Dividend (in Canadian dollars per share)												$ 1.02424
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series 11 \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												20,000,000	20,000,000	20,000,000	20,000,000
Preferred stock, value, outstanding \| $												$ 500	$ 500	$ 500	$ 500
Dividend rate (percent)												3.94%
Dividend (in Canadian dollars per share)												$ 0.98452
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series 13 \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												14,000,000	14,000,000	14,000,000	14,000,000
Preferred stock, value, outstanding \| $												$ 350	$ 350	$ 350	$ 350
Dividend rate (percent)												3.04%
Dividend (in Canadian dollars per share)												$ 0.76076
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series 15 \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												11,000,000	11,000,000	11,000,000	11,000,000
Preferred stock, value, outstanding \| $												$ 275	$ 275	$ 275	$ 275
Dividend rate (percent)												2.98%
Dividend (in Canadian dollars per share)												$ 0.74576
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Preference Shares, Series 17
Share Capital
Preferred stock, redemption amount \| $																		$ 750
Preference Shares, Series 17 \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												0	0	0	30,000,000
Preferred stock, value, outstanding \| $												$ 0	$ 0	$ 0	$ 750
Preference Shares, Series 19 \| Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) \| shares												20,000,000	20,000,000	20,000,000	20,000,000
Preferred stock, value, outstanding \| $												$ 500	$ 500	$ 500	$ 500
Dividend rate (percent)												6.21%
Dividend (in Canadian dollars per share)									$ 0.38825	$ 0.30625		$ 1.55300
Per share base redemption value (in Canadian dollars per shares)												$ 25	$ 25
Dividend rate reset period												5 years
Preference Shares, Series 19 \| Minimum \| Preferred Shares
Share Capital
Dividend rate (percent)												4.90%
Preference Shares, Series E \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.40%	2.40%
Preference Shares, Series O \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.70%	2.70%
Preference Shares, Series Q \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.50%	2.50%
Preference Shares, Series S \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.50%	2.50%
Preference Shares, Series 4 \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.40%	2.40%
Preference Shares, Series 8 \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.60%	2.60%
Preference Shares, Series 10 \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.70%	2.70%
Preference Shares, Series 12 \| Preferred Shares \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.60%	2.60%
Preference Shares, Series M \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												3.20%	3.20%
Preference Shares, Series 2 \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												3.10%	3.10%
Preference Shares, Series 6 \| 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)												2.80%	2.80%

SHARE CAPITAL - Shareholder Rig

SHARE CAPITAL - Shareholder Rights Plan (Details)	Dec. 31, 2023
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 - Narrative (Details) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($) compensationPlan shares	Dec. 31, 2022 CAD ($) shares	Dec. 31, 2021 CAD ($) shares
STOCK-BASED COMPENSATION
Number of long-term incentive compensation plans \| compensationPlan	3
Compensation expense	$ 154	$ 260	$ 157
Common stock, shares authorized \| shares	181	181	181
Incentive Stock Options
STOCK-BASED COMPENSATION
Compensation expense	$ 18	$ 15	$ 16
Vesting period	4 years
Expiration term	10 years
Unrecognized compensation cost related to non-vested share-based compensation arrangements granted	$ 11
Weighted average period over which compensation cost is expected to be recognized	2 years
Performance Stock Units (PSUs)
STOCK-BASED COMPENSATION
Compensation expense	$ 59	$ 169	$ 56
Vesting period	3 years
Weighted average period over which compensation cost is expected to be recognized	2 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	1.25	1.25
Unrecognized compensation expense related to non-vested units granted	$ 54
Performance Stock Units (PSUs) \| Minimum
STOCK-BASED COMPENSATION
Performance multiplier	0
Performance Stock Units (PSUs) \| Maximum
STOCK-BASED COMPENSATION
Performance multiplier	2
Restricted Stock Units (RSU)
STOCK-BASED COMPENSATION
Compensation expense	$ 77	$ 76	$ 85
Vesting period	3 years
Weighted average period over which compensation cost is expected to be recognized	2 years
Period prior to the maturity of the grant for which weighted average share price is used to calculate cash awards	20 days
Unrecognized compensation expense related to non-vested units granted	$ 60

STOCK OPTION AND STOCK UNIT P_4

STOCK OPTION AND STOCK UNIT PLANS - Stock Option Activity (Details) - Incentive Stock Options - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Number
Options outstanding at beginning of year (in shares)	27,624
Options granted (in shares)	3,053
Options exercised (in shares)	(648)
Options cancelled or expired (in shares)	(1,300)
Options outstanding at end of year (in shares)	28,729	27,624
Options vested at end of year (in shares)	20,235
Weighted Average Exercise Price
Options outstanding at beginning of year (in Canadian dollars per share)	$ 48.46
Options granted (in Canadian dollars per share)	53.11
Options exercised (in Canadian dollars per share)	45.70
Options cancelled or expired (in Canadian dollars per share)	53.84
Options outstanding at end of year (in Canadian dollars per share)	50.79	$ 48.46
Options vested at end of year (in Canadian dollars per share)	$ 50.64
Weighted Average Remaining Contractual Life (years)
Options outstanding at end of year	5 years 3 months 18 days
Options vested at end of year	4 years 1 month 6 days
Aggregate Intrinsic Value
Options outstanding at end of year	$ 45
Options vested at end of year	36
Stock options, additional disclosures
Total intrinsic value of awards exercised	2	$ 66	$ 24
Cash received on exercise of awards		3	2
Total fair value of options vested	$ 20	$ 21	$ 25

STOCK OPTION AND STOCK UNIT P_5

STOCK OPTION AND STOCK UNIT PLANS - Weighted Average Assumptions (Details) - Incentive Stock Options	12 Months Ended
	Dec. 31, 2023 $ / shares	Dec. 31, 2022 $ / shares	Dec. 31, 2021 $ / shares	Dec. 31, 2023 $ / shares	Dec. 31, 2022 $ / shares	Dec. 31, 2021 $ / shares
Weighted average assumptions used to determine the fair value of options
Fair value per option (in Canadian dollars per share)	$ 6.05	$ 5.07	$ 4.10
Expected option term (in years)	6 years	6 years	6 years
Expected volatility (as a percent)	22.20%	21.90%	25.50%
Expected dividend yield (as a percent)	6.70%	6.50%	7.60%
Risk-free interest rate (as a percent)	3.50%	1.80%	0.70%
Expected option term - historical exercise practice	6 years
Canadian Employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in Canadian dollars per share)	$ 5.38	$ 4.78	$ 3.91
United States Employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in Canadian dollars per share)				$ 5.23	$ 4.62	$ 3.65
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_6

STOCK OPTION AND STOCK UNIT PLANS - PSUs and RSUs (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Performance Stock Units (PSUs)
Number
Units outstanding at beginning of year (in shares)	3,249
Units granted (in shares)	2,128
Units cancelled (in shares)	(214)
Units matured (in shares)	(2,218)
Dividend reinvestment (in shares)	235
Units outstanding at end of year (in shares)	3,180	3,249
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	$ 175
Stock units, additional disclosures
Total amount paid	$ 123	$ 90	$ 70
Restricted Stock Units (RSU)
Number
Units outstanding at beginning of year (in shares)	3,565
Units granted (in shares)	1,373
Units cancelled (in shares)	(246)
Units matured (in shares)	(1,401)
Dividend reinvestment (in shares)	280
Units outstanding at end of year (in shares)	3,571	3,565
Weighted Average Grant Date Fair Value
Units outstanding at beginning of year	$ 49.64
Units granted	52.05
Units cancelled	52.06
Units matured	51.05
Dividend reinvestment	50.88
Units outstanding at end of year	$ 50.69	$ 49.64
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	10 months 24 days
Aggregate Intrinsic Value
Units outstanding at end of year	$ 177
Stock units, additional disclosures
Total amount paid	$ 56	$ 32	$ 72

COMPONENTS OF ACCUMULATED OTH_3

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Changes in AOCI
Balance at beginning of year	$ 63,398	$ 63,368
Other comprehensive income/(loss) retained in AOCI	(1,144)	4,816	$ 298
Other		16	0
Other comprehensive (income)/loss reclassified to earnings	(1,187)	5,004	564
Income tax on amounts retained in AOCI	(33)	(349)	(187)
Income tax on amounts reclassified to earnings	3	(39)	(72)
Tax impact	(30)	(388)	(259)
Balance at end of year	64,483	63,398	63,368
Interest rate contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	28	186	296
Commodity contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs			1
Foreign exchange contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	(47)	(4)	5
Other contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs		4	2
Equity investment disposal
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs			(66)
Total
Changes in AOCI
Balance at beginning of year	3,520	(1,096)	(1,401)
Balance at end of year	2,303	3,520	(1,096)
Cash Flow Hedges
Changes in AOCI
Balance at beginning of year	121	(897)	(1,326)
Other comprehensive income/(loss) retained in AOCI	232	1,125	238
Other		0	17
Other comprehensive (income)/loss reclassified to earnings	260	1,311	559
Income tax on amounts retained in AOCI	(47)	(250)	(61)
Income tax on amounts reclassified to earnings	(14)	(43)	(69)
Tax impact	(61)	(293)	(130)
Balance at end of year	320	121	(897)
Cash Flow Hedges \| Interest rate contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	28	186	296
Cash Flow Hedges \| Commodity contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs			1
Cash Flow Hedges \| Foreign exchange contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	0	(4)	5
Cash Flow Hedges \| Other contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs		4	2
Excluded Components of Fair Value Hedges
Changes in AOCI
Balance at beginning of year	(35)	0	5
Other comprehensive income/(loss) retained in AOCI	62	(35)	(5)
Other comprehensive (income)/loss reclassified to earnings	15	(35)	(5)
Income tax on amounts retained in AOCI	(14)
Income tax on amounts reclassified to earnings	11
Tax impact	(3)	0	0
Balance at end of year	(23)	(35)	0
Excluded Components of Fair Value Hedges \| Foreign exchange contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	(47)
Net Investment Hedges
Changes in AOCI
Balance at beginning of year	(1,137)	(166)	(215)
Other comprehensive income/(loss) retained in AOCI	409	(971)	49
Other comprehensive (income)/loss reclassified to earnings	409	(971)	49
Income tax on amounts retained in AOCI	0
Income tax on amounts reclassified to earnings	0
Tax impact	0	0	0
Balance at end of year	(728)	(1,137)	(166)
Cumulative Translation Adjustment
Changes in AOCI
Balance at beginning of year	4,348	56	568
Other comprehensive income/(loss) retained in AOCI	(1,695)	4,292	(492)
Other		0	(20)
Other comprehensive (income)/loss reclassified to earnings	(1,695)	4,292	(512)
Income tax on amounts retained in AOCI	0
Income tax on amounts reclassified to earnings	0
Tax impact	0	0
Balance at end of year	2,653	4,348	56
Equity Investees
Changes in AOCI
Balance at beginning of year	5	(5)	66
Other comprehensive income/(loss) retained in AOCI	6	(6)	(12)
Other		16	3
Other comprehensive (income)/loss reclassified to earnings	6	10	(75)
Income tax on amounts retained in AOCI	0
Income tax on amounts reclassified to earnings	0		4
Tax impact	0	0	4
Balance at end of year	11	5	(5)
Equity Investees \| Equity investment disposal
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs			(66)
Pension and OPEB Adjustment
Changes in AOCI
Balance at beginning of year	218	(84)	(499)
Other comprehensive income/(loss) retained in AOCI	(158)	411	520
Amortization of pension and OPEB actuarial loss and prior service costs	(24)	(14)	28
Other comprehensive (income)/loss reclassified to earnings	(182)	397	548
Income tax on amounts retained in AOCI	28	(99)	(126)
Income tax on amounts reclassified to earnings	6	4	(7)
Tax impact	34	(95)	(133)
Balance at end of year	$ 70	$ 218	$ (84)

RISK MANAGEMENT AND FINANCIAL_3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Market Risk (Details)		3 Months Ended	12 Months Ended
	Mar. 08, 2023 USD ($)	Mar. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($) stock-based_compensation_form	Dec. 31, 2023 CAD ($)
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Principal amount			$ 8,500,000,000	$ 3,900,000,000
Three-Year Fixed Rate Notes \| Notes Payable, Other Payables
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Principal amount	$ 700,000,000
Term of credit facility	3 years
Foreign exchange contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Derivative instruments not designated as hedging instruments, loss		$ 638,000,000
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Policy limit increase (as a percent)			30%	30%
Derivative, average fixed interest rate			4.10%	4.10%
Derivative, fixed interest rate	6%
Floating-To-Fixed Interest Rate Swaps
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Derivative, average fixed interest rate			3.50%	3.50%
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Number of types of equity \| stock-based_compensation_form			1

RISK MANAGEMENT AND FINANCIAL_4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Total Derivative Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	$ (404)	$ (546)
Total net derivative instruments	(404)	(546)
Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(278)	(1,476)
Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(122)	816
Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(4)	114
Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	623	1,015
Derivative assets, amounts available for offset	(335)	(223)
Derivative assets, total net derivative instruments	$ 288	$ 792
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Other current assets	Other current assets
Other current assets \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	$ 551	$ 366
Other current assets \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	31	649
Other current assets \| Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	41	0
Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	463	627
Derivative assets, amounts available for offset	(184)	(163)
Derivative assets, total net derivative instruments	$ 279	$ 464
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	$ 396	$ 216
Deferred amounts and other assets \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	51	255
Deferred amounts and other assets \| Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	16	156
Other current liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(738)	(898)
Derivative liabilities, amounts available for offset	335	223
Derivative liabilities, total net derivative instruments	$ (403)	$ (675)
Derivative liability, statement of financial position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Other current liabilities \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	$ (500)	$ (808)
Other current liabilities \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(194)	(48)
Other current liabilities \| Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(44)	(42)
Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(752)	(1,290)
Derivative liabilities, amounts available for offset	184	163
Derivative liabilities, total net derivative instruments	$ (568)	$ (1,127)
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	$ (725)	$ (1,250)
Other long-term liabilities \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(10)	(40)
Other long-term liabilities \| Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(17)	0
Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(152)	(1,327)
Total net derivative instruments	(152)	(1,327)
Foreign exchange contracts \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(148)	(1,441)
Foreign exchange contracts \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	$ 0	0
Derivative liability, statement of financial position [Extensible Enumeration]	Other long-term liabilities
Foreign exchange contracts \| Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	$ (4)	114
Foreign exchange contracts \| Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	139	46
Derivative assets, amounts available for offset	(32)	(41)
Derivative assets, total net derivative instruments	107	5
Foreign exchange contracts \| Other current assets \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	98	46
Foreign exchange contracts \| Other current assets \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Foreign exchange contracts \| Other current assets \| Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	41	0
Foreign exchange contracts \| Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	335	309
Derivative assets, amounts available for offset	(122)	(138)
Derivative assets, total net derivative instruments	213	171
Foreign exchange contracts \| Deferred amounts and other assets \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	319	153
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	16	156
Foreign exchange contracts \| Other current liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(128)	(566)
Derivative liabilities, amounts available for offset	32	41
Derivative liabilities, total net derivative instruments	(96)	(525)
Foreign exchange contracts \| Other current liabilities \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(84)	(524)
Foreign exchange contracts \| Other current 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 current liabilities \| Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(44)	(42)
Foreign exchange contracts \| Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(498)	(1,116)
Derivative liabilities, amounts available for offset	122	138
Derivative liabilities, total net derivative instruments	(376)	(978)
Foreign exchange contracts \| Other long-term liabilities \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(481)	(1,116)
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	(17)	0
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented		(4)
Total net financial asset/(liability)	(156)	910
Derivative liabilities, amounts available for offset		0
Derivative liabilities, total net derivative instruments		(4)
Total net derivative instruments	$ (156)	910
Derivative liability, statement of financial position [Extensible Enumeration]	Other long-term liabilities
Interest rate contracts \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented		(1)
Total net financial asset/(liability)	$ (52)	10
Derivative liability, statement of financial position [Extensible Enumeration]	Other long-term liabilities
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)	$ (104)	900
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
Derivative liability, statement of financial position [Extensible Enumeration]	Other long-term liabilities
Interest rate contracts \| Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	$ 65	660
Derivative assets, amounts available for offset	(32)	0
Derivative assets, total net derivative instruments	33	660
Interest rate contracts \| Other current assets \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	34	11
Interest rate contracts \| Other current assets \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	31	649
Interest rate contracts \| Other current assets \| 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	53	254
Derivative assets, amounts available for offset	(21)	0
Derivative assets, total net derivative instruments	32	254
Interest rate contracts \| Deferred amounts and other assets \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	2	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	51	254
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 \| Other current liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(186)
Derivative liabilities, amounts available for offset	32
Derivative liabilities, total net derivative instruments	(154)
Interest rate contracts \| Other current liabilities \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(3)
Interest rate contracts \| Other current liabilities \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(183)
Interest rate contracts \| Other current liabilities \| 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	(88)
Derivative liabilities, amounts available for offset	21
Derivative liabilities, total net derivative instruments	(67)
Interest rate contracts \| Other long-term liabilities \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(85)
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	(3)
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)	(96)	(139)
Total net derivative instruments	(96)	(139)
Commodity contracts \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(78)	(54)
Commodity contracts \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	(18)	(85)
Commodity contracts \| Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net financial asset/(liability)	0	0
Commodity contracts \| Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	418	302
Derivative assets, amounts available for offset	(270)	(182)
Derivative assets, total net derivative instruments	148	120
Commodity contracts \| Other current assets \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	418	302
Commodity contracts \| Other current assets \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Commodity contracts \| Other current assets \| 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	75	61
Derivative assets, amounts available for offset	(41)	(25)
Derivative assets, total net derivative instruments	34	36
Commodity contracts \| Deferred amounts and other assets \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	75	61
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 \| Other current liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(423)	(332)
Derivative liabilities, amounts available for offset	270	182
Derivative liabilities, total net derivative instruments	(153)	(150)
Commodity contracts \| Other current liabilities \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(412)	(284)
Commodity contracts \| Other current liabilities \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(11)	(48)
Commodity contracts \| Other current liabilities \| 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	(166)	(170)
Derivative liabilities, amounts available for offset	41	25
Derivative liabilities, total net derivative instruments	(125)	(145)
Commodity contracts \| Other long-term liabilities \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(159)	(133)
Commodity contracts \| Other long-term liabilities \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(7)	(37)
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
Derivative assets, total gross derivative instruments as presented	1
Derivative liabilities, total gross derivative instruments as presented	(1)
Total net financial asset/(liability)	0	10
Derivative assets, amounts available for offset	(1)
Derivative liabilities, amounts available for offset	1
Derivative assets, total net derivative instruments	0
Derivative liabilities, total net derivative instruments	0
Total net derivative instruments	0	10
Other contracts \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	1
Derivative liabilities, total gross derivative instruments as presented	(1)
Total net financial asset/(liability)	0	9
Other contracts \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0
Derivative liabilities, total gross derivative instruments as presented	0
Total net financial asset/(liability)	0	1
Other contracts \| Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0
Derivative liabilities, total gross derivative instruments as presented	0
Total net financial asset/(liability)	$ 0	0
Other contracts \| Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented		7
Derivative assets, amounts available for offset		0
Derivative assets, total net derivative instruments		7
Other contracts \| Other current assets \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented		7
Other contracts \| Other current assets \| Cash flow hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented		0
Other contracts \| Other current assets \| Fair value hedges \| Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented		0
Other contracts \| Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented		3
Derivative assets, amounts available for offset		0
Derivative assets, total net derivative instruments		3
Other contracts \| Deferred amounts and other assets \| Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented		2
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
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

RISK MANAGEMENT AND FINANCIAL_5

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, 2023 USD ($) MWh MMBbls Bcf	Dec. 31, 2023 GBP (£) MWh MMBbls Bcf	Dec. 31, 2023 EUR (€) MWh MMBbls Bcf	Dec. 31, 2023 JPY (¥) MWh MMBbls Bcf	Dec. 31, 2023 CAD ($) MWh MMBbls Bcf	Dec. 31, 2022 USD ($) MWh Bcf MMBbls	Dec. 31, 2022 GBP (£) MWh Bcf MMBbls	Dec. 31, 2022 EUR (€) MWh Bcf MMBbls	Dec. 31, 2022 JPY (¥) MWh Bcf MMBbls	Dec. 31, 2022 CAD ($) MWh Bcf MMBbls
Foreign exchange contracts - United States dollar or GBP or Japanese yen forwards - purchase
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2024	$ 1,360			¥ 0
2025	500			84,800
2026				0
2027	0			0
2028	0			0
Thereafter	0			0
Total notional principal	1,860			¥ 84,800		$ 2,155			¥ 84,800
Foreign exchange contracts - United States dollar or GBP forwards - sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2024	6,582	£ 30	€ 141
2025	5,327	30	126
2026	4,697	28	121
2027	4,091	32	81
2028	3,162	0	67
Thereafter	888	0	195
Total notional principal	$ 24,747	£ 120	€ 731			$ 27,610	£ 149	€ 697
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2024					$ 5,903
2025					1,881
2026					1,122
2027					74
2028					25
Thereafter					13
Total notional principal					9,018					$ 9,356
Interest rate contract for short term debt receive fixed rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2024					918
2025					923
2026					174
2027					0
2028					0
Thereafter					0
Total notional principal					2,015					0
Interest rate contract - long term debt - Pay Fixed Rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2024					4,582
2025					580
2026					0
2027					0
2028					0
Thereafter					0
Total notional principal					5,162					7,851
Interest rate contract for costless collar
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2024					0
2025					1,098
2026					41
2027					0
2028					0
Thereafter					0
Total notional principal					1,139					0
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2024					34
2025					13
2026					0
2027					0
2028					0
Thereafter					0
Total notional principal					$ 47					$ 80
Commodity contracts \| Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2022 notional quantity (in bcf, bbl or mbbl) \| Bcf	31	31	31	31	31
2023 notional quantity (in bcf, bbl or mbbl) \| Bcf	32	32	32	32	32
2024 notional quantity (in bcf, bbl or mbbl) \| Bcf	13	13	13	13	13
2025 notional quantity (in bcf, bbl or mbbl) \| Bcf	10	10	10	10	10
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	86	86	86	86	86	93	93	93	93	93
Commodity contracts \| Crude
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2022 notional quantity (in bcf, bbl or mbbl) \| MMBbls	6	6	6	6	6
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	6	6	6	6	6	16	16	16	16	16
Commodity contracts \| Power \| Net sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2022 notional quantity (MW/H) \| MWh	49	49	49	49	49
2023 notional quantity (MW/H) \| MWh	(14)	(14)	(14)	(14)	(14)
2024 notional quantity (MW/H) \| MWh	(26)	(26)	(26)	(26)	(26)
2025 notional quantity (MW/H) \| MWh	(53)	(53)	(53)	(53)	(53)
2026 notional quantity (MW/H) \| MWh	(57)	(57)	(57)	(57)	(57)
Thereafter notional quantity (MW/H) \| MWh	(30)	(30)	(30)	(30)	(30)
Total notional quantity (MW/H) \| MWh	(22)	(22)	(22)	(22)	(22)	(14)	(14)	(14)	(14)	(14)

RISK MANAGEMENT AND FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value Derivatives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Realized loss on derivative	$ (97)	$ (431)	$ 59
Interest rate contracts \| Fair value hedges
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Unrealized gain/(loss) on derivative	(132)	262
Unrealized gain/(loss) on hedged item	131	(254)
Realized loss on derivative	(47)	(110)
Realized gain on hedged item	$ 0	$ 85

RISK MANAGEMENT AND FINANCIAL_7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Effects on Earnings and Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	$ 282	$ 1,062	$ 191
Amount of loss reclassified from AOCI to earnings	$ 28	203	304
Period to hedge exposures to the variability of cash flows for all forecasted transactions	2 years
Cash flow hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Loss from AOCI expected to be reclassified	$ 18
Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of loss reclassified from AOCI to earnings	0	13	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	0	3	(29)
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	15	(35)	(5)
Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of loss reclassified from AOCI to earnings	28	186	296
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	201	1,151	252
Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of loss reclassified from AOCI to earnings	0	0	1
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	68	(53)	(28)
Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of loss reclassified from AOCI to earnings	0	4	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	$ (2)	$ (4)	$ 1

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value Derivatives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	$ 1,180	$ (1,280)	$ 173
Non- Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	1,180	(1,280)	173
Foreign exchange contracts \| Non- Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	1,292	(1,344)	92
Foreign exchange contracts \| Non- Qualifying Derivative Instruments \| Transportation and other services
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	645	(238)	98
Foreign exchange contracts \| Non- Qualifying Derivative Instruments \| Other income/(expense)
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	647	(1,106)	(6)
Interest rate contracts \| Non- Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(63)	10	2
Commodity contracts \| Non- Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(41)	50	71
Commodity contracts \| Non- Qualifying Derivative Instruments \| Transportation and other services
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(35)	13	9
Commodity contracts \| Non- Qualifying Derivative Instruments \| Commodity sales
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	153	89	160
Commodity contracts \| Non- Qualifying Derivative Instruments \| Commodity costs
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(94)	(102)	(105)
Commodity contracts \| Non- Qualifying Derivative Instruments \| Operating and administrative expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(65)	50	7
Other contracts \| Non- Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	$ (8)	$ 4	$ 8

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Liquidity and Credit Risk (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
LIQUIDITY RISK AND CREDIT RISK
Rolling time period over which the company forecasts cash requirements	12 months
Period of anticipated requirements for which the company maintains sufficient liquidity through committed credit facilities	1 year
Cash collateral	$ 0	$ 0
Derivative Instruments
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	1,062,000,000	1,584,000,000
Derivative Instruments \| Canadian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	457,000,000	644,000,000
Derivative Instruments \| US financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	252,000,000	277,000,000
Derivative Instruments \| European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	107,000,000	334,000,000
Derivative Instruments \| Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	121,000,000	224,000,000
Derivative Instruments \| Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 125,000,000	$ 105,000,000

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Derivatives (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Fair Value of Derivatives
Short-term portion of derivative assets	$ 623	$ 1,015
Current derivative liabilities	(738)	(898)
Total net financial asset/(liability)	(404)	(546)
Foreign exchange contracts
Fair Value of Derivatives
Total net financial asset/(liability)	(152)	(1,327)
Interest rate contracts
Fair Value of Derivatives
Total net financial asset/(liability)	(156)	910
Commodity contracts
Fair Value of Derivatives
Total net financial asset/(liability)	(96)	(139)
Other contracts
Fair Value of Derivatives
Total net financial asset/(liability)	0	10
Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	623	1,015
Long-term derivative assets	463	627
Current derivative liabilities	(738)	(898)
Long-term derivative liabilities	(752)	(1,290)
Total net financial asset/(liability)	(404)	(546)
Fair Value \| Foreign exchange contracts
Fair Value of Derivatives
Short-term portion of derivative assets	139	46
Long-term derivative assets	335	309
Current derivative liabilities	(128)	(566)
Long-term derivative liabilities	(498)	(1,116)
Total net financial asset/(liability)	(152)	(1,327)
Fair Value \| Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets	65	660
Long-term derivative assets	53	254
Current derivative liabilities	(186)
Long-term derivative liabilities	(88)	(4)
Total net financial asset/(liability)	(156)	910
Fair Value \| Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	418	302
Long-term derivative assets	75	61
Current derivative liabilities	(423)	(332)
Long-term derivative liabilities	(166)	(170)
Total net financial asset/(liability)	(96)	(139)
Fair Value \| Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets	1	7
Long-term derivative assets		3
Current derivative liabilities	(1)
Total net financial asset/(liability)	0	10
Level 1 \| Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	142	65
Long-term derivative assets	0	0
Current derivative liabilities	(136)	(60)
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	6	5
Level 1 \| Fair Value \| Foreign exchange contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	0	0
Level 1 \| Fair Value \| Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	0	0
Level 1 \| Fair Value \| Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	142	65
Long-term derivative assets	0	0
Current derivative liabilities	(136)	(60)
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	6	5
Level 1 \| Fair Value \| Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0	0
Long-term derivative assets		0
Current derivative liabilities	0
Total net financial asset/(liability)	0	0
Level 2 \| Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	308	803
Long-term derivative assets	412	583
Current derivative liabilities	(391)	(643)
Long-term derivative liabilities	(608)	(1,158)
Total net financial asset/(liability)	(279)	(415)
Level 2 \| Fair Value \| Foreign exchange contracts
Fair Value of Derivatives
Short-term portion of derivative assets	139	46
Long-term derivative assets	335	309
Current derivative liabilities	(128)	(566)
Long-term derivative liabilities	(498)	(1,116)
Total net financial asset/(liability)	(152)	(1,327)
Level 2 \| Fair Value \| Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets	65	660
Long-term derivative assets	53	254
Current derivative liabilities	(186)
Long-term derivative liabilities	(88)	(4)
Total net financial asset/(liability)	(156)	910
Level 2 \| Fair Value \| Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	103	90
Long-term derivative assets	24	17
Current derivative liabilities	(76)	(77)
Long-term derivative liabilities	(22)	(38)
Total net financial asset/(liability)	29	(8)
Level 2 \| Fair Value \| Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets	1	7
Long-term derivative assets		3
Current derivative liabilities	(1)
Total net financial asset/(liability)	0	10
Level 3
Fair Value of Derivatives
Total net financial asset/(liability)	(131)
Level 3 \| Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	173	147
Long-term derivative assets	51	44
Current derivative liabilities	(211)	(195)
Long-term derivative liabilities	(144)	(132)
Total net financial asset/(liability)	(131)	(136)
Level 3 \| Fair Value \| Foreign exchange contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	0	0
Level 3 \| Fair Value \| Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0
Long-term derivative liabilities	0	0
Total net financial asset/(liability)	0	0
Level 3 \| Fair Value \| Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	173	147
Long-term derivative assets	51	44
Current derivative liabilities	(211)	(195)
Long-term derivative liabilities	(144)	(132)
Total net financial asset/(liability)	(131)	(136)
Level 3 \| Fair Value \| Other contracts
Fair Value of Derivatives
Short-term portion of derivative assets	0	0
Long-term derivative assets		0
Current derivative liabilities	0
Total net financial asset/(liability)	$ 0	$ 0

RISK MANAGEMENT AND FINANCIA_11

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Level 3 Inputs (Details) $ in Millions	Dec. 31, 2023 CAD ($) $ / MWh $ / bbl $ / MillionsofBTU-MMBTU	Dec. 31, 2022 CAD ($)
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (404)	$ (546)
Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(404)	(546)
Level 3
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(131)
Level 3 \| Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (131)	$ (136)
Market approach valuation technique \| Level 3 \| Commodity Contracts - Financial \| Natural gas \| Minimum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MillionsofBTU-MMBTU	2.66
Market approach valuation technique \| Level 3 \| Commodity Contracts - Financial \| Natural gas \| Maximum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MillionsofBTU-MMBTU	8.29
Market approach valuation technique \| Level 3 \| Commodity Contracts - Financial \| Natural gas \| Weighted Average Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MillionsofBTU-MMBTU	3.78
Market approach valuation technique \| Level 3 \| Commodity Contracts - Financial \| Crude \| Minimum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / bbl	69.01
Market approach valuation technique \| Level 3 \| Commodity Contracts - Financial \| Crude \| Maximum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / bbl	92.76
Market approach valuation technique \| Level 3 \| Commodity Contracts - Financial \| Crude \| Weighted Average Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / bbl	80.35
Market approach valuation technique \| Level 3 \| Commodity Contracts - Financial \| Power \| Minimum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MWh	29.75
Market approach valuation technique \| Level 3 \| Commodity Contracts - Financial \| Power \| Maximum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MWh	145.24
Market approach valuation technique \| Level 3 \| Commodity Contracts - Financial \| Power \| Weighted Average Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MWh	59.21
Market approach valuation technique \| Level 3 \| Commodity Contracts - Physical \| Natural gas \| Minimum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MillionsofBTU-MMBTU	0.86
Market approach valuation technique \| Level 3 \| Commodity Contracts - Physical \| Natural gas \| Maximum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MillionsofBTU-MMBTU	11.85
Market approach valuation technique \| Level 3 \| Commodity Contracts - Physical \| Natural gas \| Weighted Average Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MillionsofBTU-MMBTU	3.42
Market approach valuation technique \| Level 3 \| Commodity Contracts - Physical \| Crude \| Minimum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / bbl	64.51
Market approach valuation technique \| Level 3 \| Commodity Contracts - Physical \| Crude \| Maximum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / bbl	98.11
Market approach valuation technique \| Level 3 \| Commodity Contracts - Physical \| Crude \| Weighted Average Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / bbl	82.85
Market approach valuation technique \| Level 3 \| Commodity Contracts - Physical \| Power \| Minimum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MWh	18.20
Market approach valuation technique \| Level 3 \| Commodity Contracts - Physical \| Power \| Maximum Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MWh	164.84
Market approach valuation technique \| Level 3 \| Commodity Contracts - Physical \| Power \| Weighted Average Price
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price \| $ / MWh	58.46
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	$ (6)
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	(7)
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	(87)
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	14
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	(7)
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	$ (38)

RISK MANAGEMENT AND FINANCIA_12

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Changes in Level 3 (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Changes in net fair value of derivative assets and liabilities classified as Level 3
Level 3 net derivative liability at beginning of period	$ (136)	$ (108)
Total gain/(loss), unrealized
Included in earnings	(48)	6
Included in OCI	67	(54)
Settlements	(14)	20
Level 3 net derivative liability at end of year	$ (131)	$ (136)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Cost of Goods and Services Sold, Operating and administrative, Operating revenues (Note 4)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Other Comprehensive Income or Comprehensive Income [Extensible Enumeration]	Other Comprehensive Income (Loss), Net of Tax

RISK MANAGEMENT AND FINANCIA_13

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Other Financial Instruments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Fair Value of Other Financial Instruments
Equity investments at carrying value	$ 173	$ 102
Long-term debt	78,100	73,500
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	34	(26)
Level 1 \| Debt Securities
Fair Value of Other Financial Instruments
Fair value of investments	287	335
Level 2
Fair Value of Other Financial Instruments
Investment owned restricted cost	279	295
Level 2 \| Debt Securities
Fair Value of Other Financial Instruments
Fair value of investments	284	298
Net investment hedges
Fair Value of Other Financial Instruments
Unrealized foreign exchange gain (loss) on translation of United States dollar denominated debt	645	(954)
Realized loss associated with the settlement of foreign exchange forward contracts	236	21
Carrying value
Fair Value of Other Financial Instruments
Long-term debt	81,200	79,300
Long-term loans receivable from affiliates	53	752
Fair Value
Fair Value of Other Financial Instruments
Fair value note receivable	$ 53	$ 752

RISK MANAGEMENT AND FINANCIA_14

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Restricted Long-Term Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Long-Lived Assets Held-for-sale [Line Items]
Assets Held-in-trust, Noncurrent	$ 717	$ 593
Restricted long-term investments (Note 23)	717	593
Debt securities, available-for-sale, amortized cost	486	437
Unrealized holding gains (losses)	$ 51	$ (122)
Fair value recurring basis unobservable input reconciliation asset gain loss statement of other comprehensive income extensible list not disclosed flag	investments	investments
Future abandonment costs	$ 745
Level 1
Long-Lived Assets Held-for-sale [Line Items]
Restricted long-term investments (Note 23)	263	$ 236
Level 2
Long-Lived Assets Held-for-sale [Line Items]
Restricted long-term investments (Note 23)	$ 454	$ 357

INCOME TAXES - Rate Reconciliat

INCOME TAXES - Rate Reconciliation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
INCOME TAX RATE RECONCILIATION
Earnings before income taxes	$ 7,879	$ 4,542	$ 7,729
Canadian federal statutory income tax rate	15%	15%	15%
Expected federal taxes at statutory rate	$ 1,182	$ 681	$ 1,159
Increase/(decrease) resulting from:
Provincial and state income taxes	411	108	228
Foreign and other statutory rate differentials	187	295	134
Effects of rate-regulated accounting	(106)	(122)	(139)
Write-off of regulatory deferrals	115	0	0
Part VI.1 tax, net of federal Part I deduction	66	76	73
US minimum tax	100	107	0
Non-taxable portion of gain on sale of investment	0	0	(23)
Valuation allowance	(12)	6	5
Accounting impairment of non-deductible goodwill	0	370	0
Noncontrolling interests	19	9	(17)
Investment and production tax credits	(47)	0	0
Other	(94)	74	(5)
Income tax expense	$ 1,821	$ 1,604	$ 1,415
Effective income tax rate (as a percent)	23.10%	35.30%	18.30%

INCOME TAXES - Components (Deta

INCOME TAXES - Components (Details) - CAD ($) $ in Millions	12 Months Ended
INCOME TAXES - Components (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings before income taxes
Earnings before income taxes	$ 7,879	$ 4,542	$ 7,729
Current income taxes
Total current income taxes	401	647	324
Deferred income taxes
Total deferred income taxes	1,420	957	1,091
Income tax expense	1,821	1,604	1,415
Financial instruments	271	456
Canada
Earnings before income taxes
Domestic	2,233	583	3,399
Current income taxes
Domestic	100	360	162
Deferred income taxes
Domestic	456	(358)	344
US
Earnings before income taxes
Foreign	4,620	2,865	3,336
Current income taxes
Foreign	191	201	80
Deferred income taxes
Foreign	974	1,309	741
Other
Earnings before income taxes
Foreign	1,026	1,094	994
Current income taxes
Foreign	110	86	82
Deferred income taxes
Foreign	$ (10)	$ 6	$ 6

INCOME TAXES - Deferred Income

INCOME TAXES - Deferred Income Tax Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred income tax liabilities
Property, plant and equipment	$ (9,202)	$ (9,096)
Investments	(7,765)	(7,099)
Regulatory assets	(1,338)	(1,291)
Other	(52)	(46)
Total deferred income tax liabilities	(18,357)	(17,532)
Deferred income tax assets
Financial instruments	271	456
Loss carryforwards	1,745	2,259
Other	1,798	1,723
Total deferred income tax assets	3,814	4,438
Less valuation allowance	(147)	(215)
Total deferred income tax assets, net	3,667	4,223
Net deferred income tax liabilities	(14,690)	(13,309)
Total deferred income tax assets	341	472
Total deferred income tax liabilities	$ (15,031)	$ (13,781)

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
INCOME TAXES - Narrative (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Income Taxes
Operating loss carryforwards that do not expire	$ 6,300	$ 7,900
Foreign subsidiaries' undistributed earnings on which deferred income taxes has not been provided	6,600	8,000
Interest and penalties expense (recovery) related to unrecognized tax benefits	1	1
Accrued interest and penalties related to unrecognized tax benefits	14	13
Canada
Income Taxes
Benefit of unused tax loss carryforwards recognized	1,300	2,100
US
Income Taxes
Benefit of unused tax loss carryforwards recognized	6,400	8,100
Operating loss carryforwards that expire	$ 100	$ 200

INCOME TAXES - Unrecognized Tax

INCOME TAXES - Unrecognized Tax Benefits (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
UNRECOGNIZED TAX BENEFITS
Unrecognized tax benefits at beginning of year	$ 55	$ 76
Gross decreases for tax positions of prior year	(2)	(17)
Change in translation of foreign currency	(1)	1
Lapses of statute of limitations	(7)	(5)
Unrecognized tax benefits at end of year	$ 45	$ 55

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Change in plan assets
Fair value of plan assets at beginning of year	$ 32
Fair value of plan assets at end of year	61	$ 32
Canada \| Pension
Change in projected benefit obligation
Projected benefit obligation at beginning of year	3,630	4,600
Service cost	81	131	$ 139
Interest cost	184	127	101
Participant contributions	31	29
Actuarial gain	359	(1,069)
Benefits paid	(193)	(187)
Foreign currency exchange rate changes	0	0
Other	0	(1)
Projected benefit obligation at end of year	4,092	3,630	4,600
Change in plan assets
Fair value of plan assets at beginning of year	4,234	4,536
Actual return/(loss) on plan assets	427	(235)
Employer contributions	27	91
Participant contributions	31	29
Benefits paid	(193)	(187)
Foreign currency exchange rate changes	0	0
Other	2	0
Fair value of plan assets at end of year	4,528	4,234	4,536
Overfunded status at end of year	436	604
Presented as follows:
Deferred amounts and other assets	636	764
Other current liabilities	(8)	(9)
Other long-term liabilities	(192)	(151)
Amount recognized in balance sheet	436	604
Accumulated benefit obligation	3,800	3,400
Canada \| Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	14	10
Canada \| OPEB
Change in projected benefit obligation
Projected benefit obligation at beginning of year	211	274
Service cost	3	4	6
Interest cost	11	7	7
Participant contributions	0	0
Actuarial gain	13	(66)
Benefits paid	(10)	(8)
Foreign currency exchange rate changes	0	0
Projected benefit obligation at end of year	228	211	274
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	10	8
Participant contributions	0	0
Benefits paid	(10)	(8)
Foreign currency exchange rate changes	0	0
Fair value of plan assets at end of year	0	0	0
Overfunded status at end of year	(228)	(211)
Presented as follows:
Deferred amounts and other assets	0	0
Other current liabilities	(12)	(12)
Other long-term liabilities	(216)	(199)
Amount recognized in balance sheet	(228)	(211)
US
Change in plan assets
Employer contributions	33	30	27
US \| Pension
Change in projected benefit obligation
Projected benefit obligation at beginning of year	1,029	1,184
Service cost	40	43	44
Interest cost	47	24	17
Participant contributions	0	0
Actuarial gain	31	(201)
Benefits paid	(76)	(94)
Foreign currency exchange rate changes	(29)	77
Other	(6)	(4)
Projected benefit obligation at end of year	1,036	1,029	1,184
Change in plan assets
Fair value of plan assets at beginning of year	1,080	1,160
Actual return/(loss) on plan assets	78	(64)
Employer contributions	5	4
Participant contributions	0	0
Benefits paid	(76)	(94)
Foreign currency exchange rate changes	(29)	78
Other	(6)	(4)
Fair value of plan assets at end of year	1,052	1,080	1,160
Overfunded status at end of year	16	51
Presented as follows:
Deferred amounts and other assets	116	141
Other current liabilities	(5)	(5)
Other long-term liabilities	(95)	(85)
Amount recognized in balance sheet	16	51
Accumulated benefit obligation	1,000	1,000
US \| Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	62	58
US \| OPEB
Change in projected benefit obligation
Projected benefit obligation at beginning of year	136	173
Service cost	1	1	1
Interest cost	6	3	3
Participant contributions	5	6
Actuarial gain	4	(37)
Benefits paid	(20)	(21)
Foreign currency exchange rate changes	(3)	11
Projected benefit obligation at end of year	129	136	173
Change in plan assets
Fair value of plan assets at beginning of year	185	201
Actual return/(loss) on plan assets	14	(21)
Employer contributions	7	7
Participant contributions	5	6
Benefits paid	(20)	(21)
Foreign currency exchange rate changes	(4)	13
Fair value of plan assets at end of year	187	185	$ 201
Overfunded status at end of year	58	49
Presented as follows:
Deferred amounts and other assets	73	75
Other current liabilities	0	0
Other long-term liabilities	(15)	(26)
Amount recognized in balance sheet	$ 58	$ 49

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, 2023	Dec. 31, 2022
Canada
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	$ 394	$ 360
Fair value of plan assets	243	218
Canada \| OPEB
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	228	211
Fair value of plan assets	0	0
Projected benefit obligation	416	377
Fair value of plan assets	243	218
US
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	99	89
Fair value of plan assets	0	0
US \| OPEB
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	78	76
Fair value of plan assets	63	50
Projected benefit obligation	99	90
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, 2023	Dec. 31, 2022
Canada \| Pension
Amount included in AOCI
Net actuarial (gain)/loss	$ 51	$ (64)
Prior service cost	0	0
Total amount recognized in AOCI	51	(64)
Canada \| OPEB
Amount included in AOCI
Net actuarial (gain)/loss	(82)	(101)
Prior service cost	(1)	(1)
Total amount recognized in AOCI	(83)	(102)
US \| Pension
Amount included in AOCI
Net actuarial (gain)/loss	74	40
Prior service cost	1	1
Total amount recognized in AOCI	75	41
US \| OPEB
Amount included in AOCI
Net actuarial (gain)/loss	(96)	(102)
Prior service cost	(22)	(30)
Total amount recognized in AOCI	$ (118)	$ (132)

PENSION AND OTHER POSTRETIREM_6

PENSION AND OTHER POSTRETIREMENT BENEFITS - Net Benefit Costs Recognized (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension \| Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 81	$ 131	$ 139
Interest cost	184	127	101
Expected return on plan assets	(271)	(295)	(252)
Amortization/settlement of net actuarial loss	0	8	54
Amortization/curtailment of prior service credit	0	0	0
Net periodic benefit (credit)/cost	(6)	(29)	42
Defined contribution benefit cost	12	10	7
Net pension (credit)/cost recognized in Earnings	6	(19)	49
Amount recognized in OCI:
Amortization/settlement of net actuarial (gain)/loss	0	(2)	(25)
Amortization/curtailment of prior service credit	0	0	0
Net actuarial (gain)/loss arising during the year	115	(288)	(291)
Total amount recognized in OCI	115	(290)	(316)
Total amount recognized in Comprehensive income	121	(309)	(267)
Pension \| US
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	40	43	44
Interest cost	47	24	17
Expected return on plan assets	(77)	(85)	(73)
Amortization/settlement of net actuarial loss	(4)	0	11
Amortization/curtailment of prior service credit	0	(2)	0
Net periodic benefit (credit)/cost	6	(20)	(1)
Defined contribution benefit cost	0	0	0
Net pension (credit)/cost recognized in Earnings	6	(20)	(1)
Amount recognized in OCI:
Amortization/settlement of net actuarial (gain)/loss	4	0	(11)
Amortization/curtailment of prior service credit	0	2	0
Net actuarial (gain)/loss arising during the year	30	(52)	(99)
Total amount recognized in OCI	34	(50)	(110)
Total amount recognized in Comprehensive income	40	(70)	(111)
OPEB \| Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	3	4	6
Interest cost	11	7	7
Expected return on plan assets	0	0	0
Amortization/settlement of net actuarial loss	(6)	(1)	0
Amortization/curtailment of prior service credit	0	0	0
Net pension (credit)/cost recognized in Earnings	8	10	13
Amount recognized in OCI:
Amortization/settlement of net actuarial (gain)/loss	6	1	0
Amortization/curtailment of prior service credit	0	0	0
Net actuarial (gain)/loss arising during the year	13	(67)	(50)
Total amount recognized in OCI	19	(66)	(50)
Total amount recognized in Comprehensive income	27	(56)	(37)
OPEB \| US
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	1	1	1
Interest cost	6	3	3
Expected return on plan assets	(11)	(12)	(10)
Amortization/settlement of net actuarial loss	(6)	(6)	(1)
Amortization/curtailment of prior service credit	(8)	(7)	(7)
Net pension (credit)/cost recognized in Earnings	(18)	(21)	(14)
Amount recognized in OCI:
Amortization/settlement of net actuarial (gain)/loss	6	6	1
Amortization/curtailment of prior service credit	8	7	7
Net actuarial (gain)/loss arising during the year	0	(4)	(80)
Total amount recognized in OCI	14	9	(72)
Total amount recognized in Comprehensive income	$ (4)	$ (12)	$ (86)

PENSION AND OTHER POSTRETIREM_7

PENSION AND OTHER POSTRETIREMENT BENEFITS - Actuarial Assumptions (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension \| Canada
Projected benefit obligation
Discount rate	4.60%	5.10%	3.20%
Rate of salary increase	3%	2.90%	2.90%
Net periodic benefit cost
Discount rate	5.30%	3.20%	2.60%
Rate of return on plan assets	6.50%	6.60%	6.20%
Rate of salary increase	2.90%	2.90%	2.30%
Pension \| US
Projected benefit obligation
Discount rate	4.70%	4.90%	2.60%
Rate of salary increase	2.60%	2.80%	2.80%
Cash balance interest credit rate	4.50%	4.30%	4.30%
Net periodic benefit cost
Discount rate	4.90%	2.60%	2.20%
Rate of return on plan assets	7.40%	7.40%	7.30%
Rate of salary increase	2.80%	2.80%	2.70%
Cash balance interest credit rate	4.30%	4.30%	4.30%
OPEB \| Canada
Projected benefit obligation
Discount rate	4.60%	5.30%	3.20%
Net periodic benefit cost
Discount rate	5.30%	3.20%	2.60%
OPEB \| US
Projected benefit obligation
Discount rate	4.70%	4.90%	2.40%
Net periodic benefit cost
Discount rate	4.90%	2.40%	2%
Rate of return on plan assets	5.90%	6%	6%

PENSION AND OTHER POSTRETIREM_8

PENSION AND OTHER POSTRETIREMENT BENEFITS - Assumed Health Care Cost Trend Rates (Details)	Dec. 31, 2023	Dec. 31, 2022
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%
US
MEDICAL COST TRENDS (as percent)
Health care cost trend rate assumed for next year	4.70%	4.70%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	3.30%	3.30%
US \| Enbridge Employee Services, Inc. Health Reimbursement Account Plan
MEDICAL COST TRENDS (as percent)
Increase in defined benefit plan	5%

PENSION AND OTHER POSTRETIREM_9

PENSION AND OTHER POSTRETIREMENT BENEFITS - Plan Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Change in plan assets
Fair value of plan assets at beginning of year	$ 32
Fair value of plan assets at end of year	$ 61	$ 32
Canada \| Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	46%
Plan asset allocations	41.40%	38.20%
Canada \| Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	23.20%
Plan asset allocations	29.60%	31.70%
Canada \| Alternatives
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	30.80%
Plan asset allocations	29%	30.10%
Canada \| Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 4,234	$ 4,536
Fair value of plan assets at end of year	4,528	4,234
Canada \| Pension \| Level 1
Change in plan assets
Fair value of plan assets at beginning of year	473
Fair value of plan assets at end of year	227	473
Canada \| Pension \| Level 2
Change in plan assets
Fair value of plan assets at beginning of year	2,470
Fair value of plan assets at end of year	3,011	2,470
Canada \| Pension \| Level 3
Change in plan assets
Fair value of plan assets at beginning of year	1,291	1,064
Unrealized and realized gains/(losses)	(41)	155
Purchases and settlements, net	40	72
Fair value of plan assets at end of year	1,290	1,291
Canada \| Pension \| Alternatives
Change in plan assets
Fair value of plan assets at beginning of year	1,291
Fair value of plan assets at end of year	1,290	1,291
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	1,291
Fair value of plan assets at end of year	1,290	1,291
Canada \| Pension \| Cash and Cash Equivalents
Change in plan assets
Fair value of plan assets at beginning of year	272
Fair value of plan assets at end of year	227	272
Canada \| Pension \| Cash and Cash Equivalents \| Level 1
Change in plan assets
Fair value of plan assets at beginning of year	272
Fair value of plan assets at end of year	227	272
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	1,263
Fair value of plan assets at end of year	1,871	1,263
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	1,263
Fair value of plan assets at end of year	1,871	1,263
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, Global
Change in plan assets
Fair value of plan assets at beginning of year	355
Fair value of plan assets at end of year	3	355
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	355
Fair value of plan assets at end of year	3	355
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	636
Fair value of plan assets at end of year	446	636
Canada \| Pension \| Government \| Level 1
Change in plan assets
Fair value of plan assets at beginning of year	201
Fair value of plan assets at end of year	0	201
Canada \| Pension \| Government \| Level 2
Change in plan assets
Fair value of plan assets at beginning of year	435
Fair value of plan assets at end of year	446	435
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	433
Fair value of plan assets at end of year	667	433
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	433
Fair value of plan assets at end of year	667	433
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	(16)
Fair value of plan assets at end of year	24	(16)
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	(16)
Fair value of plan assets at end of year	24	(16)
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
US \| Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	45%
Plan asset allocations	39.50%	38.30%
US \| Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	20%
Plan asset allocations	19.40%	20.50%
US \| Alternatives
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	35%
Plan asset allocations	41.10%	41.20%
US \| Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 1,080	$ 1,160
Fair value of plan assets at end of year	1,052	1,080
US \| Pension \| Level 1
Change in plan assets
Fair value of plan assets at beginning of year	13
Fair value of plan assets at end of year	8	13
US \| Pension \| Level 2
Change in plan assets
Fair value of plan assets at beginning of year	622
Fair value of plan assets at end of year	611	622
US \| Pension \| Level 3
Change in plan assets
Fair value of plan assets at beginning of year	445	337
Unrealized and realized gains/(losses)	(12)	78
Purchases and settlements, net	0	30
Fair value of plan assets at end of year	433	445
US \| Pension \| Alternatives
Change in plan assets
Fair value of plan assets at beginning of year	445
Fair value of plan assets at end of year	433	445
US \| 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
US \| 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
US \| Pension \| Alternatives \| Level 3
Change in plan assets
Fair value of plan assets at beginning of year	445
Fair value of plan assets at end of year	433	445
US \| Pension \| Cash and Cash Equivalents
Change in plan assets
Fair value of plan assets at beginning of year	13
Fair value of plan assets at end of year	8	13
US \| Pension \| Cash and Cash Equivalents \| Level 1
Change in plan assets
Fair value of plan assets at beginning of year	13
Fair value of plan assets at end of year	8	13
US \| 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
US \| 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
US \| Pension \| Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	414
Fair value of plan assets at end of year	416	414
US \| 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
US \| Pension \| Equity Securities, Global \| Level 2
Change in plan assets
Fair value of plan assets at beginning of year	414
Fair value of plan assets at end of year	416	414
US \| 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
US \| 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
US \| 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
US \| 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
US \| 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
US \| Pension \| Government
Change in plan assets
Fair value of plan assets at beginning of year	87
Fair value of plan assets at end of year	46	87
US \| 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
US \| Pension \| Government \| Level 2
Change in plan assets
Fair value of plan assets at beginning of year	87
Fair value of plan assets at end of year	46	87
US \| 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
US \| Pension \| Corporate
Change in plan assets
Fair value of plan assets at beginning of year	121
Fair value of plan assets at end of year	149	121
US \| 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
US \| Pension \| Corporate \| Level 2
Change in plan assets
Fair value of plan assets at beginning of year	121
Fair value of plan assets at end of year	149	121
US \| 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
US \| 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
US \| 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
US \| 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
US \| 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
US \| OPEB
Change in plan assets
Fair value of plan assets at beginning of year	185	201
Fair value of plan assets at end of year	187	185
US \| OPEB \| Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	185
Fair value of plan assets at end of year	187	185
US \| OPEB \| Level 1 \| Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	48
Fair value of plan assets at end of year	45	48
US \| OPEB \| Level 2 \| Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	109
Fair value of plan assets at end of year	113	109
US \| OPEB \| Level 3
Change in plan assets
Fair value of plan assets at beginning of year	28	22
Unrealized and realized gains/(losses)	1	4
Purchases and settlements, net	0	2
Fair value of plan assets at end of year	29	28
US \| OPEB \| Level 3 \| Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	28
Fair value of plan assets at end of year	29	28
US \| OPEB \| Alternatives \| Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	28
Fair value of plan assets at end of year	29	28
US \| 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
US \| 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
US \| OPEB \| Alternatives \| Level 3 \| Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	28
Fair value of plan assets at end of year	29	28
US \| OPEB \| Cash and Cash Equivalents \| Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	2
Fair value of plan assets at end of year	3	2
US \| OPEB \| Cash and Cash Equivalents \| Level 1 \| Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	2
Fair value of plan assets at end of year	3	2
US \| 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
US \| 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
US \| OPEB \| Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	34
Fair value of plan assets at end of year	36	34
US \| 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
US \| OPEB \| Equity Securities, US \| Level 2
Change in plan assets
Fair value of plan assets at beginning of year	34
Fair value of plan assets at end of year	36	34
US \| 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
US \| OPEB \| Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	62
Fair value of plan assets at end of year	62	62
US \| 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
US \| OPEB \| Equity Securities, Global \| Level 2
Change in plan assets
Fair value of plan assets at beginning of year	62
Fair value of plan assets at end of year	62	62
US \| 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
US \| OPEB \| Government \| 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	45	51
US \| OPEB \| Government \| Level 1 \| Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	46
Fair value of plan assets at end of year	42	46
US \| OPEB \| Government \| Level 2 \| Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	5
Fair value of plan assets at end of year	3	5
US \| 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
US \| 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	12	8
US \| 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
US \| 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	12	8
US \| 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, 2023 CAD ($)
Canada \| Pension
Benefits Expected to be Paid by the Company
2024	$ 207
2025	213
2026	219
2027	224
2028	230
2029-2033	1,234
Contributions expected to be paid in next fiscal year	18
Canada \| OPEB
Benefits Expected to be Paid by the Company
2024	13
2025	13
2026	13
2027	13
2028	13
2029-2033	70
Contributions expected to be paid in next fiscal year	13
US \| Pension
Benefits Expected to be Paid by the Company
2024	87
2025	87
2026	87
2027	86
2028	81
2029-2033	393
Contributions expected to be paid in next fiscal year	5
US \| OPEB
Benefits Expected to be Paid by the Company
2024	16
2025	15
2026	14
2027	13
2028	12
2029-2033	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) - US - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension and Other Postretirement Benefit Disclosures
Percent of match (percent)	6%
Total contributions by the Company	$ 33	$ 30	$ 27

LEASES - Narrative (Details)

LEASES - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
LEASES - Narrative (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Operating lease, expense	$ 131	$ 118	$ 95
Operating lease, payments	$ 129	$ 123	$ 118
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease term	1 month
Lessor, operating lease, remaining lease term	3 months
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	35 years
Lessor, operating lease, remaining lease term	28 years

LEASES - Supplemental Statement

LEASES - Supplemental Statements of Financial Position (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Leases, Operating [Abstract]
Operating lease right-of-use assets, net	$ 669	$ 680
Operating lease liabilities - current	98	87
Operating lease liabilities - long-term	652	677
Total operating lease liabilities	$ 750	$ 764
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 Accrued Liabilities, Current	Accounts Payable and Other Accrued Liabilities, Current
Operating lease, liability, noncurrent, statement of financial position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Finance leases
Finance lease right-of-use assets, net	$ 287	$ 62
Finance lease liabilities - current	19	17
Finance lease liabilities - long-term	264	39
Total finance lease liabilities	$ 283	$ 56
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 17)	Current portion of long-term debt (Note 17)
Finance lease, liability, noncurrent, statement of financial position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Weighted average remaining lease term
Operating leases	12 years	12 years
Finance leases	31 years	5 years
Weighted average discount rate
Operating leases	4.50%	4.20%
Finance leases	5.70%	4.40%
Affiliated Entity
Leases, Operating [Abstract]
Operating lease right-of-use assets, net	$ 42	$ 47
Operating lease liabilities - current	5	5
Operating lease liabilities - long-term	$ 38	$ 43

LEASES - Lease Commitments (Det

LEASES - Lease Commitments (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Operating leases
2024	$ 130
2025	120
2026	106
2027	96
2028	75
Thereafter	459
Total undiscounted lease payments	986
Less imputed interest	(236)
Total	750	$ 764
Finance leases
2024	31
2025	25
2026	25
2027	18
2028	18
Thereafter	502
Total undiscounted lease payments	619
Less imputed interest	(336)
Total finance lease liabilities	$ 283	$ 56

LEASES - Lessor Lease Income (D

LEASES - Lessor Lease Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating lease income	$ 241	$ 266	$ 263
Variable lease income	299	321	333
Total lease income	$ 540	$ 587	$ 596
Operating lease income comprehensive income extensible list not disclosed flag	Total lease income1	Total lease income1	Total lease income1

LEASES - Lessor Future Expected

LEASES - Lessor Future Expected Lease Receipts (Details) $ in Millions	Dec. 31, 2023 CAD ($)
Leases [Abstract]
2024	$ 225
2025	206
2026	201
2027	199
2028	201
Thereafter	1,612
Future lease payments	$ 2,644

OTHER INCOME_(EXPENSE) (Details

OTHER INCOME/(EXPENSE) (Details) - CAD ($) $ in Millions	12 Months Ended
OTHER INCOME/(EXPENSE) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Other Income and Expenses [Abstract]
Gain/(loss) on dispositions	$ 15	$ (12)	$ 319
Realized foreign currency gain/(loss)	(129)	92	126
Unrealized foreign currency gain/(loss)	821	(1,094)	160
Net defined pension and OPEB credit	135	239	150
Other	382	186	224
Total	$ 1,224	$ (589)	$ 979

CHANGES IN OPERATING ASSETS A_3

CHANGES IN OPERATING ASSETS AND LIABILITIES (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CHANGES IN OPERATING ASSETS AND LIABILITIES
Trade receivables and unbilled revenues	$ 1,125	$ (572)	$ (1,030)
Other current assets	1,278	(395)	(198)
Accounts receivable from affiliates	18	17	(38)
Inventory	763	(599)	(118)
Deferred amounts and other assets	23	1	(195)
Trade payables and accrued liabilities	(1,542)	585	652
Other current liabilities	339	515	(565)
Accounts payable to affiliates	(66)	16	52
Interest payable	199	58	43
Other long-term liabilities	174	362	(69)
Changes in operating assets and liabilities	$ 2,311	$ (12)	$ (1,466)

RELATED PARTY TRANSACTIONS - Tr

RELATED PARTY TRANSACTIONS - Transactions With Significantly Influenced Investees (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
RELATED PARTY TRANSACTIONS
Operating revenues (Note 4)	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 43,649	$ 53,309	$ 47,071
Operating and administrative									8,600	8,219	6,712
Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Operating and administrative									625	503	380
Commodity costs									63	778	790
Gas distribution costs									$ 140	136	131
Offshore - various joint ventures \| Minimum \| Offshore - various joint ventures \| Gas Transmission and Midstream
RELATED PARTY TRANSACTIONS
Ownership interest (as a percent)	22%								22%
Offshore - various joint ventures \| Maximum \| Offshore - various joint ventures \| Gas Transmission and Midstream
RELATED PARTY TRANSACTIONS
Ownership interest (as a percent)	74.30%								74.30%
Other \| Minimum \| Other \| Gas Distribution and Storage
RELATED PARTY TRANSACTIONS
Ownership interest (as a percent)	30%								30%
Other \| Maximum \| Other \| Gas Distribution and Storage
RELATED PARTY TRANSACTIONS
Ownership interest (as a percent)	50%								50%
Transportation and other services
RELATED PARTY TRANSACTIONS
Operating revenues (Note 4)									$ 19,829	18,506	16,172
Transportation and other services \| Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Operating revenues (Note 4)									169	185	237
Commodity sales
RELATED PARTY TRANSACTIONS
Operating revenues (Note 4)									18,981	29,150	26,873
Commodity sales \| Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Operating revenues (Note 4)									0	51	20
Seaway Crude Pipeline System \| Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Operating and administrative									632	495	389
Aux Sable Canada LP \| Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Commodity costs									$ 2	$ 571	$ 447

RELATED PARTY TRANSACTIONS - Na

RELATED PARTY TRANSACTIONS - Narrative (Details) - Affiliated Entity - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
RELATED PARTY TRANSACTIONS
Affiliate loan receivable	$ 54	$ 752
Interest income	$ 21	$ 30	$ 39
Minimum
RELATED PARTY TRANSACTIONS
Annual interest rate on the loans (as a percent)	4%
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, 2023 CAD ($)
Purchase of services, pipe and other materials, including transportation
Total	$ 11,018
Less than 1 year	4,193
2 years	1,421
3 years	1,206
4 years	1,039
5 years	996
Thereafter	2,163
Maintenance agreements2
Total	473
Less than 1 year	51
2 years	52
3 years	52
4 years	53
5 years	34
Thereafter	231
Right-of-ways commitments3
Total	1,328
Less than 1 year	44
2 years	45
3 years	45
4 years	45
5 years	45
Thereafter	1,104
Total
Total	12,819
Less than 1 year	4,288
2 years	1,518
3 years	1,303
4 years	1,137
5 years	1,075
Thereafter	$ 3,498

QUARTERLY FINANCIAL DATA (UNA_3

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - CAD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 13,424	$ 11,573	$ 13,215	$ 15,097	$ 43,649	$ 53,309	$ 47,071
Operating income	1,845	1,794	2,350	2,662	(540)	1,778	1,520	2,420	8,651	5,178	7,805
Earnings/(loss)	1,568	623	2,001	1,866	(1,109)	1,383	607	2,057	6,058	2,938	6,314
Earnings attributable to controlling interests	1,818	621	1,935	1,817	(983)	1,362	595	2,029	6,191	3,003	6,189
Earnings/(loss) attributable to common shareholders	$ 1,726	$ 532	$ 1,848	$ 1,733	$ (1,067)	$ 1,279	$ 450	$ 1,927	$ 5,839	$ 2,589	$ 5,816
Earnings per common share
Basic (in CAD per share)	$ 0.81	$ 0.26	$ 0.91	$ 0.86	$ (0.53)	$ 0.63	$ 0.22	$ 0.95	$ 2.84	$ 1.28	$ 2.87
Diluted (in CAD per share)	$ 0.81	$ 0.26	$ 0.91	$ 0.85	$ (0.53)	$ 0.63	$ 0.22	$ 0.95	$ 2.84	$ 1.28	$ 2.87

SUBSEQUENT EVENT (Details)

SUBSEQUENT EVENT (Details) - Subsequent Event - RNG Facilities $ in Billions, $ in Billions	Jan. 02, 2024 CAD ($) facility	Jan. 02, 2024 USD ($)	Jan. 02, 2026 CAD ($)	Jan. 02, 2026 USD ($)	Jan. 02, 2024 USD ($) facility
SUBSEQUENT EVENTS
Purchase price	$ 1.4	$ 1.1
Cash	$ 0.5	$ 0.4
Remaining consideration payable, payment period	2 years	2 years
Contingent consideration payable	$ 0.9		$ 1.6	$ 1.2	$ 0.7
Number of facilities acquired	7				7