Enbridge (ENB) 10-K 14 Feb 25 2024 FY Annual report Financial data

Cover

Cover - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2024	Feb. 07, 2025	Jun. 30, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
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			$ 77.5
Entity Common Stock, Shares Outstanding		2,179,049,670
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE: Not applicable.
Entity Central Index Key	0000895728
Amendment Flag	false
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2024
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, 2024 CAD ($) $ / shares	Dec. 31, 2023 CAD ($) $ / shares	Dec. 31, 2022 CAD ($) $ / shares
Operating revenues
Total operating revenues (Note 4)	$ 53,473	$ 43,649	$ 53,309
Operating expenses
Operating and administrative	9,427	8,600	8,219
Depreciation and amortization	5,167	4,613	4,317
Impairment of long-lived assets	190	419	541
Impairment of goodwill	0	0	2,465
Total operating expenses	43,824	34,998	48,131
Operating income	9,649	8,651	5,178
Income from equity investments (Note 13)	2,304	1,816	2,056
Gain on disposition of equity investments (Note 13)	1,091	0	0
Gain on joint venture merger transaction (Note 13)	0	0	1,076
Other income/(expense) (Note 27)	(1,326)	1,224	(589)
Interest expense (Note 17)	(4,419)	(3,812)	(3,179)
Earnings before income taxes	7,299	7,879	4,542
Income tax expense (Note 24)	(1,668)	(1,821)	(1,604)
Earnings	5,631	6,058	2,938
(Earnings)/loss attributable to noncontrolling interests	(190)	133	65
Earnings attributable to controlling interests	5,441	6,191	3,003
Preference share dividends	(388)	(352)	(414)
Earnings attributable to common shareholders	$ 5,053	$ 5,839	$ 2,589
Earnings per common share attributable to common shareholders (in Canadian dollars per share) | $ / shares	$ 2.34	$ 2.84	$ 1.28
Diluted earnings per common share attributable to common shareholders (in Canadian dollars per share) | $ / shares	$ 2.34	$ 2.84	$ 1.28
Commodity sales
Operating revenues
Total operating revenues (Note 4)	$ 27,018	$ 18,981	$ 29,150
Operating expenses
Commodity costs and Gas distribution costs	26,556	18,526	28,942
Gas distribution sales
Operating revenues
Total operating revenues (Note 4)	6,802	5,442	6,237
Operating expenses
Commodity costs and Gas distribution costs	2,484	2,840	3,647
Transportation and other services
Operating revenues
Total operating revenues (Note 4)	$ 19,653	$ 19,226	$ 17,922

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Earnings	$ 5,631	$ 6,058	$ 2,938
Other comprehensive income/(loss), net of tax
Change in unrealized gain on cash flow hedges	73	220	847
Change in unrealized gain/(loss) on net investment hedges	(1,305)	409	(971)
Other comprehensive income/(loss) from equity investees	(10)	6	(6)
Excluded components of fair value hedges	9	12	(35)
Reclassification to earnings of loss on cash flow hedges	23	14	143
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(16)	(18)	(10)
Reclassification to earnings of loss on equity investees	0	0	16
Actuarial gain/(loss) on pension and OPEB	248	(130)	312
Foreign currency translation adjustments	5,895	(1,728)	4,406
Other comprehensive income/(loss), net of tax	4,917	(1,215)	4,702
Comprehensive income	10,548	4,843	7,640
Comprehensive (income)/loss attributable to noncontrolling interests	(295)	131	(21)
Comprehensive income attributable to controlling interests	10,253	4,974	7,619
Preference share dividends	(388)	(352)	(414)
Comprehensive income attributable to common shareholders	$ 9,865	$ 4,622	$ 7,205

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)	Noncontrolling interests (Note 19)
Balance at beginning of year at Dec. 31, 2021			$ 7,747	$ 64,799	$ 365	$ (10,989)	$ (1,096)	$ 2,542
Increase (Decrease) in Stockholders' Equity
Redemption of preference shares			(929)
Shares issued, net of issue costs				0
Shares issued on exercise of stock options				53	(50)
Shares issued on vesting of restricted stock units (RSU), net of tax	$ 0			0
Share repurchases at stated value				(88)
Other				(4)				47
Stock-based compensation					36
Purchase of noncontrolling interests					(43)
Other				(4)	(33)
Earnings attributable to controlling interests	3,003					3,003
Preference share dividends						(414)
Common share dividends declared						(7,023)
Share repurchases 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
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	3,511
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share)	$ 3.44
Redemption of preference shares			0
Shares issued, net of issue costs				4,485
Shares issued on exercise of stock options				3	(3)
Shares issued on vesting of restricted stock units (RSU), net of tax				12	(20)
Share repurchases at stated value				(80)
Other				0				(1)
Stock-based compensation					71
Purchase of noncontrolling interests					(28)
Other				0	(27)
Earnings attributable to controlling interests	$ 6,191					6,191
Preference share dividends						(352)
Common share dividends declared						(7,423)
Share repurchases 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
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	3,029
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share)	$ 3.55
Redemption of preference shares			0
Shares issued, net of issue costs				2,489
Shares issued on exercise of stock options				39	(39)
Shares issued on vesting of restricted stock units (RSU), net of tax				30	(52)
Share repurchases at stated value				0
Other				0				0
Stock-based compensation					98
Purchase of noncontrolling interests					0
Other				0	0
Earnings attributable to controlling interests	$ 5,441					5,441
Preference share dividends						(388)
Common share dividends declared						(7,984)
Share repurchases in excess of stated value						0
Other comprehensive income/(loss) attributable to common shareholders, net of tax							4,812
Earnings/(loss) attributable to noncontrolling interests								190
Change in unrealized gain/(loss) on cash flow hedges								9
Foreign currency translation adjustments								96
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax								105
Comprehensive income/(loss) attributable to noncontrolling interests	(295)							295
Distributions								(333)
Contributions								4
Purchase of noncontrolling interests								(2)
Balance at end of year at Dec. 31, 2024	$ 68,893	$ 65,900	$ 6,818	$ 71,738	$ 275	$ (20,046)	$ 7,115	$ 2,993
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share)	$ 3.66

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2024 CAD ($)		Dec. 31, 2023 CAD ($)		Dec. 31, 2022 CAD ($)
Operating activities
Earnings		$ 5,631		$ 6,058		$ 2,938
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization		5,167		4,613		4,317
Deferred income tax expense (Note 24)		719		1,420		957
Unrealized derivative fair value (gain)/loss, net (Note 23)		2,082		(1,180)		1,280
Income from equity investments (Note 13)		(2,304)		(1,816)		(2,056)
Distributions from equity investments		2,121		1,998		1,827
Impairment of long-lived assets		190		419		541
Impairment of goodwill		0		0		2,465
Gain on joint venture merger transaction (Note 13)		0		0		(1,076)
Gain on disposition of equity investment		(1,091)		0		0
Other		218		378		49
Changes in operating assets and liabilities (Note 28)		(133)		2,311		(12)
Net cash provided by operating activities		12,600		14,201		11,230
Investing activities
Capital expenditures		(6,711)		(4,654)		(4,647)
Long-term, restricted and other investments		(3,416)		(1,276)		(1,041)
Distributions from equity investments in excess of cumulative earnings		785		1,151		763
Additions to intangible assets		(219)		(222)		(174)
Acquisitions		(13,472)		(954)		(828)
Proceeds from joint venture merger transaction (Note 13)		0		0		522
Proceeds from dispositions of equity investments		2,724		0		0
Net change in affiliate loans		2		(27)		135
Other		(56)		(61)		0
Net cash used in investing activities		(20,363)		(6,043)		(5,270)
Financing activities
Net change in short-term borrowings		129		(1,596)		481
Net change in commercial paper and credit facility draws		6,549		(8,157)		(1,333)
Debenture and term note issues, net of issue costs		9,546		15,377		7,547
Debenture and term note repayments		(6,633)		(4,819)		(4,198)
Sale of noncontrolling interest in subsidiary (Note 8)		0		0		1,092
Contributions from noncontrolling interests		4		11		13
Distributions to noncontrolling interests		(333)		(363)		(259)
Common shares issued, net of issue costs		2,485		4,450		3
Common shares repurchased		0		(125)		(151)
Preference share dividends		(387)		(352)		(338)
Common share dividends		(7,875)		(7,276)		(6,968)
Redemption of preference shares		0		0		(1,003)
Net change in affiliate loan		99		71		0
Other		(40)		(85)		(314)
Net cash provided by/(used in) financing activities		3,544		(2,864)		(5,428)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		234		(216)		55
Net change in cash and cash equivalents and restricted cash		(3,985)		5,078		587
Cash and cash equivalents and restricted cash at beginning of year		5,985	[1]	907	[1]	320
Cash and cash equivalents and restricted cash at end of year1	[1]	2,000		5,985		907
Supplementary cash flow information
Cash paid for income taxes		861		578		495
Cash paid for interest, net of amount capitalized		4,134		3,380		2,920
Property, plant and equipment and intangible assets non-cash accruals		$ 1,251		$ 813		$ 937
[1] 1 As at December 31, 2024, long-term restricted cash of $105 million (2023 and 2022 - nil) was included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position.

CONSOLIDATED STATEMENTS OF CA_2

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Cash Flows [Abstract]
Long-term restricted cash	$ 105	$ 0	$ 0

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Current assets
Cash and cash equivalents	$ 1,803	$ 5,901
Restricted cash	92	84
Trade receivables and unbilled revenues	6,920	4,410
Other current assets	2,770	2,440
Accounts receivable from affiliates	90	85
Inventory (Note 10)	1,488	1,479
Current assets	13,163	14,399
Property, plant and equipment, net (Note 11)	131,104	104,641
Long-term investments (Note 13)	20,691	16,793
Restricted long-term investments and cash (Note 23)	998	717
Deferred amounts and other assets	11,034	8,041
Intangible assets, net (Note 14)	4,587	3,537
Goodwill (Note 15)	36,600	31,848
Deferred income taxes (Note 24)	796	341
Total assets	218,973	180,317
Current liabilities
Short-term borrowings (Note 17)	529	400
Trade payables and accrued liabilities	7,060	4,308
Other current liabilities (Note 16)	7,241	5,659
Accounts payable to affiliates	22	26
Interest payable	1,231	958
Current portion of long-term debt (Note 17)	7,729	6,084
Current liabilities	23,812	17,435
Long-term debt (Note 17)	93,414	74,715
Other long-term liabilities	13,258	8,653
Deferred income taxes (Note 24)	19,596	15,031
Liabilities	150,080	115,834
Commitments and contingencies (Note 30)
Share capital
Preference shares	6,818	6,818
Common shares (2,178 and 2,125 outstanding at December 31, 2024 and 2023, respectively)	71,738	69,180
Additional paid-in capital	275	268
Deficit	(20,046)	(17,115)
Accumulated other comprehensive income (Note 22)	7,115	2,303
Total Enbridge Inc. shareholders’ equity	65,900	61,454
Noncontrolling interests (Note 19)	2,993	3,029
Equity	68,893	64,483
Total liabilities and equity	$ 218,973	$ 180,317

CONSOLIDATED STATEMENTS OF FI_2

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Dec. 31, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	2,178	2,125

BUSINESS OVERVIEW

BUSINESS OVERVIEW	12 Months Ended
	Dec. 31, 2024
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. Effective January 1, 2024, to better align how the chief operating decision maker (CODM) reviews operating performance and resource allocation across operating segments, we transferred our Canadian and United States (US) crude oil marketing businesses from the Energy Services segment to the Liquids Pipelines segment. As a result, the Energy Services segment ceased to exist and the remainder of the business, comprising natural gas and power marketing, is now reported in Eliminations and Other. Beginning in the first quarter of 2024, prior period comparable results for segmented information have been recast to reflect the change in reportable segments. This segment reporting change does not have an impact on our consolidated results. Enbridge is a publicly traded energy transportation and distribution company. We conduct our business through four business segments: Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation. 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 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. Effective January 1, 2024, our Canadian and US crude oil marketing businesses are included in this segment. These businesses provide energy marketing services to customers and undertake physical commodity marketing activity and logistical services to manage our volume commitments on various pipeline systems. GAS TRANSMISSION Gas Transmission 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. On January 2, 2024, we acquired six Morrow Renewables operating landfill gas-to-RNG production facilities (Tomorrow RNG) located in Texas and Arkansas which are a component of Other within the Gas Transmission segment (Note 8) . We also sold our interests in the Alliance Pipeline and Aux Sable (including a 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and a 50.0% interest in Aux Sable Canada LP), previously reported in the Gas Transmission segment, to Pembina Pipeline Corporation on April 1, 2024 (Note 13) . GAS DISTRIBUTION AND STORAGE Gas Distribution and Storage consists of our rate-regulated natural gas utility operations in Canada and the US. Enbridge Gas Inc. (Enbridge Gas Ontario) serves residential, commercial and industrial customers across Ontario. In 2024, we acquired three US natural gas utilities, The East Ohio Gas Company (EOG), Questar Gas Company (Questar) and its related Wexpro companies (Wexpro), and Public Service Company of North Carolina, Incorporated (PSNC), which make up our US gas utilities (Note 8) . This business segment also includes natural gas distribution activities in Québec. RENEWABLE POWER GENERATION Renewable Power Generation consists primarily of investments in wind and solar assets, as well as equity interests in geothermal power and power 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) . 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. Effective January 1, 2024, our natural gas and power marketing businesses are also included in Eliminations and Other. Enbridge's CODM is the President and Chief Executive Officer. The CODM uses earnings before interest, income taxes and depreciation and amortization (EBITDA), disaggregated by line of business, to assess segment performance and to set targets predominantly in the annual and long-term budgeting and forecasting process. Budget-to-actual and actual-to-actual variances in EBITDA are considered when making decisions about the allocation of resources to the segments and to meet our strategic priorities. Refer to Note 5 - Segmented Information for a reconciliation of EBITDA to earnings before income taxes.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2024
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 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 British Columbia (BC) Energy Regulator, the Ontario Energy Board (OEB), the Québec Régie de l’énergie, the Public Utilities Commission of Ohio (Ohio Commission), the North Carolina Utilities Commission (North Carolina Commission), the Utah Public Service Commission (Utah Commission), the Wyoming Public Service Commission (Wyoming Commission), and the Idaho Public Utilities Commission (Idaho Commission). 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 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. We believe that the recovery of our regulatory assets as at December 31, 2024 is probable over the periods described in Note 7 - Regulatory Matters . During the fourth quarter of 2023, Southern Lights Pipeline completed an open season to negotiate new transportation service agreements. We did not renew the agreements under a cost-of-service toll methodology, therefore Southern Lights Pipeline was 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 in 2023. We collect and set aside funds to cover future pipeline abandonment costs for all CER-regulated pipelines in accordance with the Land Matters Consultation Initiative (LMCI) to fund future pipeline decommissioning costs in the state of Minnesota and to satisfy retirement obligations as Wexpro properties are abandoned. The funds collected are held in trusts in accordance with applicable regulations. The funds collected from customers are reported within Operating revenues in the Consolidated Statements of Earnings and Restricted long-term investments and cash in the Consolidated Statements of Financial Position. Concurrently, for LMCI, 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 portion 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, 2024, 2023 and 2022, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $97 million, $210 million and $238 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 generally 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. Certain of our US gas utilities have a revenue decoupling mechanism, referred to as a Customer Usage Tracker (CUT) or Conservation Enabling Tariff (CET), which allows for the collection of an allowed monthly revenue per customer and to promote energy conservation. Under the mechanism, non-gas revenues are decoupled from the temperature-adjusted usage per customer. The difference between actual revenue and the allowed monthly revenue per customer is recorded as a regulatory asset or liability and recovered from, or refunded to, customers through periodic rate adjustments. Amounts deferred under the CUT or CET arise due to specific arrangements with the regulators rather than customers and represent alternative revenue programs. Revenue from alternative revenue programs is recorded within Operating revenues in the Consolidated Statements of Earnings in the month the related adjustments are deferred and is presented as Other revenues not from contracts with customers when disaggregated in Note 4 - Revenue . Our crude oil, natural gas and power marketing businesses enter 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, 2024, 2023 and 2022. DERIVATIVE INSTRUMENTS AND HEDGING Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to mitigate 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 and interest rates. 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 may use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates and interest rates. 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 and Financing 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 AND CASH Long-term investments and cash that are restricted as to withdrawal or usage, for the purposes of funding pipeline abandonment in accordance with the CER's LMCI, to cover future pipeline decommissioning costs in the state of Minnesota, and to satisfy retirement obligations as Wexpro properties are abandoned, are presented as Restricted long-term investments and cash in the Consolidated Statements of Financial Position. 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. 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. 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 $119 million and $100 million as at December 31, 2024 and 2023, 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 businesses in our Gas Distribution and Storage and Gas Transmission segments, crude oil and natural gas held by our crude oil and natural gas marketing businesses, and materials and supplies. Natural gas held in storage by our Gas Distribution and Storage businesses is recorded at the prices approved by the regulators in the determination of distribution rates. The actual price of gas purchased may differ from the regulator 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 regulators. Commodity inventory held by our crude oil and natural gas marketing businesses is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, commodity 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 life of the asset commencing when it 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 generally not reflected in earnings but are booked as an adjustment to accumulated depreciation. The successful efforts method of accounting is used for cost-of-service reserves developed and produced by Wexpro for gas utility affiliate, Questar. Cost-of-service reserves are properties for which the operations and return on investment are subject to the Wexpro Agreements. Under the successful efforts method, Wexpro capitalizes the costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, and purchasing related support equipment and facilities. Geological and geophysical studies are expensed as incurred. Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved natural gas and crude oil reserves. 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 (Note 7) , overfunded defined benefit pension and OPEB plan assets (Note 25) , operating lease ROU assets (Note 26) and long-term gross derivative asset balances (Note 23) . INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, customer relationships and biogas rights agreements. 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. Biogas rights agreements are long-term gas supply agreements with landfill owners of our landfill gas-to-RNG production facilities 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. 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. 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 trend

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2024
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, 2024. ADOPTION OF NEW ACCOUNTING STANDARDS Segment Reporting Effective January 1, 2024, with interim disclosure requirements effective after January 1, 2025, we adopted Accounting Standards Update (ASU) 2023-07 on a retrospective basis beginning on January 1, 2022. The new standard 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 ASU requires entities to disclose the title and position of the individual or the name of the group or committee identified as the CODM. The adoption of this ASU did not have a material impact on our consolidated financial statements. FUTURE ACCOUNTING POLICY CHANGES 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 the presentation of Note 24 - Income Taxes to our consolidated financial statements. Disaggregation of Income Statement Expenses ASU 2024-03 was issued in November 2024 to improve financial reporting by requiring entities to disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. The ASU requires entities to disclose 1) the amounts of (a) purchases of inventory, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, (e) depreciation, depletion and amortization recognized as part of oil and gas producing activities, (f) expense reimbursements included in a relevant expense caption, and (g) selling expenses, and 2) a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. ASU 2024-03 is effective January 1, 2027, with interim period disclosure requirements effective after January 1, 2028 and can be applied either prospectively or retrospectively. We are currently assessing the impact of the new standard on our annual disclosures for the year ending December 31, 2027 and on our interim disclosures beginning in 2028.

REVENUE

REVENUE	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE Change in Revenue Classification To better align the classification of revenues resulting from our acquisitions of the US gas utilities (Note 8) , we have made adjustments to Gas distribution sales and Transportation and other services revenues. Revenues generated from customers who procure their own gas but use our distribution system for delivery to the end use location have been reclassified to Gas distribution sales revenue from Transportation and other services revenue on the Consolidated Statements of Earnings and reclassified to Gas distribution sales from Transportation revenue in the Revenue from Contracts with Customers tables below. Our prior period comparable results have been recast to reflect the change in revenue classification. This change does not have an impact on our Total operating revenues. REVENUE FROM CONTRACTS WITH CUSTOMERS Major Products and Services Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Eliminations and Other Consolidated Year ended December 31, 2024 (millions of Canadian dollars) Transportation revenue 11,958 5,279 284 — — 17,521 Storage and other revenue 255 573 509 — — 1,337 Gas distribution sales — — 6,734 — — 6,734 Electricity and transmission revenue — — — 189 — 189 Commodity sales — 158 — — — 158 Total revenue from contracts with customers 12,213 6,010 7,527 189 — 25,939 Commodity sales 25,689 99 — — 1,072 26,860 Other revenue 1,2 281 70 4 319 — 674 Intersegment revenue — 20 11 6 (37) — Total revenue 38,183 6,199 7,542 514 1,035 53,473 Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Eliminations and Other Consolidated Year ended December 31, 2023 (millions of Canadian dollars) Transportation revenue 3 11,875 5,302 212 — — 17,389 Storage and other revenue 257 461 355 — — 1,073 Gas distribution sales 3 — — 5,461 — — 5,461 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 17,494 — — — 1,470 18,964 Other revenue 1,2 257 72 (58) 215 — 486 Intersegment revenue (1) 2 6 3 (10) — Total revenue 29,882 5,854 5,976 477 1,460 43,649 Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Eliminations and Other Consolidated Year ended December 31, 2022 (millions of Canadian dollars) Transportation revenue 3 11,283 5,012 198 — — 16,493 Storage and other revenue 235 350 308 — — 893 Gas gathering and processing revenue — 22 — — — 22 Gas distribution sales 3 — — 6,227 — — 6,227 Electricity and transmission revenue — — — 281 — 281 Total revenue from contracts with customers 11,518 5,384 6,733 281 — 23,916 Commodity sales 25,740 — — — 3,410 29,150 Other revenue 1,2 (81) 39 (20) 305 — 243 Intersegment revenue (3) 3 16 (4) (12) — Total revenue 37,174 5,426 6,729 582 3,398 53,309 1 Includes realized and unrealized gains and losses $23 million and losses of $97 million and $431 million for the years ended December 31, 2024, 2023 and 2022, respectively. 2 Includes revenues from lease contracts. Refer to Note 26 - Leases . 3 These balances reflect a transfer from Transportation revenue to Gas distribution sales of $602 million and $584 million for the years ended December 31, 2023 and 2022, respectively. We disaggregate revenue into categories which represent our principal performance obligations within each business segment. These revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance. Contract Balances Contract Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at December 31, 2024 3,764 330 2,828 Balance as at December 31, 2023 2,802 400 2,591 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, 2024 included in contract liabilities at the beginning of the year is $372 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2024, were $532 million. Performance Obligations Segment Nature of Performance Obligation Liquids Pipelines • Transportation and storage of crude oil and natural gas liquids (NGL) Gas Transmission • Transportation, storage, gathering, compression and treating of natural gas • Transportation of crude oil and NGL • Sale of renewable natural gas and its attached environmental attributes 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, 2024 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 The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, that is expected to be recognized in the following periods: Total 1 year 2-5 years Thereafter (billions of Canadian dollars) Expected revenue 62.6 10.4 25.2 27.0 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. On March 4, 2024, the CER approved the negotiated Mainline tolling settlement. The new tolls are finalized and were in effect on an interim basis on July 1, 2023, and the overall agreement is retroactively effective as of July 1, 2021 through to the end of 2028. Recognition and Measurement of Revenue Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2024 (millions of Canadian dollars) Revenue from products transferred at a point in time — 158 137 — 295 Revenue from products and services transferred over time 1 12,213 5,852 7,390 189 25,644 Total revenue from contracts with customers 12,213 6,010 7,527 189 25,939 Liquids Pipelines Gas Transmission 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 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 1 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales. Performance Obligations Satisfied Over Time For arrangements involving the transportation and sale of petroleum products and natural gas where the transportation services or commodities are simultaneously received and consumed by the shipper or customer, we recognize revenue over time using an output method based on volumes of commodities delivered or transported. The measurement of the volumes transported or delivered corresponds directly to the benefits received by the shippers or customers during that period. Determination of Transaction Prices Prices for transportation and gas processing services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services, plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation. Prices for commodities sold are determined by reference to market price indices, plus or minus a negotiated differential and in certain cases a marketing fee. Prices for natural gas sold and distribution services provided by regulated natural gas distribution operations are prescribed by regulation.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION Year ended December 31, 2024 Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Total Reportable Segments (millions of Canadian dollars) Operating revenues 1 38,183 6,199 7,542 514 52,438 Commodity and gas distribution costs (25,283) (130) (2,501) 4 (27,910) Operating and administrative (4,495) (2,322) (2,276) (304) (9,397) Impairment of long-lived assets (2) (162) (3) (23) (190) Income from equity investments 1,051 812 3 455 2,321 Gain on disposition of equity investments (Note 13) — 1,063 — 28 1,091 Other income 77 196 104 59 436 Earnings before interest, income taxes and depreciation and amortization 9,531 5,656 2,869 733 18,789 Eliminations and Other (1,904) Depreciation and amortization (5,167) Interest expense (Note 17) (4,419) Earnings before income taxes 7,299 Year ended December 31, 2023 Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Total Reportable Segments (millions of Canadian dollars) Operating revenues 1 29,882 5,854 5,976 477 42,189 Commodity and gas distribution costs (17,106) (15) (2,871) (20) (20,012) Operating and administrative (4,659) (2,380) (1,285) (261) (8,585) Impairment of long-lived assets 2 145 — (281) (283) (419) Income from equity investments 1,007 688 2 140 1,837 Other income 114 117 51 96 378 Earnings before interest, income taxes and depreciation and amortization 9,383 4,264 1,592 149 15,388 Eliminations and Other 916 Depreciation and amortization (4,613) Interest expense (Note 17) (3,812) Earnings before income taxes 7,879 Year ended December 31, 2022 Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Total Reportable Segments (millions of Canadian dollars) Operating revenues 1 37,174 5,426 6,729 582 49,911 Commodity and gas distribution costs (25,495) — (3,693) (16) (29,204) Operating and administrative (4,318) (2,254) (1,289) (255) (8,116) Impairment of long-lived assets (258) — — (235) (493) Impairment of goodwill — (2,465) — — (2,465) Income from equity investments 785 1,133 1 141 2,060 Gain on joint venture merger transaction (Note 13) — 1,076 — — 1,076 Other income 53 210 79 45 387 Earnings before interest, income taxes and depreciation and amortization 7,941 3,126 1,827 262 13,156 Eliminations and Other (1,118) Depreciation and amortization (4,317) Interest expense (Note 17) (3,179) Earnings before income taxes 4,542 1 Refer to Note 4 - Revenue for a reconciliation of segment Operating revenues to the Consolidated Statements of Earnings. 2 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) . Capital Expenditures 1 Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Liquids Pipelines 1,157 1,158 1,418 Gas Transmission 2,571 1,944 1,690 Gas Distribution and Storage 2,386 1,451 1,499 Renewable Power Generation 661 100 50 Eliminations and Other 59 55 33 6,834 4,708 4,690 1 Includes the equity component of the AFUDC. Property, Plant and Equipment Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Liquids Pipelines 53,863 51,855 53,573 Gas Transmission 34,683 31,016 29,666 Gas Distribution and Storage 38,636 18,766 17,857 Renewable Power Generation 3,612 2,706 3,082 Eliminations and Other 310 298 282 131,104 104,641 104,460 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, 2024 2023 2022 (millions of Canadian dollars) Canada 22,001 23,781 27,498 US 31,472 19,868 25,811 53,473 43,649 53,309 1 Revenues are based on the country of origin of the product or service sold. Property, Plant and Equipment 1 December 31, 2024 2023 (millions of Canadian dollars) Canada 48,873 48,570 US 82,231 56,071 131,104 104,641 1 Amounts are based on the location where the assets are held.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	12 Months Ended
	Dec. 31, 2024
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. DILUTED The treasury stock method is used to determine the dilutive impact of stock options and share-settled RSUs. This method assumes any proceeds from the exercise of stock options and vesting of share-settled 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 common share are as follows: December 31, 2024 2023 2022 (number of shares in millions) Weighted average shares outstanding 2,155 2,056 2,025 Effect of dilutive options and RSUs 3 2 4 Diluted weighted average shares outstanding 2,158 2,058 2,029 For the years ended December 31, 2024, 2023 and 2022, 14.6 million, 19.3 million and 10.4 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $54.37, $54.42 and $56.49, respectively, were excluded from the diluted earnings per common share calculation.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2024
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 Mainline Tolling Settlement (MTS), governs the tolls paid for products shipped on its Mainline System, with the exception of Lines 8 and 9 which are tolled on a separate basis and was approved by the CER on March 4, 2024. The MTS has a seven-and-a-half year term through the end of 2028 and 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 $2.0 billion as at December 31, 2024 (2023 - $1.9 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. Southern Lights Pipeline In February 2024, we entered into fixed-toll agreements for a five GAS TRANSMISSION 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 2024-2025 settlement agreements, which stipulate an allowable return on equity (ROE) and the continuation and establishment of certain deferral and variance accounts. 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, which was approved on February 14, 2024, as filed. US Gas Transmission The majority 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 Ontario Enbridge Gas Ontario's distribution rates, commencing in 2024, were set by the OEB under a five-year Incentive Regulation (IR) framework. The framework included the establishment of 2024 base rates on a cost-of-service basis, while rates for 2025 through 2028 will be established using a price cap mechanism. The price cap mechanism will establish new rates each year through an annual base rate adjustment to expense an incremental $50 million of capitalized overheads as operating and maintenance costs; annual base rate escalation at inflation less a 0.28% productivity factor; annual updates for certain costs to be passed through to customers; and, where applicable, it will provide for the recovery of material unexpected events and discrete incremental capital investments beyond those that can be funded through base rates. The price cap mechanism includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas Ontario to share equally with customers any earnings in excess of 100 basis points over the allowed ROE, and share 90% of earnings in excess of 300 basis points over the allowed ROE. Enbridge Gas Ohio Enbridge Gas Ohio is subject to the jurisdiction of the Ohio Commission with its natural gas sales and transportation and storage services being provided under rate schedules approved by the regulatory commission. Enbridge Gas Ohio uses a straight-fixed-variable rate design, where majority of operating costs are recovered through a monthly charge, as established in a 2008 rate case settlement. In October 2023, Enbridge Gas Ohio filed for a non-fuel base rate increase of $212 million projected to be effective January 2025. This base rate increase aims to recover investments in distribution infrastructure for the benefit of Ohio customers. The proposed rates would provide an ROE of 10.40% compared to the currently authorized 10.38%. Additionally, Enbridge Gas Ohio also requested approval for an alternative rate plan for the continuation and modification of the Pipeline Infrastructure Replacement (PIR) and the Capital Expenditure Program (CEP). On December 18, 2024, Enbridge Gas Ohio filed a Notice of Intent to Modify Filed Positions. The Notice of Intent indicated a willingness to accept a reduced annual revenue requirement increase (from $212 million to $60 million) and, if the reduced position were adopted, to forgo filing a new base rate case until October 31, 2027. The hearing began on January 13, 2025, and remains underway. The PIR program aims to replace 25% of the pipeline system. In April 2022, the Ohio Commission extended the PIR program through 2026. The CEP allows Enbridge Gas Ohio to defer depreciation expense, property tax expense and carrying costs at the debt rate of 6.5% on capital investments not covered by its PIR program. In September 2024, the Ohio Commission approved adjustments to CEP cost recovery rates for 2023 costs. Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho are regulated by the Utah Commission, the Wyoming Commission, and the Idaho Commission. For rate oversight of Enbridge Gas Idaho's operations in a small area of southeastern Idaho, the Idaho Commission has contracted with Utah Commission. Both Utah and Wyoming Commissions allow for the recovery of gas costs through a balancing-account mechanism. Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho use several mechanisms to manage costs and promote efficiency. They recover gas costs through a balance-account mechanism that adjusts rates periodically to reflect changes in natural gas prices. The Infrastructure Replacement Program allows Enbridge Gas Utah, Enbridge Gas Wyoming, and Enbridge Gas Idaho to earn a return on capital expenditures for infrastructure replacement. The CET decouples non-gas revenues from customer usage, enabling the collection of allowed revenue per customer and encourages energy conservation. The Energy Efficiency Program promotes natural gas conservation through advertising, rebates, and home energy plans. These costs are recovered through periodic rate adjustments. The Utah Commission approved the construction of natural gas infrastructure to extend services to rural Utah, including 30 miles of intermediate high-pressure pipeline and up to 500 service lines. Recent approvals also include adjustments in the rural expansion rate tracker. Enbridge Gas North Carolina Enbridge Gas North Carolina is subject to regulation of rates and other aspects of its business by the North Carolina Commission. Base rates for Enbridge Gas North Carolina are designed primarily based on rate design methodology in which the majority of operating costs are recovered through volumetric charges. The North Carolina Commission authorized Enbridge Gas North Carolina to use a tracker mechanism to recover costs related to pipeline integrity and safety requirements that are not included in current base rates. Enbridge Gas North Carolina uses several mechanisms to adjust rates and recover costs. CUT allows for rate adjustments based on changes in customer usage patterns. Rider D enables the recovery of gas purchases from customers, with rates periodically adjusted to reflect market price changes. Rider F facilitates the recovery of costs associated with energy efficiency measures and programs. 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, 2024 2023 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Purchase gas variance 74 15 2025 Under-recovery of fuel costs 4 75 2025 Deferred projects costs 1 90 — 2025 Other current regulatory assets 304 380 2025 Total current regulatory assets 2 (Note 9) 472 470 Long-term regulatory assets Deferred income taxes 3 4,698 4,456 Various Deferred projects costs 1 1,045 — Various Long-term debt 4 318 348 2032-2046 Negative salvage 5 136 180 Various Demand-side management costs 237 54 Various Pension plan receivable 6 266 1 Various Other long-term regulatory assets 447 198 Various Total long-term regulatory assets 2 7,147 5,237 Total regulatory assets 7,619 5,707 Current regulatory liabilities Purchase gas variance 292 31 2025 Regulatory liability related to US income taxes 7 44 — 2025 Other current regulatory liabilities 280 276 2025 Total current regulatory liabilities 8 (Note 16) 616 307 Long-term regulatory liabilities Future removal and site restoration reserves 9 2,964 1,693 Various Regulatory liability related to US income taxes 7 2,021 854 Various Pipeline future abandonment costs (Note 23) 826 745 Various Pension plan payable 6 59 143 Various Other long-term regulatory liabilities 242 86 Various Total long-term regulatory liabilities 8 6,112 3,521 Total regulatory liabilities 6,728 3,828 1 Represents the amounts anticipated to be collected from customers in East Ohio’s service areas for rider projects, including CEP, PIR and costs related to the Pipeline Safety Management Program. The recovery periods for these expenditures vary according to the stipulations outlined in the respective riders. For Enbridge Gas North Carolina, these amounts relate to pipeline integrity management which represent operating costs incurred to comply with federal regulatory requirements related to natural gas pipelines and have been deferred pending future approval of rate recovery. 2 Current regulatory assets are included in Other current assets, while long-term regulatory assets are included in Deferred amounts and other assets. 3 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, 2024 is net of regulatory deferred tax write-offs. 4 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. 5 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. 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 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 for our US Gas Transmission pipelines and by the respective state utility commission for each US Gas Distribution franchise. 8 Current regulatory liabilities are included in Other current liabilities, while long-term regulatory liabilities are included in Other long-term liabilities. 9 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the respective regulatory authorities, 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.

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITION BUSINESS COMBINATIONS We accounted for each of the acquisitions discussed below using the acquisition method as prescribed by ASC 805 Business Combinations . In accordance with valuation methodologies described in ASC 820 Fair Value Measurement , acquired assets and assumed liabilities are recorded at their estimated fair values as at the date of acquisition. The fair values of regulatory assets and liabilities, which are subject to rate-setting and cost recovery mechanisms under ASC 980 Regulated Operations , are equal to their carrying values at acquisition. 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 at acquisition. Public Service Company of North Carolina, Incorporated On September 30, 2024, through a wholly-owned US subsidiary, we acquired all of the membership interests of Fall North Carolina Holdco LLC, which owns 100% of PSNC, for cash consideration of $2.7 billion (US$2.0 billion) (the PSNC Acquisition). PSNC is a public utility primarily engaged in the purchase, sale, transportation and distribution of natural gas to residential, commercial and industrial customers in North Carolina. PSNC operates under rates approved by the North Carolina Commission. Subsequent to its acquisition, PSNC conducts business as Enbridge Gas North Carolina. The following table summarizes the estimated preliminary fair values that were assigned to the net assets of PSNC: September 30, 2024 1 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 303 Property, plant and equipment (b) 4,147 Long-term assets (c) 189 Current liabilities 277 Long-term debt (d) 1,529 Other long-term liabilities (e) 653 Deferred income tax liabilities 365 Goodwill (f) 895 Purchase price: Cash 2,710 1 In the fourth quarter of 2024, immaterial adjustments were made to the PSNC Acquisition purchase price allocation. a) Current assets consist primarily of cash, trade and other accounts receivable, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $70 million due to the short period to maturity. A provision of $2 million for expected credit loss associated with accounts receivable has been recorded. b) PSNC's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, distribution and storage assets. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value. c) Long-term assets consist primarily of $114 million of regulatory assets expected to be recovered from customers in future periods through rates and equity interests in a liquefied natural gas (LNG) storage facility in North Carolina and in an intrastate natural gas pipeline. d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $156 million with no corresponding regulatory offset. e) Other long-term liabilities consist primarily of regulatory liabilities expected to be refunded to customers in future periods through rates. f) Goodwill is primarily attributable to the existing assembled assets and workforce of PSNC that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides a platform for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible. Upon completion of the PSNC Acquisition, we began consolidating PSNC. For the period beginning September 30, 2024 through to December 31, 2024, PSNC generated $284 million of operating revenues and $50 million of earnings attributable to common shareholders. Our supplemental pro forma consolidated financial information for the years ended December 31, 2024 and 2023, including the results of operations for PSNC as if the PSNC Acquisition had been completed on January 1, 2023, is as follows: Year ended December 31, 2024 2023 (unaudited; millions of Canadian dollars) Operating revenues 54,116 44,614 Earnings attributable to common shareholders 1 5,149 5,944 1 Includes adjustment for pro forma interest expense on debt financing for the PSNC Acquisition of $48 million (after-tax of $37 million) for the year ended December 31, 2023. Questar Gas Company On May 31, 2024, through a wholly-owned US subsidiary, we acquired all of the membership interests of Fall West Holdco LLC which owns 100% of Questar and Wexpro for cash consideration of $4.1 billion (US$3.0 billion) (the Questar Acquisition). Questar is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Utah, southwestern Wyoming and southeastern Idaho. The Utah Commission, the Wyoming Commission and the Idaho Commission have granted Questar the necessary regulatory approvals to serve these areas. Wexpro develops and produces cost-of-service gas reserves for Questar and operates under agreements with the states of Utah and Wyoming. Subsequent to its acquisition, Questar conducts business as Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho in those respective states. The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Questar and Wexpro: May 31, 2024 1 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 380 Property, plant and equipment (b) 6,013 Long-term assets (c) 163 Current liabilities 416 Long-term debt (d) 1,343 Other long-term liabilities (e) 919 Deferred income tax liabilities 527 Goodwill (f) 793 Purchase price: Cash 4,144 1 In the fourth quarter of 2024, immaterial adjustments were made to the Questar Acquisition purchase price allocation. a) Current assets consist primarily of cash, trade and other accounts receivable and inventory. The fair value of trade receivables from customers approximates their carrying value of $202 million due to the short period to maturity. A provision of $9 million for expected credit loss associated with accounts receivable has been recorded. b) Questar's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, distribution and storage assets. Wexpro's property, plant and equipment consists of cost-of-service gas and oil properties developed and produced for Questar. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value. c) Long-term assets consist primarily of funds collected from Questar by Wexpro and held in trust to fund future AROs, as well as regulatory assets expected to be recovered from customers in future periods through rates. d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $301 million with no corresponding regulatory offset. e) Other long-term liabilities consist primarily of regulatory liabilities, expected to be refunded to customers in future periods through rates, as well as ARO. The fair value of the ARO liability was determined using a discounted cash flow approach. f) Goodwill is primarily attributable to the existing assembled assets and workforce of Questar and Wexpro that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides a platform for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible. Upon completion of the Questar Acquisition, we began consolidating Questar and Wexpro. For the period beginning May 31, 2024 through to December 31, 2024, Questar and Wexpro generated $755 million of operating revenues and $75 million of earnings attributable to common shareholders. Our supplemental pro forma consolidated financial information for the years ended December 31, 2024 and 2023, including the results of operations for Questar and Wexpro as if the Questar Acquisition had been completed on January 1, 2023, is as follows: Year ended December 31, 2024 2023 (unaudited; millions of Canadian dollars) Operating revenues 54,698 45,918 Earnings attributable to common shareholders 1 5,193 6,005 1 Includes adjustment for pro forma interest expense on debt financing for the Questar Acquisition of $70 million (after-tax of $53 million) for the year ended December 31, 2023. The East Ohio Gas Company On March 6, 2024, through a wholly-owned US subsidiary, we acquired all of the outstanding shares of capital stock of EOG for cash consideration of $5.8 billion (US$4.3 billion) (the EOG Acquisition). EOG is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Ohio and is regulated by the Ohio Commission. Subsequent to its acquisition, EOG conducts business as Enbridge Gas Ohio. The following table summarizes the estimated preliminary fair values that were assigned to the net assets of EOG: March 6, 2024 1 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 493 Property, plant and equipment (b) 7,276 Long-term assets (c) 1,689 Current liabilities 551 Long-term debt (d) 2,612 Other long-term liabilities (e) 1,001 Deferred income tax liabilities 1,045 Goodwill (f) 1,603 Purchase price: Cash 5,852 1 In the fourth quarter of 2024, immaterial adjustments were made to the EOG Acquisition purchase price allocation. a) Current assets consist primarily of trade and other accounts receivable, prepaid expenses, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $379 million due to the short period to maturity. A provision of $3 million for expected credit loss associated with accounts receivable has been recorded. b) EOG's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, gathering, distribution and storage assets. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value. c) Long-term assets consist primarily of overfunded pension plan assets of $367 million and $1.2 billion of regulatory assets expected to be recovered from customers in future periods through rates. Pension plan assets attributable to the workforce acquired from EOG were transferred in cash to an Enbridge-sponsored pension plan based on their fair value as at March 6, 2024. The fair value of plan assets was determined using unadjusted quoted market prices for identical investments. d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $478 million with no corresponding regulatory offset. e) Other long-term liabilities consist primarily of regulatory liabilities expected to be refunded to customers in future periods through rates. f) Goodwill is primarily attributable to the existing assembled assets and workforce of EOG that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides a platform for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible. Upon completion of the EOG Acquisition, we began consolidating EOG. For the period beginning March 6, 2024 through to December 31, 2024, EOG generated $1.2 billion of operating revenues and $190 million of earnings attributable to common shareholders. Our supplemental pro forma consolidated financial information for the years ended December 31, 2024 and 2023, including the results of operations for EOG as if the EOG Acquisition had been completed on January 1, 2023, is as follows: Year ended December 31, 2024 2023 (unaudited; millions of Canadian dollars) Operating revenues 53,788 45,058 Earnings attributable to common shareholders 1 5,130 5,961 1 Includes adjustment for pro forma interest expense on debt financing for the EOG Acquisition of $100 million (after-tax of $77 million) for the year ended December 31, 2023. The purchase price allocations for the PSNC Acquisition, Questar Acquisition and EOG Acquisition (together, the Acquisitions) were prepared on a preliminary basis and are subject to change as additional information becomes available concerning the fair values of the ARO and regulatory balances and their tax bases. Any adjustments to the purchase price allocations will be made as soon as practicable, but no later than one year from the date of each acquisition. The Acquisitions further diversify, and are complementary to, our existing gas distribution operations. Acquisition of RNG Facilities On January 2, 2024, through a wholly-owned US subsidiary, we acquired six Morrow Renewables operating landfill gas-to-RNG production facilities (Tomorrow RNG) located in Texas and Arkansas for total consideration of $1.3 billion (US$1.0 billion), of which $584 million (US$439 million) was paid at close and an additional deferred consideration is payable within two years with a fair value of $757 million (US$568 million) (the RNG Facilities Acquisition). The acquired assets align with and advance our lower-carbon strategy. The following table summarizes the estimated fair values that were assigned to the net assets of Tomorrow RNG: January 2, 2024 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 31 Intangible assets (a) 925 Property, plant and equipment (b) 174 Current liabilities 5 Goodwill (c) 223 Purchase price: Cash 584 Deferred consideration (d): Current portion of long-term debt 550 Long-term debt 207 Other adjustments 7 1,348 a) Intangible assets consist of long-term gas supply agreements with the respective facility's landfill owner. Fair value was determined using an income-based approach, specifically the multi-period excess earnings method, by estimating the present value of the after-tax cash flows attributable to the gas rights. The intangible assets will be amortized on a straight-line basis over the term of the respective agreement, inclusive of extension options, which range from 13 to 42 years (approximately nine years to the next extension period on a weighted-average basis). b) Tomorrow RNG's property, plant and equipment constitutes specialized landfill gas plant and equipment which collects gas produced by waste decomposition, treats and compresses the gas to pipeline specifications. The direct method of replacement cost was used to determine the majority of the fair value of property, plant and equipment. Adjustments were then applied for estimated physical deterioration. c) Goodwill is primarily attributable to expected future returns from a portfolio of both operating and scalable RNG assets, furthering the diversity of our renewable projects portfolio and accelerating progress toward our energy transition goals. The goodwill balance recognized has been assigned to our Gas Transmission segment and is tax deductible over 15 years. d) We entered into six non-interest bearing promissory notes due to Morrow Renewables, the total value of which represents deferred payments of $808 million (US$606 million) due within two years. The first and second payments are due on January 2, 2025 and December 31, 2025, respectively. The $757 million (US$568 million) recognized in the purchase price represents the fair value of deferred consideration at the date of acquisition using the imputed interest rate method over the terms of the notes. Upon completion of the RNG Facilities Acquisition, we began consolidating Tomorrow RNG. For the period beginning January 2, 2024 through to December 31, 2024, operating revenues and earnings attributable to common shareholders generated by Tomorrow RNG were immaterial. The impact to our supplemental pro forma consolidated operating revenues and earnings attributable to common shareholders for the years ended December 31, 2024 and 2023, as if the RNG Facilities Acquisition had been completed on January 1, 2023, was also immaterial. 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 (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 LNG exports. The following table summarizes the estimated 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 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. 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. 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 $72 million (US$53 million) to TGE's former common unit holders if performance milestones were met on certain projects. The $49 million (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. ASSET ACQUISITION 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 segment. DISPOSITION 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. No gain or loss was recognized on the sale and a noncontrolling interest was recorded in our Consolidated Statements of Financial Position beginning in 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
	Dec. 31, 2024
Receivables [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS December 31, 2024 2023 (millions of Canadian dollars) Derivative assets (Note 23) 557 623 Regulatory assets (Note 7) 472 470 Gas imbalances 517 209 Income taxes receivable 375 347 Other 849 791 2,770 2,440

INVENTORY

INVENTORY	12 Months Ended
	Dec. 31, 2024
Inventory Disclosure [Abstract]
INVENTORY	INVENTORY December 31, 2024 2023 (millions of Canadian dollars) Natural gas 811 938 Crude oil 479 413 Other 198 128 1,488 1,479

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Weighted Average December 31, Depreciation Rate 2024 2023 (millions of Canadian dollars) Pipelines 2.9 % 73,633 66,698 Facilities and equipment 3.2 % 43,439 37,634 Land and right-of-way 1 2.8 % 4,181 3,600 Gas mains, services and other 3.0 % 26,925 15,346 Storage 2.6 % 6,455 4,929 Wind turbines, solar panels and other 3.9 % 4,798 4,511 Other 8.6 % 3,987 1,652 Under construction — % 5,648 2,829 Total property, plant and equipment 2 169,066 137,199 Total accumulated depreciation 2 (37,962) (32,558) Property, plant and equipment, net 131,104 104,641 1 The measurement of weighted average depreciation rate excludes non-depreciable assets. 2 As at December 31, 2024, the cost and accumulated depreciation of leased assets accounted for as lessor operating leases was $5.3 billion and $2.3 billion, respectively (December 31, 2023 - $5.1 billion and $2.1 billion, respectively). Depreciation expense for the years ended December 31, 2024, 2023 and 2022 was $4.6 billion, $4.0 billion and $3.8 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
	Dec. 31, 2024
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 provides us with 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. 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 only 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, 2024 2023 (millions of Canadian dollars) Assets Current assets Cash and cash equivalents 448 442 Restricted cash 11 9 Trade receivables and unbilled revenues 138 144 Other current assets 5 8 Accounts receivable from affiliates 13 5 Inventory 13 11 628 619 Property, plant and equipment, net 6,934 7,105 Long-term investments 20 14 Restricted long-term investments and cash 141 106 Deferred amounts and other assets 145 148 Intangible assets, net 77 84 7,945 8,076 Liabilities Current liabilities Trade payables and accrued liabilities 108 83 Other current liabilities 124 145 Accounts payable to affiliates 22 4 254 232 Long-term debt — 1 Other long-term liabilities 1,133 971 Deferred income taxes 6 5 1,393 1,209 6,552 6,867 We do not have obligations to provide additional financial support to any of our consolidated VIEs. UNCONSOLIDATED VARIABLE INTEREST ENTITIES We also hold interests in unconsolidated 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 the entity's economic performance. These interests include investments in limited partnerships that are assessed to be VIEs due to the limited partners not having substantive participating rights or kick-out rights. The power to direct the activities of a majority of these unconsolidated 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, 2024 and 2023 are as follows: Carrying Maximum December 31, 2024 the VIE Loss (millions of Canadian dollars) Rampion Offshore Wind Limited 1 387 490 Vector Pipeline 2 193 314 Woodfibre LNG Limited Partnership 3 1,275 3,153 Whistler Parent JV 4 1,102 1,425 Other 3 168 501 3,125 5,883 Carrying Maximum December 31, 2023 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 5 105 130 Rampion Offshore Wind Limited 1 391 452 Vector Pipeline 2 191 320 Woodfibre LNG Limited Partnership 3 778 2,854 Fox Squirrel Solar LLC 6 312 661 Other 3 132 230 1,909 4,647 1 As at December 31, 2024 and 2023, our maximum exposure to loss includes parental guarantees that have been committed in project contracts in which we would be liable for in the event of default by the VIE and the carrying value of an affiliate dividend receivable of $73 million and nil, respectively. 2 Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US. As at December 31, 2024 and 2023, our maximum exposure to loss includes the carrying value of outstanding affiliate loans receivable of $16 million and $24 million, respectively, and our share of the VIE's available credit facility for $105 million. 3 As at December 31, 2024 and 2023, our maximum exposure to loss includes parental guarantees and funding obligations that have been committed in connection with the projects for which we would be liable in the event of default by the VIE(s). 4 In May 2024, Enbridge formed a joint venture (the Whistler Parent JV) in which we hold a 19.0% interest. Refer to Note 13 - Long-Term Investments . As at December 31, 2024, our maximum exposure to loss includes funding obligations that have been committed in project contracts in which we would be liable for in the event of default by the VIE. 5 In April 2024, Enbridge sold its interest in Aux Sable Liquid Products L.P. Refer to Note 13 - Long-Term Investments . As at December 31, 2023, our maximum exposure to loss included a guarantee by us for our respective share of the VIE's borrowing on a bank credit facility. 6 In November 2023, Enbridge acquired a 50.0% interest in Fox Squirrel Solar LLC. Refer to Note 13 - Long-Term Investments . As at December 31, 2024, Fox Squirrel Solar LLC no longer met the requirements of a VIE as a result of a VIE reconsideration event. As at December 31, 2023, our maximum exposure to loss included parental guarantees that had been committed in project contracts in which we would be liable for in the event of default by the VIE. We do not have an obligation to and did not provide any additional financial support to our unconsolidated VIEs during the years ended December 31, 2024 and 2023.

LONG-TERM INVESTMENTS

LONG-TERM INVESTMENTS	12 Months Ended
	Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
LONG-TERM INVESTMENTS	LONG-TERM INVESTMENTS December 31, Ownership 2024 2023 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines Cactus II Pipeline LLC 30.0 % 651 618 DCP Midstream, LLC (Class B Units) 1 90.0 % 1,554 1,486 Illinois Extension Pipeline Company, L.L.C. 65.0 % 608 584 MarEn Bakken Company LLC 2 75.0 % 2,296 1,819 Seaway Crude Holdings LLC 50.0 % 2,820 2,661 Other 30.0 % - 43.8 % 96 84 Gas Transmission Alliance Pipeline 3,5 50.0 % — 359 Aux Sable 4,5 42.7 % - 50.0 % — 229 DCP Midstream, LLC (Class A Units) 6 23.4 % 480 367 Delaware Basin Residue, LLC 7 15.0 % 319 — Gulfstream Natural Gas System, L.L.C. 50.0 % 1,316 1,224 NEXUS Gas Transmission, LLC 50.0 % 1,301 1,220 Sabal Trail Transmission, LLC 50.0 % 1,565 1,467 Southeast Supply Header, LLC 50.0 % 355 80 Steckman Ridge, LP 50.0 % 101 87 Vector Pipeline 60.0 % 193 191 Whistler Parent JV 8 19.0 % 1,102 — Woodfibre LNG Limited Partnership 30.0 % 1,275 777 Offshore - various joint ventures 22.0 % - 74.3 % 260 217 Other 21.3 % - 45.0 % 49 — Gas Distribution and Storage Other 17.0 % - 50.0 % 67 22 Renewable Power Generation East-West Tie Limited Partnership 24.1 % 106 132 EIH S.à r.l. 9 51.0 % 89 52 Fox Squirrel Solar LLC 50.0 % 783 312 Hohe See and Albatros Offshore Wind Facilities 49.9 % 1,606 1,701 Rampion Offshore Wind Limited 24.9 % 387 391 Other 16.4 % - 50.0 % 93 110 OTHER LONG-TERM INVESTMENTS Gas Transmission Ara Divert HoldCo, Inc. 116 106 Other 23 22 Gas Distribution and Storage Other 27 24 Renewable Power Generation Other 21 21 Eliminations and Other Other 10 1,032 430 20,691 16,793 1 We own 90.0% of the Class B units of DCP Midstream, LLC. This class of units represents DCP Midstream, LLC's 65.0% interest in Gray Oak Pipeline, LLC (Gray Oak), resulting in a 58.5% interest in Gray Oak through DCP Midstream, LLC. 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%. 2 MarEn Bakken Company LLC 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. 3 Includes Alliance Pipeline Limited Partnership in Canada and Alliance Pipeline L.P. in the US. 4 Includes Aux Sable Canada LP in Canada and Aux Sable Liquid Products L.P. and Aux Sable Midstream LLC in the US. 5 On April 1, 2024, we closed the sale of our 50.0% equity interest in the Alliance Pipeline and our interest in Aux Sable to Pembina Pipeline Corporation for $3.1 billion, including $0.3 billion of non-recourse debt. 6 We own 23.4% of the Class A units of DCP Midstream, LLC. These units represent DCP Midstream, LLC's 56.5% interest in DCP Midstream, LP (DCP), resulting in a 13.2% effective interest in DCP by us. 7 On October 31, 2024, we acquired an effective 15.0% interest in Delaware Basin Residue, LLC (DBR) for consideration of $303 million (US$220 million). DBR owns transportation and storage assets in West Texas, serving as the primary supply point for the Whistler Pipeline. 8 On May 29, 2024, we formed a joint venture with WhiteWater/I Squared Capital and MPLX LP. We hold a 19.0% interest in the joint venture, which owns a 100% interest in the Rio Bravo Pipeline project. Additionally, we have a 25.0% special interest in the Rio Bravo Pipeline project, resulting in a 39.3% effective interest in the Rio Bravo Pipeline project by us. 9 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%). 10 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, 2024, this basis difference was $3.7 billion (2023 - $3.5 billion), of which $1.7 billion (2023 - $1.7 billion) was amortizable. For the years ended December 31, 2024, 2023 and 2022, distributions received from equity investments were $2.9 billion, $3.1 billion and $2.6 billion, respectively. Summarized combined financial information of our unconsolidated equity investments (presented at 100%) is as follows: Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Operating revenues 20,657 22,586 30,026 Operating expenses 14,692 17,111 23,835 Earnings 5,177 4,818 5,123 Earnings attributable to Enbridge 2,304 1,816 2,056 December 31, 2024 2023 (millions of Canadian dollars) Current assets 8,611 5,842 Non-current assets 69,381 61,141 Current liabilities 7,240 6,194 Non-current liabilities 27,491 23,957 Noncontrolling interests 4,979 4,124 DISPOSITION Disposition of Alliance Pipeline and Aux Sable Interests On April 1, 2024, we closed the sale of our 50.0% interest in the Alliance Pipeline, our interest in Aux Sable and our interest in NRGreen Power Limited Partnership (NRGreen) to Pembina Pipeline Corporation for $3.1 billion, including $327 million of non-recourse debt. A gain on disposal of $1.1 billion before tax, which is net of $1.0 billion of the goodwill from our Gas Transmission segment allocated to the disposal group, is included in Gain on disposition of equity investments in the Consolidated Statements of Earnings for the year ended December 31, 2024. Our equity investments in the Alliance Pipeline and Aux Sable were previously included in our Gas Transmission segment. Our equity investment in NRGreen was previously included in our Renewable Power Generation segment. OTHER EQUITY INVESTMENT TRANSACTIONS Joint Venture with WhiteWater/I Squared and MPLX On May 29, 2024, we formed a joint venture (the Whistler Parent JV) with WhiteWater/I Squared Capital (WhiteWater/I Squared) and MPLX LP (MPLX) that will develop, construct, own and operate natural gas pipeline and storage assets connecting Permian Basin natural gas supply to growing LNG and other US Gulf Coast demand. The Whistler Parent JV is owned by WhiteWater/I Squared (50.6%), MPLX (30.4%) and Enbridge (19.0%) and is accounted for as an equity method investment. In connection with the formation of the Whistler Parent JV, we contributed our 100% interest in the Rio Bravo Pipeline project and $487 million (US$357 million) of cash to the Whistler Parent JV. In addition to our 19.0% equity interest in the Whistler Parent JV, we received a special equity interest in the Whistler Parent JV which provides for a 25.0% economic interest in the Rio Bravo Pipeline project. This interest is subject to certain redemption rights held by Whitewater/I Squared and MPLX. After the closing on May 29, 2024, we accrued for our share of the post-closing mandatory capital expenditures of approximately US$150 million for the Rio Bravo Pipeline project. Additional capital expenditures to complete the Rio Bravo Pipeline project will be proportionate to our economic interest. The contribution of our interest in the Rio Bravo Pipeline project to the Whistler Parent JV in exchange for the equity interests discussed above represents a non-cash transaction in Cash Flows from Investing Activities and does not have an effect on our Consolidated Statements of Cash Flows. This component of the transaction resulted in a reduction of $321 million (US$235 million) to Property, plant and equipment, net and a corresponding increase to Long-term investments in the Consolidated Statements of Financial Position. The cash component of the transaction, as well as subsequent cash payments made for post-closing mandatory capital expenditures, have been reflected as contributions in Cash Flows from Investing Activities. Fox Squirrel Solar LLC On November 15, 2023, we acquired a 50.0% 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 included an upfront payment of $157 million (US$115 million) with subsequent capital contributions of $591 million (US$426 million), for all phases of construction, made at the project's in-service dates. 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 49.0% 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 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.

INTANGIBLE ASSETS

INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
INTANGIBLE ASSETS	INTANGIBLE ASSETS December 31, 2024 Weighted Average Amortization Rate Cost Accumulated Amortization Net (millions of Canadian dollars) Software 10.9 % 2,109 (1,222) 887 Power purchase agreements 4.5 % 58 (26) 32 Project agreement 1 4.0 % 173 (52) 121 Customer relationships 8.6 % 2,856 (975) 1,881 Biogas rights agreements 3.4 % 999 (34) 965 Other intangible assets 5.8 % 665 (234) 431 Under development — % 270 — 270 7,130 (2,543) 4,587 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 1 Represents a project agreement acquired from the merger of Enbridge and Spectra Energy. For the years ended December 31, 2024, 2023 and 2022, our amortization expense related to intangible assets totaled $530 million, $535 million and $483 million, respectively. Our expected amortization expense associated with existing intangible assets for each of the years 2025 to 2029 is $558 million.

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Consolidated (millions of Canadian dollars) Balance at January 1, 2023 8,549 18,106 5,397 388 32,440 Foreign exchange and other (205) (425) — (8) (638) Acquisition 3 — 46 — — 46 Balance at December 31, 2023 1,2 8,344 17,727 5,397 380 31,848 Dispositions 4 — (1,026) — — (1,026) Foreign exchange and other 672 1,354 204 34 2,264 Acquisitions 5 — 223 3,291 — 3,514 Balance at December 31, 2024 1,2 9,016 18,278 8,892 414 36,600 1 Gross goodwill as at December 31, 2024 and 2023 was $40.7 billion and $35.9 billion, respectively. 2 Accumulated impairment as at December 31, 2024 and 2023 was $4.1 billion. 3 In 2023, we recorded $46 million of goodwill related to the acquisition of Aitken Creek. Refer to Note 8 - Acquisitions and Disposition . 4 In 2024, we derecognized $1.0 billion of goodwill related to the sale of our interests in the Alliance Pipeline and Aux Sable. Refer to Note 13 - Long-Term Investments . 5 In 2024, we recorded $895 million of goodwill related to the PSNC Acquisition, $793 million of goodwill related to the Questar Acquisition, $1.6 billion of goodwill related to the EOG Acquisition, and $223 million of goodwill related to the RNG Facilities Acquisition. Refer to Note 8 - Acquisitions and Disposition .

OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES	12 Months Ended
	Dec. 31, 2024
Payables and Accruals [Abstract]
OTHER LONG-TERM LIABILITIES	OTHER CURRENT LIABILITIES December 31, 2024 2023 (millions of Canadian dollars) Dividends payable 2,088 1,975 Deferred credits 1,072 1,177 Derivative liabilities (Note 23) 1,335 738 Taxes payable 959 596 Regulatory liabilities (Note 7) 616 307 Federal carbon program liability 498 376 Asset retirement obligations (Note 18) 120 136 Other 553 354 7,241 5,659

DEBT

DEBT	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
DEBT	DEBT December 31, Weighted Average Interest Rate 8 Maturity 2024 2023 (millions of Canadian dollars) Enbridge Inc. US dollar senior notes 4.8 % 2025 - 2054 19,703 14,636 Medium-term notes 4.5 % 2025 - 2064 9,900 8,598 Sustainability-linked bonds 4.7 % 2032 - 2033 7,146 6,751 Fixed-to-fixed subordinated term notes 1 7.4 % 2054 - 2084 9,372 7,156 Fixed-to-floating rate subordinated term notes 2 5.8 % 2077 - 2078 6,139 5,828 Floating rate notes — 791 Fixed-to-floating non-call notes — 923 Commercial paper and credit facility draws 3.7 % 2025 - 2029 5,843 3,177 Other 3 12 17 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 4.8 % 2026 - 2029 4,707 670 Other 3 276 263 Enbridge Energy Partners, L.P. Senior notes 6.5 % 2025 - 2045 3,524 3,231 Enbridge Gas Inc. Medium-term notes 4.1 % 2025 - 2053 9,970 10,185 Debentures 8.7 % 2025 125 210 Commercial paper and credit facility draws 3.4 % 2026 530 400 Other 3 1 2 Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 4.0 % 2040 736 791 Enbridge Pipelines Inc. Medium-term notes 4 4.2 % 2025 - 2053 5,425 5,425 Debentures — 200 Commercial paper and credit facility draws 3.8 % 2026 509 449 Other 3 2 4 Enbridge Southern Lights LP Senior notes 4.0 % 2040 183 214 Spectra Energy Capital, LLC Senior notes 7.1 % 2032 - 2038 248 228 Algonquin Gas Transmission, LLC Senior notes 4.4 % 2029 - 2034 1,222 1,121 East Tennessee Natural Gas, LLC Senior notes 5.7 % 2034 662 251 Texas Eastern Transmission, LP Senior notes 4.7 % 2028 - 2048 3,667 3,362 Spectra Energy Partners, LP Senior notes 4.2 % 2025 - 2045 3,164 4,220 Blauracke GmbH Senior notes 2.1 % 2032 471 521 The East Ohio Gas Company Senior notes 3.1 % 2025 - 2052 3,308 — Other 3 24 — Questar Gas Company Senior notes 4.2 % 2027 - 2052 2,028 — Public Service Company of North Carolina, Incorporated Senior notes 5.0 % 2026 - 2054 1,798 — Enbridge Holdings (Tomorrow RNG), LLC Senior notes 4.9 % 2025 817 — Westcoast Energy Inc. Medium-term notes 5.4 % 2025 - 2041 875 1,225 Debentures 8.1 % 2025 - 2026 275 275 Fair value adjustment (468) 514 Other 5 (522) (439) Total debt 6 101,672 81,199 Current maturities (7,729) (6,084) Short-term borrowings 7 (529) (400) Long-term debt 93,414 74,715 1 For an initial five 2 For an initial five 3 Primarily finance lease obligations. 4 Included in medium-term notes is $100 million with a maturity date of 2112. 5 Primarily unamortized discounts, premiums and debt issuance costs. 6 2024 - $40 billion, US$43 billion and €316 million; 2023 - $37 billion, US$33 billion and €359 million. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment. 7 Weighted average interest rates on outstanding commercial paper were 3.4% as at December 31, 2024 (2023 - 5.2%). 8 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2024. As at December 31, 2024, all outstanding debt was unsecured. CREDIT FACILITIES The following table provides details of our committed credit facilities as at December 31, 2024: Maturity 1 Total Facilities Draws 2 Available (millions of Canadian dollars) Enbridge Inc. 2025-2049 8,840 5,843 2,997 Enbridge (U.S.) Inc. 2026-2029 10,813 4,707 6,106 Enbridge Pipelines Inc. 2026 2,000 509 1,491 Enbridge Gas Inc. 2026 2,500 530 1,970 Total committed credit facilities 24,153 11,589 12,564 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 2024, we entered into a delayed-draw term loan facility in support of sustainable retrofit projects for large buildings using decarbonization solutions for $200 million which matures in March 2049. In June 2024, we entered into a five-year, non-revolving term loan facility of US$250 million which matures in June 2029. In July 2024, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2026, which includes a one-year term out provision from July 2025. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2029. Further, we extended the maturity dates of our three-year credit facilities to July 2027. In July 2024, Enbridge Gas Ontario extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025. In July 2024, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025. In January 2024 and October 2024, we entered into new letters of credit facilities and increased our letter of credit facilities by $146 million and $200 million, respectively. In addition to the committed credit facilities noted above, we maintain $1.4 billion of uncommitted demand letter of credit facilities, of which $931 million was unutilized as at December 31, 2024. As at December 31, 2023, we had $1.1 billion of uncommitted demand letter of credit facilities, of which $572 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 2025 to 2049. As at December 31, 2024 and 2023, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $10.3 billion and $3.8 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt. ACQUISITIONS As a result of the EOG Acquisition, RNG Facilities Acquisition, Questar Acquisition and PSNC Acquisition, our debt increased by US$1.9 billion, US$568 million, US$1.0 billion, and US$1.1 billion, respectively, on each acquisition date. Refer to Note 8 - Acquisitions and Disposition for further details. LONG-TERM DEBT ISSUANCES During the year ended December 31, 2024, we completed the following long-term debt issuances totaling US$5.7 billion and $1.8 billion: Company Issue Date Principal Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. April 2024 5.25% senior notes due April 2027 US$750 April 2024 5.30% senior notes due April 2029 US$750 April 2024 5.63% senior notes due April 2034 US$1,200 April 2024 5.95% senior notes due April 2054 US$800 June 2024 7.38% fixed-to-fixed subordinated notes due March 2055 1 US$500 June 2024 7.20% fixed-to-fixed subordinated notes due June 2054 2 US$700 August 2024 4.21% medium-term notes due February 2030 $600 August 2024 4.73% medium-term notes due August 2034 $800 August 2024 5.32% medium-term notes due August 2054 $400 Algonquin Gas Transmission, LLC July 2024 5.95% senior notes due July 2034 US$350 East Tennessee Natural Gas, LLC December 2024 5.72% senior notes due December 2034 US$460 Questar Gas Company December 2024 5.33% senior notes due December 2034 US$200 1 For the initial 5.5 years, the notes carry a fixed interest rate. On March 15, 2030, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.12%. 2 For the initial 9.75 years, the notes carry a fixed interest rate. On June 27, 2034, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 2.97%. LONG-TERM DEBT REPAYMENTS During the year ended December 31, 2024, we completed the following long-term debt repayments totaling US$3.9 billion, $1.4 billion, and €43 million, respectively: Company Repayment Date Principal Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. February 2024 Floating rate notes 1 US$600 February 2024 2.15% senior notes US$400 March 2024 5.97% senior notes 2 US$700 June 2024 3.50% senior notes US$500 November 2024 3.95% medium-term notes $500 Enbridge Gas Inc. August 2024 3.15% medium-term notes $215 December 2024 9.85 % debentures $85 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2024 3.98% senior notes US$89 Enbridge Pipelines Inc. February 2024 8.20% debentures $200 Enbridge Southern Lights LP January, July and December 2024 4.01% senior notes $31 Westcoast Energy Inc. September 2024 3.43% medium-term notes $350 Spectra Energy Partners, LP March 2024 4.75% senior notes US$1,000 Blauracke GmbH April and October 2024 2.10% senior notes €43 Algonquin Gas Transmission, LLC July 2024 3.51% senior notes US$350 Questar Gas Company December 2024 2.98% senior notes US$40 East Tennessee Natural Gas, LLC December 2024 3.10% senior notes US$190 1 Notes carried an interest rate set to equal the SOFR plus a margin of 63 basis points. 2 The notes carried an original maturity date in March 2026, and were callable in March 2024, which was one year after their issuance. 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, 2024, we were in compliance with all debt covenants. ANNUAL DEBT MATURITIES As at December 31, 2024, 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 1 101,819 7,724 7,379 4,704 3,056 13,578 65,378 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, 2024 2023 2022 (millions of Canadian dollars) Debentures and term notes 4,123 3,439 2,910 Commercial paper and credit facility draws 439 519 388 Amortization of fair value adjustment 18 (45) (45) Capitalized interest (161) (101) (74) 4,419 3,812 3,179

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS Our ARO relate mostly to the retirement of pipelines, renewable power generation assets, oil and gas wells and production facilities, 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, 2024 and 2023 ranged from 1.5% to 9.0%. A reconciliation of movements in our ARO liabilities is as follows: December 31, 2024 2023 (millions of Canadian dollars) Obligations at beginning of year 493 488 Liabilities acquired 185 1 Liabilities incurred 3 — Liabilities settled (139) (23) Change in estimate and other 51 5 Foreign currency translation adjustment 40 (6) Accretion expense 33 28 Obligations at end of year 666 493 Presented as follows: Other current liabilities (Note 16) 120 136 Other long-term liabilities 546 357 666 493

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 (millions of Canadian dollars) Algonquin Gas Transmission, LLC 414 384 Enbridge Athabasca Midstream Investor Limited Partnership 1,073 1,086 Maritimes & Northeast Pipeline, L.L.C. 606 559 Renewable energy assets 786 885 Maritimes & Northeast Pipeline Limited Partnership 109 111 Other 5 4 2,993 3,029

SHARE CAPITAL

SHARE CAPITAL	12 Months Ended
	Dec. 31, 2024
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 2024 2023 2022 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 2,125 69,180 2,025 64,760 2,026 64,799 Shares issued, net of issue costs 51 2,489 103 4,485 — — Shares issued on exercise of stock options 1 39 — 3 2 53 Shares issued on vesting of RSUs, net of tax 1 30 — 12 — — Share repurchases at stated value 1 — — (3) (80) (3) (88) Other — — — — — (4) Balance at end of year 2,178 71,738 2,125 69,180 2,025 64,760 1 Reflects the repurchase and cancellation of common shares under our normal course issuer bid. On May 15, 2024, we filed prospectus supplements in Canada and the US to establish an at-the-market equity issuance program (the ATM Program) that allowed us to issue and sell, at our discretion, up to $2.75 billion (or the US dollar equivalent) of our common shares from treasury to the public from time to time at the market prices prevailing at the time of sale through the Toronto Stock Exchange, the New York Stock Exchange (NYSE) or any other marketplace in Canada or the US where the common shares may be traded. During the period from May 15, 2024 to July 31, 2024, 51,298,629 common shares were issued and sold under the ATM Program at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.50 billion ($2.48 billion, net of aggregate commissions paid of $16.3 million and other issuance costs). On August 1, 2024, we terminated the ATM Program. Net proceeds from sales of common shares under the ATM Program were used to partially fund the Questar Acquisition and PSNC Acquisition and to pay related fees and expenses. 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 were also used to finance a portion of the aggregate cash consideration payable for the Acquisitions discussed in Note 8 - Acquisitions and Disposition . PREFERENCE SHARES 2024 2023 2022 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 20 500 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 18 454 18 454 20 500 Preference Shares, Series G 1 2 46 2 46 — — Preference Shares, Series H 12 291 12 291 14 350 Preference Shares, Series I 2 2 59 2 59 — — 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 22 562 24 600 24 600 Preference Shares, Series 4 3 2 38 — — — — 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 19 20 500 20 500 20 500 Issuance costs (135) (135) (135) Balance at end of year 6,818 6,818 6,818 1 On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G. 2 On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I. 3 On September 1, 2024, 1,502,775 of the outstanding Preference Shares, Series 3 were converted into Preference Shares, Series 4. 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 5.41 % $1.35300 $25 March 1, 2028 Series E Preference Shares, Series F 5.54 % $1.38452 $25 June 1, 2028 Series G Preference Shares, Series G 5 6.15 % $1.51644 $25 June 1, 2028 Series F Preference Shares, Series H 6.11 % $1.52800 $25 September 1, 2028 Series I Preference Shares, Series I 6 5.76 % $1.42028 $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 6.70 % $1.67400 $25 December 1, 2028 Series O Preference Shares, Series P 7 5.92 % $1.47952 $25 March 1, 2029 Series Q Preference Shares, Series R 8 6.31 % $1.57852 $25 June 1, 2029 Series S Preference Shares, Series 1 6.70 % US$1.67592 US$25 June 1, 2028 Series 2 Preference Shares, Series 3 9 5.29 % $1.32200 $25 September 1, 2029 Series 4 Preference Shares, Series 4 10 6.02 % $1.48440 $25 September 1, 2029 Series 3 Preference Shares, Series 5 11 6.68 % US$1.67076 US$25 March 1, 2029 Series 6 Preference Shares, Series 7 12 5.99 % $1.49700 $25 March 1, 2029 Series 8 Preference Shares, Series 9 13 5.67 % $1.41800 $25 December 1, 2029 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 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, Series I and Series 4 contain a feature where the dividend rate resets on a quarterly basis. These Dividend Rates are presented in the table above on an annualized basis using the most recent quarterly dividend rate reset. 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 G was decreased to $0.37911 from $0.43014 on December 1, 2024 due to reset on a quarterly basis. 6 The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.35507 from $0.40589 on December 1, 2024 due to reset on a quarterly basis. 7 The quarterly dividend per share paid on Preference Shares, Series P was increased to $0.36988 from $0.27369 on March 1, 2024 due to reset of the annual dividend on March 1, 2024. 8 The quarterly dividend per share paid on Preference Shares, Series R was increased to $0.39463 from $0.25456 on June 1, 2024 due to reset of the annual dividend on June 1, 2024. 9 The quarterly dividend per share paid on Preference Shares, Series 3 was increased to $0.33050 from $0.23356 on September 1, 2024 due to reset of the annual dividend on September 1, 2024. 10 On September 1, 2024, 1,502,775 of the outstanding Preference Shares, Series 3 were converted into Preference Shares, Series 4. The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to $0.37110 from $0.42206 on December 1, 2024 due to reset on a quarterly basis following the date of issuance. 11 The quarterly dividend per share paid on Preference Shares, Series 5 was increased to US$0.41769 from US$0.33596 on March 1, 2024 due to reset of the annual dividend on March 1, 2024. 12 The quarterly dividend per share paid on Preference Shares, Series 7 was increased to $0.37425 from $0.27806 on March 1, 2024 due to reset of the annual dividend on March 1, 2024. 13 The quarterly dividend per share paid on Preference Shares, Series 9 was increased to $0.35450 from $0.25606 on December 1, 2024 due to reset of the annual dividend on December 1, 2024. SHAREHOLDER RIGHTS PLAN The Shareholder Rights Plan is designed to encourage the fair treatment of our shareholders in connection with any takeover offer. Rights issued under the plan become exercisable when a person and any related parties acquires or announces its intention to acquire 20% or more of our outstanding common shares without complying with certain provisions set out in the plan or without approval of our Board of Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase our common shares at a 50% discount to the market price at that time.

STOCK OPTION AND STOCK UNIT PLA

STOCK OPTION AND STOCK UNIT PLANS	12 Months Ended
	Dec. 31, 2024
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, 2024, 2023 and 2022 was $186 million, $154 million and $260 million, respectively. The number of common shares authorized for share-settled awards under the Plan was 181 million as at December 31, 2024, 2023 and 2022. 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-year period and expire 10 years after the issue date. December 31, 2024 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 28,729 50.79 Options granted 5,036 46.36 Options exercised 1 (7,328) 49.27 Options cancelled or expired (1,113) 51.78 Options outstanding at end of year 25,324 50.31 5.7 70 Options vested at end of year 2 15,602 51.33 4.2 37 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2024, 2023 and 2022 was $18 million, $2 million and $66 million, respectively, and cash received on exercise was $1 million, nil and $3 million, respectively. 2 The total fair value of ISOs vested during the years ended December 31, 2024, 2023 and 2022 was $17 million, $20 million and $21 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, 2024 2023 2022 Fair value per option (Canadian dollars) 1 4.07 6.05 5.07 Valuation assumptions Expected option term (years) 2 6 6 6 Expected volatility 3 21.1 % 22.2 % 21.9 % Expected dividend yield 4 8.1 % 6.7 % 6.5 % Risk-free interest rate 5 3.8 % 3.5 % 1.8 % 1 Options granted to US employees are based on the NYSE prices. The option value and assumptions shown are based on a weighted average of the US and Canadian options. The fair value per option for the years ended December 31, 2024, 2023 and 2022 were $3.53, $5.38 and $4.78, respectively, for Canadian employees and US$3.58, US$5.23 and US$4.62, respectively, for US employees. 2 The expected option term is six years based on historical exercise practice and five years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada's Canadian bond yields and the US Treasury bond yields at the grant date. Compensation expense recorded for the years ended December 31, 2024, 2023 and 2022 for ISOs was $19 million, $18 million and $15 million, respectively. As at December 31, 2024, unrecognized compensation expense related to non-vested ISOs was $12 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 with the 2023 grant, the performance multiplier also includes a greenhouse gas reduction component. To calculate the 2024 expense, a multiplier of 1.38 was used for 2024 PSU grants, 1.1 for 2023 PSU grants and 1.0 for 2022 PSU grants. December 31, 2024 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 3,180 Units granted 1,444 Units cancelled (104) Units matured 1 (1,355) Dividend reinvestment 237 Units outstanding at end of year 3,402 1.6 244 1 The total amount paid during the years ended December 31, 2024, 2023 and 2022 for PSUs was $65 million, $123 million and $90 million, respectively. Compensation expense recorded for the years ended December 31, 2024, 2023 and 2022 for PSUs was $75 million, $59 million and $169 million, respectively. As at December 31, 2024, unrecognized compensation expense related to non-vested PSUs was $109 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.Share-settled awards granted to non-executive senior management employees vest following a three-year maturity period. Beginning in 2023, share-settled units were also granted to non-executive employees. These units vest either on each of the first, second and third anniversaries of the grant date, or following a 12-month period. Cash-settled RSUs are given to non-executive employees and are paid in equal installments 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, 2024 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 3,571 50.69 Units granted 1,758 48.50 Units cancelled (112) 51.38 Units matured 1 (1,910) 49.99 Dividend reinvestment 284 50.94 Units outstanding at end of year 3,591 51.10 1.0 187 1 The total amount paid during the years ended December 31, 2024, 2023 and 2022 for RSUs was $40 million, $56 million and $32 million, respectively. 2 Weighted average grant date fair value excludes cash-settled units. Compensation expense recorded for the years ended December 31, 2024, 2023 and 2022 for RSUs was $92 million, $77 million and $76 million, respectively. As at December 31, 2024, unrecognized compensation expense related to non-vested RSUs was $67 million. The expense is expected to be fully recognized over a weighted average period of approximately one year.

COMPONENTS OF ACCUMULATED OTHER

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	12 Months Ended
	Dec. 31, 2024
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, 2024, 2023 and 2022 are as follows: Cash Flow Hedges Excluded Components of Fair Value Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2024 320 (23) (728) 2,653 11 70 2,303 Other comprehensive income/(loss) retained in AOCI 79 (42) (1,305) 5,799 (9) 323 4,845 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 31 — — — — — 31 Commodity contracts 2 (1) — — — — — (1) Foreign exchange contracts 3 — 53 — — — — 53 Amortization of pension and OPEB actuarial gain 4 — — — — — (21) (21) 109 11 (1,305) 5,799 (9) 302 4,907 Tax impact Income tax on amounts retained in AOCI (15) 10 — — (1) (75) (81) Income tax on amounts reclassified to earnings (7) (12) — — — 5 (14) (22) (2) — — (1) (70) (95) Balance as at December 31, 2024 407 (14) (2,033) 8,452 1 302 7,115 Cash Flow Hedges Excluded Components of Fair Value Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2023 121 (35) (1,137) 4,348 5 218 3,520 Other comprehensive income/(loss) retained in AOCI 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 3 — (47) — — — — (47) Amortization of pension and OPEB actuarial gain 4 — — — — — (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 Components of Fair Value Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2022 (897) — (166) 56 (5) (84) (1,096) Other comprehensive income/(loss) retained in AOCI 1,125 (35) (971) 4,292 (6) 411 4,816 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 186 — — — — — 186 Foreign exchange contracts 3 (4) — — — — — (4) Other contracts 5 4 — — — — — 4 Amortization of pension and OPEB actuarial gain 4 — — — — — (14) (14) Other — — — — 16 — 16 1,311 (35) (971) 4,292 10 397 5,004 Tax impact Income tax on amounts retained in AOCI (250) — — — — (99) (349) Income tax on amounts reclassified to earnings (43) — — — — 4 (39) (293) — — — — (95) (388) Balance as at December 31, 2022 121 (35) (1,137) 4,348 5 218 3,520 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Transportation and other services revenues in the Consolidated Statements of Earnings. 3 Reported within Interest expense and Other income/(expense) in the Consolidated Statements of Earnings. 4 These components are included in the computation of net periodic benefit credit and are reported within Other income/(expense) in the Consolidated Statements of Earnings. 5 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2024
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 risk). 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 US dollar-denominated debt. 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 have a policy of limiting our maximum floating rate debt to 30% of total debt outstanding. To ensure compliance with our policy, we monitor and adjust our debt portfolio mix of fixed and variable rate debt instruments in conjunction with the use of derivative instruments. We have implemented a 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 3.6%. Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. A combination of qualifying and non-qualifying forward starting interest rate swaps is 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 3.4%. 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 marketing 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. TOTAL DERIVATIVE INSTRUMENTS We 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 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 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. December 31, 2024 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 — 78 47 125 (29) 96 Interest rate contracts 44 — 23 67 (39) 28 Commodity contracts 2 — 360 362 (191) 171 Other contracts — — 3 3 — 3 46 78 433 557 (259) 298 Deferred amounts and other assets Foreign exchange contracts — — 83 83 (71) 12 Interest rate contracts 9 — 137 146 (27) 119 Commodity contracts — — 197 197 (39) 158 9 — 417 426 (137) 289 Other current liabilities Foreign exchange contracts — (73) (731) (804) 29 (775) Interest rate contracts (58) — (22) (80) 39 (41) Commodity contracts — — (451) (451) 191 (260) (58) (73) (1,204) (1,335) 259 (1,076) Other long-term liabilities Foreign exchange contracts — — (1,579) (1,579) 71 (1,508) Interest rate contracts — — (80) (80) 27 (53) Commodity contracts (1) — (238) (239) 39 (200) (1) — (1,897) (1,898) 137 (1,761) Total net derivative asset/(liability) Foreign exchange contracts — 5 (2,180) (2,175) — (2,175) Interest rate contracts (5) — 58 53 — 53 Commodity contracts 1 — (132) (131) — (131) Other contracts — — 3 3 — 3 (4) 5 (2,251) (2,250) — (2,250) December 31, 2023 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Fair Value Hedges Non-Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Other current assets Foreign exchange contracts — 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) The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments: 2024 2023 As at December 31, 2025 2026 2027 2028 2029 Thereafter Total Total Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) 1,245 — — — — — 1,245 1,860 Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) 6,406 5,627 4,811 3,522 1,248 — 21,614 24,747 Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) 30 28 32 — — — 90 120 Foreign exchange contracts - Euro forwards - sell (millions of Euro) 126 121 81 67 66 129 590 731 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) 2,296 1,737 676 49 13 — 4,771 9,018 Interest rate contracts - short-term receive fixed rate (millions of Canadian dollars) — — — — — — — 2,015 Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 1 4,531 753 — — — — 5,284 5,162 Interest rate contracts - costless collar (millions of Canadian dollars) 1,938 268 104 6 — — 2,316 1,139 Equity contracts (millions of Canadian dollars) — — — — — — — 47 Commodity contracts - natural gas (billions of cubic feet) 2 154 79 37 11 5 2 288 86 Commodity contracts - crude oil (millions of barrels) 2 6 15 1 1 1 1 25 6 Commodity contracts - power (megawatt per hour (MW/H)) 61 24 (31) (49) (30) — (5) 3 (22) 3 1 Represents the notional amount of long-term debt issuances hedged. 2 Represents the notional amount of net purchase/(sale). 3 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, 2024 2023 (millions of Canadian dollars) Unrealized loss on derivative (3) (132) Unrealized gain on hedged item 6 131 Realized gain/(loss) on derivative 26 (47) Realized loss on hedged item (79) — 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 comprehensive income, before the effect of income taxes: Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts — — 3 Interest rate contracts 67 201 1,151 Commodity contracts 19 68 (53) Other contracts 1 (2) (4) Fair value hedges Foreign exchange contracts (42) 15 (35) 45 282 1,062 Amount of (income)/loss reclassified from AOCI to earnings Foreign exchange contracts 1 53 — 13 Interest rate contracts 2 31 28 186 Commodity contracts 3 (1) — — Other contracts 4 — — 4 83 28 203 1 Reported within Interest expense and Other income/(expense) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. We estimate that no amounts from AOCI related to open 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 two years as at December 31, 2024. 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, 2024 2023 2022 (millions of Canadian dollars) Foreign exchange contracts 1 (2,033) 1,292 (1,344) Interest rate contracts 2 112 (63) 10 Commodity contracts 3 (163) (41) 50 Other contracts 4 2 (8) 4 Total unrealized derivative fair value gain/(loss), net (2,082) 1,180 (1,280) 1 For the respective years ended, reported within Transportation and other services revenues (2024 - nil ; 2023 - $645 million gain; 2022 - $238 million loss) and Other income/(expense) (2024 - $2,033 million loss; 2023 - $647 million gain; 2022 - $1,106 million loss) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 For the respective years ended, reported within Transportation and other services revenues (2024 - $23 million loss; 2023 - $35 million loss; 2022 - $13 million gain), Commodity sales (2024 - $92 million loss; 2023 - $153 million gain; 2022 - $89 million gain), Commodity costs (2024 - $31 million loss; 2023 - $94 million loss; 2022 - $102 million loss) and Operating and administrative expense (2024 - $17 million loss; 2023 - $65 million loss; 2022 - $50 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. 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, 2024. 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 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, contractual requirements and netting arrangements. We also review counterparty credit exposure using external credit rating services and other analytical tools to manage credit risk. We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2024 2023 (millions of Canadian dollars) Canadian financial institutions 344 457 US financial institutions 128 252 European financial institutions 116 107 Asian financial institutions 53 121 Other 1 332 125 973 1,062 1 Other is comprised of commodity clearing house and crude oil, natural gas and power counterparties. As at December 31, 2024, 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, 2024 and 2023. 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 counterparty credit ratings and netting arrangements. Within the Gas Distribution and Storage segment, credit risk is mitigated by the utility's large and diversified customer base and the ability to recover 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. Under the fair value hierarchy, cash and cash equivalents are classified as Level 1. 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, and investments in exchange-traded funds held by our captive insurance subsidiaries. We also hold restricted long-term investments in exchange-traded funds and common shares in trusts in accordance with the CER's regulatory requirements under the LMCI and to cover future pipeline decommissioning costs in the state of Minnesota. 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 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, physical forward commodity contracts, as well as options. 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, 2024 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 125 — 125 Interest rate contracts — 67 — 67 Commodity contracts 34 72 256 362 Other contracts — 3 — 3 34 267 256 557 Long-term derivative assets Foreign exchange contracts — 83 — 83 Interest rate contracts — 146 — 146 Commodity contracts 1 14 182 197 Other contracts — — — — 1 243 182 426 Financial liabilities Current derivative liabilities Foreign exchange contracts — (804) — (804) Interest rate contracts — (80) — (80) Commodity contracts (52) (116) (283) (451) Other contracts — — — — (52) (1,000) (283) (1,335) Long-term derivative liabilities Foreign exchange contracts — (1,579) — (1,579) Interest rate contracts — (80) — (80) Commodity contracts (1) (31) (207) (239) Other contracts — — — — (1) (1,690) (207) (1,898) Total net derivative asset/(liability) Foreign exchange contracts — (2,175) — (2,175) Interest rate contracts — 53 — 53 Commodity contracts (18) (61) (52) (131) Other contracts — 3 — 3 (18) (2,180) (52) (2,250) 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 derivative asset/(liability) Foreign exchange contracts — (152) — (152) Interest rate contracts — (156) — (156) Commodity contracts 6 29 (131) (96) Other contracts — — — — 6 (279) (131) (404) The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2024 Fair Value Unobservable Input Minimum Price/Volatility Maximum Price/Volatility Weighted Average Price/Volatility Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas (5) Forward gas price 3.73 9.85 4.12 $/mmbtu 2 Crude (13) Forward crude price 73.54 104.42 97.44 $/barrel Power (44) Forward power price 31.17 229.29 68.51 $/MW/H Commodity contracts - physical 1 Natural gas (80) Forward gas price 1.40 22.57 4.12 $/mmbtu 2 Crude 22 Forward crude price 77.31 118.28 99.76 $/barrel Power (98) Forward power price 12.94 211.42 70.30 $/MW/H Commodity options 3 Natural gas 166 Forward gas price 2.44 7.09 4.44 $/mmbtu 2 Price volatility 3 % 77 % 50 % (52) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 One million British thermal units (mmbtu). 3 Commodity options contracts are valued using an option model valuation technique. 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, 2024 2023 (millions of Canadian dollars) Level 3 net derivative liability at beginning of year (131) (136) Total gain/(loss), unrealized Included in earnings 1 (92) (48) Included in OCI 19 67 Included in regulatory assets/liabilities 130 — Settlements 22 (14) Level 3 net derivative liability at end of year (52) (131) 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, 2024 or 2023. 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, 2024 and 2023, we recognized unrealized foreign exchange losses of $1,185 million and gains of $645 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, 2024 and 2023. No realized gains or losses associated with the settlement of foreign exchange forward contracts were recognized in OCI during the years ended December 31, 2024 and 2023. During the years ended December 31, 2024 and 2023, we recognized realized losses of $120 million and losses of $236 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 $187 million and $173 million as at December 31, 2024 and 2023, 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, 2024 , the fair value of investment s in equity funds and debt securities held by our captive insurance subsidiaries was $114 million and $1.1 billion, respectively (2023 - $287 million and $284 million, respectively). Our investments in debt securities had a cost basis of $1.1 billion as at December 31, 2024 (2023 - $279 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 losses of $16 million for the year ended December 31, 2024 (2023 - gains of $34 million). As at December 31, 2024 and 2023, our long-term debt had a carrying value of $101.6 billion and $81.2 billion, respectively, before debt issuance costs and a fair value of $98.9 billion and $78.1 billion, respectively. As at December 31, 2024 and 2023, we had investments with a fair value of $998 million and $717 million, respectively, included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position which are classified as available-for-sale. These securities represent restricted funds held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements, to cover future pipeline decommissioning costs in the state of Minnesota and to satisfy retirement obligations as Wexpro properties are abandoned. We had restricted long-term investments and cash held in trust totaling $491 million and $263 million as at December 31, 2024 and 2023, respectively, which are classified as Level 1 in the fair value hierarchy. We also had restricted long-term investments held in trust totaling $507 million (cost basis - $540 million) and $454 million (cost basis - $486 million) as at December 31, 2024 and 2023, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding gains of $33 million and $51 million on these investments for the years ended December 31, 2024 and 2023, respectively. Within Other long-term liabilities we had estimated future abandonment costs related to LMCI of $826 million and $745 million as at December 31, 2024 and 2023, 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 and long-term debt described above approximate their carrying value due to the short period to maturity.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES INCOME TAX RATE RECONCILIATION Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Earnings before income taxes 7,299 7,879 4,542 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 1,095 1,182 681 Increase/(decrease) resulting from: Provincial and state income taxes 1 183 411 108 Foreign and other statutory rate differentials 2 340 187 295 Effects of rate-regulated accounting 3.4 (192) (106) (122) Write-off of regulatory deferrals 3,5 4 115 — Part VI.1 tax, net of federal Part I deduction 3,6 73 66 76 US Minimum Tax 148 100 107 Non-taxable portion of gain on sale of investmen t 3,7 (147) — — Valuation allowance 3 (2) (12) 6 Accounting impairment of non-deductible goodwill 3,8 148 — 370 Noncontrolling interests 3,9 (30) 19 9 Investment and production tax credits (23) (47) — Other 3 71 (94) 74 Income tax expense 1,668 1,821 1,604 Effective income tax rate 22.9 % 23.1 % 35.3 % 1 The change in provincial and state income taxes from 2023 to 2024 reflects the decrease in earnings from Canadian operations partially offset by an increase in earnings from US operations before considering the non-deductible goodwill impairment to the Gas Transmission segment. Refer to Note 13 - Long-Term Investments . 2 The change in foreign and other statutory rate differentials from 2023 to 2024 reflects the increase in earnings from US operations before considering the non-deductible goodwill impairment to the Gas Transmission segment. Refer to Note 13 - Long-Term Investments. 3 T he provincial and state tax component of these items is included in the Provincial and state income taxes above. 4 The amount in 2024 includes the effects of rate regulated accounting attributable to the Acquisitions. Refer to Note 8 - Acquisitions and Disposition. 5 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 . 6 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada. 7 The amount in 2024 represents the federal component of the non-taxable portion of the gain on sales relating to Alliance Pipeline and Aux Sable. Refer to Note 13 - Long-Term Investments . 8 The amounts relates to the federal impact of the non-deductible goodwill impairment to the Gas Transmissions segment. Refer to Note 13 - Long-Term Investments and Note 15 - Goodwill . 9 The amount in 2023 and 2022 includes the federal tax impact of impairments to Chapman Ranch and Magic Valley attributable to non-controlling interests in those respective years. Refer to Note 11 - Property, Plant and Equipment . COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Earnings before income taxes Canada 1,035 2,233 583 US 5,231 4,620 2,865 Other 1,033 1,026 1,094 7,299 7,879 4,542 Current income taxes Canada 248 100 360 US 578 191 201 Other 123 110 86 949 401 647 Deferred income taxes Canada (299) 456 (358) US 1,013 974 1,309 Other 5 (10) 6 719 1,420 957 Income tax expense 1,668 1,821 1,604 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, 2024 2023 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (11,368) (9,202) Investments (9,043) (7,765) Regulatory assets (1,940) (1,338) Other (251) (52) Total deferred income tax liabilities (22,602) (18,357) Deferred income tax assets Financial instruments 740 271 Loss carryforwards 1,272 1,745 Other 2,088 1,798 Total deferred income tax assets 4,100 3,814 Less valuation allowance (298) (147) Total deferred income tax assets, net 3,802 3,667 Net deferred income tax liabilities, net (18,800) (14,690) Presented as follows: Total deferred income tax assets 796 341 Total deferred income tax liabilities (19,596) (15,031) Net deferred income tax liabilities, net (18,800) (14,690) 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 both December 31, 2024 and 2023, we recognized the benefit of unused tax loss carryforwards of $1.3 billion in Canada which expire in 2031 and beyond. As at December 31, 2024, and 2023, we recognized the benefit of unused tax loss carryforwards of $4.2 billion and $6.4 billion, respectively, in the US with 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 $9.5 billion and $6.6 billion for the periods ended December 31, 2024 and 2023, 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 2017 to 2024 tax years and by US tax authorities for the 2021 to 2024 tax years. We are currently under examination for income tax matters in Canada for the 2018 to 2021 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, 2024 2023 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 45 55 Gross decreases for tax positions of prior year (2) (2) Change in translation of foreign currency 4 (1) Lapses of statute of limitations (16) (7) Unrecognized tax benefits at end of year 31 45 The unrecognized tax benefits as at December 31, 2024, if recognized, would impact our effective income tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on our consolidated financial statements. We recognize accrued interest and penalties related to unrecognized tax benefits as a component of income taxes. Interest and penalties included in income taxes for the years ended December 31, 2024 and 2023 were $8 million recovery and $1 million expense, respectively. As at December 31, 2024 and 2023, interest and penalties of $6 million and $14 million, respectively, have been accrued.

PENSION AND OTHER POSTRETIREMEN

PENSION AND OTHER POSTRETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 2024 2023 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 4,092 3,630 1,036 1,029 Service cost 103 81 60 40 Interest cost 186 184 69 47 Participant contributions 32 31 — — Actuarial (gain)/loss 1 — 359 (98) 31 Benefits paid (210) (193) (100) (76) Transfer in — — 569 — Foreign currency exchange rate changes — — 119 (29) Other — — (7) (6) Projected benefit obligation at end of year 2 4,203 4,092 1,648 1,036 Change in plan assets Fair value of plan assets at beginning of year 4,528 4,234 1,052 1,080 Actual return on plan assets 627 427 197 78 Employer contributions 23 27 5 5 Participant contributions 32 31 — — Benefits paid (210) (193) (100) (76) Transfer in — — 900 — Foreign currency exchange rate changes — — 146 (29) Other — 2 (6) (6) Fair value of plan assets at end of year 3 5,000 4,528 2,194 1,052 Overfunded status at end of year 797 436 546 16 Presented as follows: Deferred amounts and other assets 943 636 653 116 Other current liabilities (10) (8) (6) (5) Other long-term liabilities (136) (192) (101) (95) 797 436 546 16 1 Primarily due to the increase in the discount rate and changes in benefit assumptions and member data used to measure the defined benefit obligations (2023 - primarily due to the decrease in the discount rates used to measure the benefit obligation). 2 The accumulated benefit obligation for our Canadian pension plans was $3.9 billion and $3.8 billion as at December 31, 2024 and 2023, respectively. The accumulated benefit obligation for our US pension plans was $1.6 billion and $1.0 billion as at December 31, 2024 and 2023, respectively. 3 Assets in the amount of $18 million (2023 - $14 million) and $80 million (2023 - $62 million), related to our Canadian and US non-registered supplemental pension plan obligations, respectively, 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, 2024 2023 2024 2023 (millions of Canadian dollars) Accumulated benefit obligation 404 394 107 99 Fair value of plan assets 283 243 — — 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, 2024 2023 2024 2023 (millions of Canadian dollars) Projected benefit obligation 428 416 107 99 Fair value of plan assets 283 243 — — 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, 2024 2023 2024 2023 (millions of Canadian dollars) Net actuarial (gain)/loss (122) 51 (42) 74 Prior service cost — — 5 1 Total amount recognized in AOCI 1 (122) 51 (37) 75 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, 2024 2023 2022 2024 2023 2022 (millions of Canadian dollars) Service cost 1 103 81 131 60 40 43 Interest cost 2 186 184 127 69 47 24 Expected return on plan assets 2 (304) (271) (295) (131) (77) (85) Amortization/settlement of net actuarial (gain)/loss 2 4 — 8 7 (4) — Amortization/curtailment of prior service credit 2 — — — (4) — (2) Net periodic benefit (credit)/cost (11) (6) (29) 1 6 (20) Defined contribution benefit cost 12 12 10 — — — Net pension (credit)/cost recognized in Earnings 1 6 (19) 1 6 (20) Amount recognized in OCI: Amortization/settlement of net actuarial (gain)/loss — — (2) — 4 — Amortization/curtailment of prior service credit — — — 4 — 2 Net actuarial (gain)/loss arising during the year (173) 115 (288) (116) 30 (52) Total amount recognized in OCI (173) 115 (290) (112) 34 (50) Total amount recognized in Comprehensive income (172) 121 (309) (111) 40 (70) 1 Reported within Operating and administrative in the Consolidated Statements of Earnings. 2 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 2024 2023 2022 2024 2023 2022 Projected benefit obligation Discount rate 4.7 % 4.6 % 5.1 % 5.5 % 4.7 % 4.9 % Rate of salary increase 3.0 % 3.0 % 2.9 % 2.6 % 2.6 % 2.8 % Cash balance interest credit rate N/A N/A N/A 4.0 % 4.5 % 4.3 % Net periodic benefit cost Discount rate 4.6 % 5.3 % 3.2 % 4.8 % 4.9 % 2.6 % Rate of return on plan assets 6.8 % 6.5 % 6.6 % 7.3 % 7.4 % 7.4 % Rate of salary increase 3.0 % 2.9 % 2.9 % 2.8 % 2.8 % 2.8 % Cash balance interest credit rate N/A N/A N/A 4.4 % 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, 2024 2023 2024 2023 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 228 211 129 136 Service cost 3 3 3 1 Interest cost 10 11 7 6 Participant contributions — — 5 5 Actuarial (gain)/loss 1 (21) 13 (9) 4 Benefits paid (10) (10) (20) (20) Transfer in — — 46 — Foreign currency exchange rate changes — — 16 (3) Accumulated postretirement benefit obligation at end of year 210 228 177 129 Change in plan assets Fair value of plan assets at beginning of year — — 187 185 Actual return on plan assets — — 22 14 Employer contributions 10 10 7 7 Participant contributions — — 5 5 Benefits paid (10) (10) (20) (20) Transfer in — — 55 — Foreign currency exchange rate changes — — 20 (4) Other — — 2 — Fair value of plan assets at end of year — — 278 187 Overfunded/(underfunded) status at end of year (210) (228) 101 58 Presented as follows: Deferred amounts and other assets — — 113 73 Other current liabilities (11) (12) — — Other long-term liabilities (199) (216) (12) (15) (210) (228) 101 58 1 Primarily due to the increase in the discount rate and changes in benefit assumptions and member data used to measure the defined benefit obligation (2023 - primarily due to decrease 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, 2024 2023 2024 2023 (millions of Canadian dollars) Accumulated benefit obligation 210 228 100 78 Fair value of plan assets — — 88 63 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, 2024 2023 2024 2023 (millions of Canadian dollars) Net actuarial gain (99) (82) (103) (96) Prior service credit — (1) (16) (22) Total amount recognized in AOCI 1 (99) (83) (119) (118) 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, 2024 2023 2022 2024 2023 2022 (millions of Canadian dollars) Service cost 1 3 3 4 3 1 1 Interest cost 2 10 11 7 7 6 3 Expected return on plan assets 2 — — — (15) (11) (12) Amortization/settlement of net actuarial gain 2 (5) (6) (1) (5) (6) (6) Amortization/curtailment of prior service credit 2 (1) — — (6) (8) (7) Net periodic benefit (credit)/cost recognized in Earnings 7 8 10 (16) (18) (21) Amount recognized in OCI: Amortization/settlement of net actuarial gain 5 6 1 5 6 6 Amortization/curtailment of prior service credit 1 — — 6 8 7 Net actuarial (gain)/loss arising during the year (22) 13 (67) (12) — (4) Total amount recognized in OCI (16) 19 (66) (1) 14 9 Total amount recognized in Comprehensive income (9) 27 (56) (17) (4) (12) 1 Reported within Operating and administrative in the Consolidated Statements of Earnings. 2 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 2024 2023 2022 2024 2023 2022 Accumulated postretirement benefit obligation Discount rate 4.7 % 4.6 % 5.3 % 5.3 % 4.7 % 4.9 % Net periodic benefit cost Discount rate 4.6 % 5.3 % 3.2 % 5.5 % 4.9 % 2.4 % Rate of return on plan assets N/A N/A N/A 6.7 % 5.9 % 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 2024 2023 2024 2023 Health care cost trend rate assumed for next year 4.0 % 4.0 % 3.2 % 4.7 % Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.0 % 4.0 % 3.7 % 3.3 % Year that the rate reaches the ultimate trend rate N/A N/A 2023 - 2046 2022 - 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 2024 2023 Allocation 2024 2023 Equity securities 46.2 % 39.1 % 41.4 % 43.4 % 44.8 % 39.5 % Fixed income securities 23.0 % 31.6 % 29.6 % 23.2 % 33.0 % 19.4 % Alternatives 1 30.8 % 29.3 % 29.0 % 33.4 % 22.2 % 41.1 % 1 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Fund values are based on the net asset value of the funds that invest directly in the aforementioned underlying investments. The values of the investments have been estimated using the capital accounts representing the plan's ownership interest in the funds. Pension Plans The following table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level: Canada US Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2024 Cash and cash equivalents 201 — — 201 57 — — 57 Equity securities 4 Canada — 3 — 3 — — — — Global 134 1,817 — 1,951 27 954 — 981 Fixed income securities 4 Government — 543 — 543 — 194 — 194 Corporate — 838 — 838 — 474 — 474 Alternatives 5 — — 1,464 1,464 — — 488 488 Total pension plan assets at fair value 335 3,201 1,464 5,000 84 1,622 488 2,194 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 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 $77 million (2023 - $61 million) of indirectly held related party equity and fixed income securities investments. 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, 2024 2023 2024 2023 (millions of Canadian dollars) Balance at beginning of year 1,290 1,291 433 445 Unrealized and realized gains/(losses) 104 (41) 63 (12) Purchases and settlements, net 70 40 (8) — Balance at end of year 1,464 1,290 488 433 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, 2024 Cash and cash equivalents 4 — — 4 Equity securities US — 52 — 52 Global — 93 — 93 Fixed income securities Government 71 6 — 77 Corporate — 19 — 19 Alternatives 4 — — 33 33 Total OPEB plan assets at fair value 75 170 33 278 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 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, 2024 2023 (millions of Canadian dollars) Balance at beginning of year 29 28 Unrealized and realized gains 5 1 Purchases and settlements, net (1) — Balance at end of year 33 29 EXPECTED BENEFIT PAYMENTS Year ending December 31, 2025 2026 2027 2028 2029 2030-2034 (millions of Canadian dollars) Pension Canada 214 220 226 232 238 1,285 US 117 120 123 123 120 625 OPEB Canada 11 12 12 12 12 64 US 16 16 16 16 16 71 EXPECTED EMPLOYER CONTRIBUTIONS In 2025, we expect to contribute approximately $21 million and $6 million to the Canadian and US pension plans, respectively, and $11 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 receive a matching contribution where we match a certain percentage of before-tax employee contributions ranging from 3.0% to 7.0% of eligible pay per pay period. For the year ended December 31, 2024, pre-tax employer matching contribution costs were $35 million ($33 million in 2023 and $30 million in 2022).

LEASES

LEASES	12 Months Ended
	Dec. 31, 2024
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 2 months to 41 years as at December 31, 2024. For the years ended December 31, 2024, 2023 and 2022, we incurred operating lease expenses of $132 million, $131 million and $118 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings. For the years ended December 31, 2024, 2023 and 2022, operating lease payments to settle lease liabilities were $128 million, $129 million and $123 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, 2024 December 31, 2023 (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 785 669 Operating lease liabilities - current 3 121 98 Operating lease liabilities - long-term 3 738 652 Total operating lease liabilities 859 750 Finance leases Finance lease right-of-use assets, net 4 294 287 Finance lease liabilities - current 5 16 19 Finance lease liabilities - long-term 5 300 264 Total finance lease liabilities 316 283 Weighted average remaining lease term Operating leases 14 years 12 years Finance leases 31 years 31 years Weighted average discount rate Operating leases 4.8 % 4.5 % Finance leases 5.8 % 5.7 % 1 Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2024 were $42 million (December 31, 2023 - $42 million), $6 million (December 31, 2023 - $5 million) and $37 million (December 31, 2023 - $38 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, 2024, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance (millions of Canadian dollars) 2025 148 31 2026 134 30 2027 123 23 2028 97 23 2029 65 22 Thereafter 685 531 Total undiscounted lease payments 1,252 660 Less imputed interest (393) (344) Total 859 316 LESSOR We receive revenues from operating leases primarily related to natural gas and crude oil storage and processing facilities, and wind power generation assets. Our operating leases have remaining lease terms of 3 months to 27 years as at December 31, 2024. Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Operating lease income 229 241 266 Variable lease income 321 299 321 Total lease income 1 550 540 587 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings. As at December 31, 2024, 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) 2025 221 2026 202 2027 197 2028 198 2029 199 Thereafter 1,415 Future lease payments 2,432
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 2 months to 41 years as at December 31, 2024. For the years ended December 31, 2024, 2023 and 2022, we incurred operating lease expenses of $132 million, $131 million and $118 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings. For the years ended December 31, 2024, 2023 and 2022, operating lease payments to settle lease liabilities were $128 million, $129 million and $123 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, 2024 December 31, 2023 (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 785 669 Operating lease liabilities - current 3 121 98 Operating lease liabilities - long-term 3 738 652 Total operating lease liabilities 859 750 Finance leases Finance lease right-of-use assets, net 4 294 287 Finance lease liabilities - current 5 16 19 Finance lease liabilities - long-term 5 300 264 Total finance lease liabilities 316 283 Weighted average remaining lease term Operating leases 14 years 12 years Finance leases 31 years 31 years Weighted average discount rate Operating leases 4.8 % 4.5 % Finance leases 5.8 % 5.7 % 1 Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2024 were $42 million (December 31, 2023 - $42 million), $6 million (December 31, 2023 - $5 million) and $37 million (December 31, 2023 - $38 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, 2024, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance (millions of Canadian dollars) 2025 148 31 2026 134 30 2027 123 23 2028 97 23 2029 65 22 Thereafter 685 531 Total undiscounted lease payments 1,252 660 Less imputed interest (393) (344) Total 859 316 LESSOR We receive revenues from operating leases primarily related to natural gas and crude oil storage and processing facilities, and wind power generation assets. Our operating leases have remaining lease terms of 3 months to 27 years as at December 31, 2024. Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Operating lease income 229 241 266 Variable lease income 321 299 321 Total lease income 1 550 540 587 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings. As at December 31, 2024, 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) 2025 221 2026 202 2027 197 2028 198 2029 199 Thereafter 1,415 Future lease payments 2,432

OTHER INCOME_(EXPENSE)

OTHER INCOME/(EXPENSE)	12 Months Ended
	Dec. 31, 2024
Other Income and Expenses [Abstract]
OTHER INCOME/(EXPENSE)	OTHER INCOME/(EXPENSE) Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Realized foreign currency gain/(loss) 121 (129) 92 Unrealized foreign currency gain/(loss) (2,199) 821 (1,094) Net defined pension and OPEB credit 188 135 239 Other 564 397 174 (1,326) 1,224 (589)

CHANGES IN OPERATING ASSETS AND

CHANGES IN OPERATING ASSETS AND LIABILITIES	12 Months Ended
	Dec. 31, 2024
CHANGES IN OPERATING ASSETS AND LIABILITIES
CHANGES IN OPERATING ASSETS AND LIABILITIES	CHANGES IN OPERATING ASSETS AND LIABILITIES Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Trade receivables and unbilled revenues (1,638) 1,125 (572) Accounts receivable from affiliates (23) 18 17 Inventory 177 763 (599) Other current and non-current assets (426) 1,301 (394) Trade payables and accrued liabilities 1,383 (1,542) 585 Accounts payable to affiliates (8) (66) 16 Interest payable 157 199 58 Other current and long-term liabilities 245 513 877 (133) 2,311 (12)

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 2022 (millions of Canadian dollars) Transportation and other revenues 181 169 185 Commodity sales — — 51 Operating and administrative 1 637 625 503 Commodity costs 2 22 63 778 Gas distribution costs 147 140 136 1 During the years ended December 31, 2024, 2023 and 2022, we had Operating and administrative costs from the Seaway Crude Pipeline System of $650 million, $632 million and $495 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	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS As at December 31, 2024, 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 14,019 4,260 2,047 1,755 1,535 1,200 3,222 Maintenance agreements 2 452 57 56 57 36 36 210 Right-of-ways commitments 3 981 52 48 53 49 49 730 Total 15,452 4,369 2,151 1,865 1,620 1,285 4,162 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. 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 judgment 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 maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable. In such case, we may decide to self-insure additional risks.

GUARANTEES

GUARANTEES	12 Months Ended
	Dec. 31, 2024
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, 2024, 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
	Dec. 31, 2024
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) 2024 Operating revenues 11,038 11,336 14,882 16,217 53,473 Operating income 2,711 2,273 2,218 2,447 9,649 Earnings 1,565 2,001 1,447 618 5,631 Earnings attributable to controlling interests 1,512 1,943 1,391 595 5,441 Earnings attributable to common shareholders 1,419 1,848 1,293 493 5,053 Earnings per common share Basic 0.67 0.86 0.59 0.23 2.34 Diluted 0.67 0.86 0.59 0.23 2.34 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

Pay vs Performance Disclosure

Pay vs Performance Disclosure - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pay vs Performance Disclosure
Earnings attributable to controlling interests	$ 595	$ 1,391	$ 1,943	$ 1,512	$ 1,818	$ 621	$ 1,935	$ 1,817	$ 5,441	$ 6,191	$ 3,003

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Insider Trading Policies and Pr

Insider Trading Policies and Procedures	12 Months Ended
	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Cybersecurity Risk Management a

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
	Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	Oversight of cybersecurity is integrated into the responsibilities of the Board and its committees. The Board is responsible for identifying and understanding Enbridge’s principal risks and ensuring that appropriate systems are implemented to monitor, manage and mitigate those risks. The committees of the Board have oversight over risks within their respective mandates. The Audit, Finance and Risk Committee (AFRC) provides primary oversight of cybersecurity matters, including with respect to financial risk and controls, integrity of financial data and public disclosures, and security of the cyber landscape across data and digital. Management provides quarterly cybersecurity reports to the AFRC and the Board and also reports to the Safety and Reliability Committee, as deemed necessary, on cybersecurity issues related to safety, reliability and operations. Each year, management prepares and provides to the Board and its committees a corporate risk assessment (CRA), which analyzes and prioritizes enterprise-wide risks, highlighting top risks and trends (including cybersecurity). The annual CRA is an integrated enterprise-wide process which engages each part of our business to assess and rank risks based on impact and probability. We strive to ensure that mitigation measures are appropriately designed, prioritized and resourced. The CRA report is reviewed by the Board committees with responsibility for the risk categories relevant to their mandate and is provided to the Board, which coordinates Enbridge's overall risk management approach. Complementary to the CRA, management prepares and provides to the Safety and Reliability Committee an annual top operational risk report that highlights the highest consequence operational risks across Enbridge and includes further detail on the risks and their treatment. This information helps inform the Board about the potential impact of top operational risks and of treatments in place to manage those risks. Cybersecurity has been identified as a top risk, as attacks against participants in our industry have continued to increase in sophistication and frequency over the years. Although we devote significant resources and security measures to prevent unwanted intrusions and to protect our systems and data, we (and our third-party vendors) have experienced, and expect to continue to experience, cyber attacks of varying degrees in the conduct of our business, including, for example, denial of service attacks. Cybersecurity risk is described in Item 1A. Risk Factors. Enbridge’s management is responsible for the implementation of risk management strategies and monitoring performance. The technology and information services (TIS) function is centralized under the Senior Vice President & Chief Information Officer (CIO). We also engage independent third parties to assess our cybersecurity program, track their recommendations, and use those to further improve the program. Reporting to the CIO is the Chief Information Security Officer who is in charge of our cybersecurity program and oversees the 24x7x365 Security Operations Center (SOC). We conduct continuous assessments of our cybersecurity standards, perform regular tests of our ability to respond and recover, and monitor for potential threats. To further mitigate threats, we collaborate with governments and regulatory agencies and take part in external events to learn and share. Our workforce participates in regular security awareness training, including exercises to build capabilities to identify and report suspect phishing emails to our SOC. In the last year, we continued to expand the cybersecurity training and simulated testing we administer to high-risk groups within the organization. A tailored cybersecurity training course has been implemented for team members in operational technology roles, and we have increased the frequency of phishing simulation tests. We have a cybersecurity third-party risk management program, which is an evolving, cross-functional program to help assess and mitigate risks from third-party vendors and other service providers. Our cybersecurity team also uses several layers of defense and protection technologies, cybersecurity experts, and automated alerting and response mechanisms to reduce risk to Enbridge. Although cybersecurity risks have not materially affected us, including our business strategy, results of operations or financial condition, to date, we have experienced an increasing number of cybersecurity threats in recent years. For more information about the cybersecurity risks we face, see the risk factor entitled " Cyber attacks and other cybersecurity incidents pose threats to our technology systems and could materially adversely affect our business, operations, reputation or financial results." in Item 1A. Risk Factors.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	versight of cybersecurity is integrated into the responsibilities of the Board and its committees. The Board is responsible for identifying and understanding Enbridge’s principal risks and ensuring that appropriate systems are implemented to monitor, manage and mitigate those risks. The committees of the Board have oversight over risks within their respective mandates.
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	The committees of the Board have oversight over risks within their respective mandates.The Audit, Finance and Risk Committee (AFRC) provides primary oversight of cybersecurity matters, including with respect to financial risk and controls, integrity of financial data and public disclosures, and security of the cyber landscape across data and digital. Management provides quarterly cybersecurity reports to the AFRC and the Board and also reports to the Safety and Reliability Committee, as deemed necessary, on cybersecurity issues related to safety, reliability and operations.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	The Audit, Finance and Risk Committee (AFRC) provides primary oversight of cybersecurity matters, including with respect to financial risk and controls, integrity of financial data and public disclosures, and security of the cyber landscape across data and digital. Management provides quarterly cybersecurity reports to the AFRC and the Board and also reports to the Safety and Reliability Committee, as deemed necessary, on cybersecurity issues related to safety, reliability and operations.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	Management provides quarterly cybersecurity reports to the AFRC and the Board and also reports to the Safety and Reliability Committee, as deemed necessary, on cybersecurity issues related to safety, reliability and operations.
Cybersecurity Risk Role of Management [Text Block]	Enbridge’s management is responsible for the implementation of risk management strategies and monitoring performance. The technology and information services (TIS) function is centralized under the Senior Vice President & Chief Information Officer (CIO). We also engage independent third parties to assess our cybersecurity program, track their recommendations, and use those to further improve the program. Reporting to the CIO is the Chief Information Security Officer who is in charge of our cybersecurity program and oversees the 24x7x365 Security Operations Center (SOC).
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	The technology and information services (TIS) function is centralized under the Senior Vice President & Chief Information Officer (CIO).
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	The technology and information services (TIS) function is centralized under the Senior Vice President & Chief Information Officer (CIO).
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	Each year, management prepares and provides to the Board and its committees a corporate risk assessment (CRA), which analyzes and prioritizes enterprise-wide risks, highlighting top risks and trends (including cybersecurity). The annual CRA is an integrated enterprise-wide process which engages each part of our business to assess and rank risks based on impact and probability. We strive to ensure that mitigation measures are appropriately designed, prioritized and resourced. The CRA report is reviewed by the Board committees with responsibility for the risk categories relevant to their mandate and is provided to the Board, which coordinates Enbridge's overall risk management approach. Complementary to the CRA, management prepares and provides to the Safety and Reliability Committee an annual top operational risk report that highlights the highest consequence operational risks across Enbridge and includes further detail on the risks and their treatment. This information helps inform the Board about the potential impact of top operational risks and of treatments in place to manage those risks.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

SIGNIFICANT ACCOUNTING POLICI_2

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2024
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 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 British Columbia (BC) Energy Regulator, the Ontario Energy Board (OEB), the Québec Régie de l’énergie, the Public Utilities Commission of Ohio (Ohio Commission), the North Carolina Utilities Commission (North Carolina Commission), the Utah Public Service Commission (Utah Commission), the Wyoming Public Service Commission (Wyoming Commission), and the Idaho Public Utilities Commission (Idaho Commission). 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 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. We believe that the recovery of our regulatory assets as at December 31, 2024 is probable over the periods described in Note 7 - Regulatory Matters . During the fourth quarter of 2023, Southern Lights Pipeline completed an open season to negotiate new transportation service agreements. We did not renew the agreements under a cost-of-service toll methodology, therefore Southern Lights Pipeline was 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 in 2023. We collect and set aside funds to cover future pipeline abandonment costs for all CER-regulated pipelines in accordance with the Land Matters Consultation Initiative (LMCI) to fund future pipeline decommissioning costs in the state of Minnesota and to satisfy retirement obligations as Wexpro properties are abandoned. The funds collected are held in trusts in accordance with applicable regulations. The funds collected from customers are reported within Operating revenues in the Consolidated Statements of Earnings and Restricted long-term investments and cash in the Consolidated Statements of Financial Position. Concurrently, for LMCI, 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 portion 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, 2024, 2023 and 2022, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $97 million, $210 million and $238 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 generally 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. Certain of our US gas utilities have a revenue decoupling mechanism, referred to as a Customer Usage Tracker (CUT) or Conservation Enabling Tariff (CET), which allows for the collection of an allowed monthly revenue per customer and to promote energy conservation. Under the mechanism, non-gas revenues are decoupled from the temperature-adjusted usage per customer. The difference between actual revenue and the allowed monthly revenue per customer is recorded as a regulatory asset or liability and recovered from, or refunded to, customers through periodic rate adjustments. Amounts deferred under the CUT or CET arise due to specific arrangements with the regulators rather than customers and represent alternative revenue programs. Revenue from alternative revenue programs is recorded within Operating revenues in the Consolidated Statements of Earnings in the month the related adjustments are deferred and is presented as Other revenues not from contracts with customers when disaggregated in Note 4 - Revenue . Our crude oil, natural gas and power marketing businesses enter 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 mitigate 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 and interest rates. 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 may use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates and interest rates. 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 and Financing 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 and Cash	RESTRICTED LONG-TERM INVESTMENTS AND CASH Long-term investments and cash that are restricted as to withdrawal or usage, for the purposes of funding pipeline abandonment in accordance with the CER's LMCI, to cover future pipeline decommissioning costs in the state of Minnesota, and to satisfy retirement obligations as Wexpro properties are abandoned, are presented as Restricted long-term investments and cash in the Consolidated Statements of Financial Position. 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.
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.
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 businesses in our Gas Distribution and Storage and Gas Transmission segments, crude oil and natural gas held by our crude oil and natural gas marketing businesses, and materials and supplies. Natural gas held in storage by our Gas Distribution and Storage businesses is recorded at the prices approved by the regulators in the determination of distribution rates. The actual price of gas purchased may differ from the regulator 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 regulators. Commodity inventory held by our crude oil and natural gas marketing businesses is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, commodity 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 life of the asset commencing when it 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 generally not reflected in earnings but are booked as an adjustment to accumulated depreciation. The successful efforts method of accounting is used for cost-of-service reserves developed and produced by Wexpro for gas utility affiliate, Questar. Cost-of-service reserves are properties for which the operations and return on investment are subject to the Wexpro Agreements. Under the successful efforts method, Wexpro capitalizes the costs of acquiring leaseholds, drilling development wells, drilling successful exploratory wells, and purchasing related support equipment and facilities. Geological and geophysical studies are expensed as incurred. Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved natural gas and crude oil reserves.
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 (Note 7) , overfunded defined benefit pension and OPEB plan assets (Note 25) , operating lease ROU assets (Note 26) and long-term gross derivative asset balances (Note 23) .
Intangible Assets	INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, customer relationships and biogas rights agreements. 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. Biogas rights agreements are long-term gas supply agreements with landfill owners of our landfill gas-to-RNG production facilities 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.
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. 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 (including the impact of changes in discount rates and rate base multiple), changes to regulatory environments, capital accessibility, operating income trends (including changes to projected cash flows from operations, expected future capital expenditures and forecasted rate base), 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, 2024, 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. No indicators of goodwill impairment were identified during the remainder of 2024.
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 qualitative or quantitative 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 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 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 certain defined benefit OPEB plans; and • as a component of Deferred amounts and other assets and/or Other long-term liabilities for certain utilities' defined benefit pension plans and OPEB 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 they occur.
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. 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 targets set out under the plan. We also award share-settled RSUs to certain non-executive senior management employees which vest at the completion of a three-year term. Beginning in 2023, share-settled RSUs were also granted to non-executive employees, which vest either one-third annually from the grant date, or following a 12-month period. 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, 2024. ADOPTION OF NEW ACCOUNTING STANDARDS Segment Reporting Effective January 1, 2024, with interim disclosure requirements effective after January 1, 2025, we adopted Accounting Standards Update (ASU) 2023-07 on a retrospective basis beginning on January 1, 2022. The new standard 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 ASU requires entities to disclose the title and position of the individual or the name of the group or committee identified as the CODM. The adoption of this ASU did not have a material impact on our consolidated financial statements. FUTURE ACCOUNTING POLICY CHANGES 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 the presentation of Note 24 - Income Taxes to our consolidated financial statements. Disaggregation of Income Statement Expenses ASU 2024-03 was issued in November 2024 to improve financial reporting by requiring entities to disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. The ASU requires entities to disclose 1) the amounts of (a) purchases of inventory, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, (e) depreciation, depletion and amortization recognized as part of oil and gas producing activities, (f) expense reimbursements included in a relevant expense caption, and (g) selling expenses, and 2) a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. ASU 2024-03 is effective January 1, 2027, with interim period disclosure requirements effective after January 1, 2028 and can be applied either prospectively or retrospectively. We are currently assessing the impact of the new standard on our annual disclosures for the year ending December 31, 2027 and on our interim disclosures beginning in 2028.

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Schedule of Major Products and Services	Major Products and Services Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Eliminations and Other Consolidated Year ended December 31, 2024 (millions of Canadian dollars) Transportation revenue 11,958 5,279 284 — — 17,521 Storage and other revenue 255 573 509 — — 1,337 Gas distribution sales — — 6,734 — — 6,734 Electricity and transmission revenue — — — 189 — 189 Commodity sales — 158 — — — 158 Total revenue from contracts with customers 12,213 6,010 7,527 189 — 25,939 Commodity sales 25,689 99 — — 1,072 26,860 Other revenue 1,2 281 70 4 319 — 674 Intersegment revenue — 20 11 6 (37) — Total revenue 38,183 6,199 7,542 514 1,035 53,473 Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Eliminations and Other Consolidated Year ended December 31, 2023 (millions of Canadian dollars) Transportation revenue 3 11,875 5,302 212 — — 17,389 Storage and other revenue 257 461 355 — — 1,073 Gas distribution sales 3 — — 5,461 — — 5,461 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 17,494 — — — 1,470 18,964 Other revenue 1,2 257 72 (58) 215 — 486 Intersegment revenue (1) 2 6 3 (10) — Total revenue 29,882 5,854 5,976 477 1,460 43,649 Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Eliminations and Other Consolidated Year ended December 31, 2022 (millions of Canadian dollars) Transportation revenue 3 11,283 5,012 198 — — 16,493 Storage and other revenue 235 350 308 — — 893 Gas gathering and processing revenue — 22 — — — 22 Gas distribution sales 3 — — 6,227 — — 6,227 Electricity and transmission revenue — — — 281 — 281 Total revenue from contracts with customers 11,518 5,384 6,733 281 — 23,916 Commodity sales 25,740 — — — 3,410 29,150 Other revenue 1,2 (81) 39 (20) 305 — 243 Intersegment revenue (3) 3 16 (4) (12) — Total revenue 37,174 5,426 6,729 582 3,398 53,309 1 Includes realized and unrealized gains and losses $23 million and losses of $97 million and $431 million for the years ended December 31, 2024, 2023 and 2022, respectively. 2 Includes revenues from lease contracts. Refer to Note 26 - Leases . 3 These balances reflect a transfer from Transportation revenue to Gas distribution sales of $602 million and $584 million for the years ended December 31, 2023 and 2022, respectively. Recognition and Measurement of Revenue Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2024 (millions of Canadian dollars) Revenue from products transferred at a point in time — 158 137 — 295 Revenue from products and services transferred over time 1 12,213 5,852 7,390 189 25,644 Total revenue from contracts with customers 12,213 6,010 7,527 189 25,939 Liquids Pipelines Gas Transmission 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 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 1 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.
Schedule of Contract Balances	Contract Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at December 31, 2024 3,764 330 2,828 Balance as at December 31, 2023 2,802 400 2,591
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 • Transportation, storage, gathering, compression and treating of natural gas • Transportation of crude oil and NGL • Sale of renewable natural gas and its attached environmental attributes 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 Revenue Allocated to Remaining Performance Obligations	The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, that is expected to be recognized in the following periods: Total 1 year 2-5 years Thereafter (billions of Canadian dollars) Expected revenue 62.6 10.4 25.2 27.0

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
Schedule of Reporting Information by Segment	Year ended December 31, 2024 Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Total Reportable Segments (millions of Canadian dollars) Operating revenues 1 38,183 6,199 7,542 514 52,438 Commodity and gas distribution costs (25,283) (130) (2,501) 4 (27,910) Operating and administrative (4,495) (2,322) (2,276) (304) (9,397) Impairment of long-lived assets (2) (162) (3) (23) (190) Income from equity investments 1,051 812 3 455 2,321 Gain on disposition of equity investments (Note 13) — 1,063 — 28 1,091 Other income 77 196 104 59 436 Earnings before interest, income taxes and depreciation and amortization 9,531 5,656 2,869 733 18,789 Eliminations and Other (1,904) Depreciation and amortization (5,167) Interest expense (Note 17) (4,419) Earnings before income taxes 7,299 Year ended December 31, 2023 Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Total Reportable Segments (millions of Canadian dollars) Operating revenues 1 29,882 5,854 5,976 477 42,189 Commodity and gas distribution costs (17,106) (15) (2,871) (20) (20,012) Operating and administrative (4,659) (2,380) (1,285) (261) (8,585) Impairment of long-lived assets 2 145 — (281) (283) (419) Income from equity investments 1,007 688 2 140 1,837 Other income 114 117 51 96 378 Earnings before interest, income taxes and depreciation and amortization 9,383 4,264 1,592 149 15,388 Eliminations and Other 916 Depreciation and amortization (4,613) Interest expense (Note 17) (3,812) Earnings before income taxes 7,879 Year ended December 31, 2022 Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Total Reportable Segments (millions of Canadian dollars) Operating revenues 1 37,174 5,426 6,729 582 49,911 Commodity and gas distribution costs (25,495) — (3,693) (16) (29,204) Operating and administrative (4,318) (2,254) (1,289) (255) (8,116) Impairment of long-lived assets (258) — — (235) (493) Impairment of goodwill — (2,465) — — (2,465) Income from equity investments 785 1,133 1 141 2,060 Gain on joint venture merger transaction (Note 13) — 1,076 — — 1,076 Other income 53 210 79 45 387 Earnings before interest, income taxes and depreciation and amortization 7,941 3,126 1,827 262 13,156 Eliminations and Other (1,118) Depreciation and amortization (4,317) Interest expense (Note 17) (3,179) Earnings before income taxes 4,542 1 Refer to Note 4 - Revenue for a reconciliation of segment Operating revenues to the Consolidated Statements of Earnings. 2 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) . Capital Expenditures 1 Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Liquids Pipelines 1,157 1,158 1,418 Gas Transmission 2,571 1,944 1,690 Gas Distribution and Storage 2,386 1,451 1,499 Renewable Power Generation 661 100 50 Eliminations and Other 59 55 33 6,834 4,708 4,690 1 Includes the equity component of the AFUDC. Property, Plant and Equipment Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Liquids Pipelines 53,863 51,855 53,573 Gas Transmission 34,683 31,016 29,666 Gas Distribution and Storage 38,636 18,766 17,857 Renewable Power Generation 3,612 2,706 3,082 Eliminations and Other 310 298 282 131,104 104,641 104,460 The measurement basis for preparation of segmented information is consistent with our significant accounting policies (Note 2) .
Schedule of Revenues by Geographical Segments	GEOGRAPHIC INFORMATION Revenues 1 Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Canada 22,001 23,781 27,498 US 31,472 19,868 25,811 53,473 43,649 53,309 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, 2024 2023 (millions of Canadian dollars) Canada 48,873 48,570 US 82,231 56,071 131,104 104,641 1 Amounts are based on the location where the assets are held.

EARNINGS PER COMMON SHARE (Tabl

EARNINGS PER COMMON SHARE (Tables)	12 Months Ended
	Dec. 31, 2024
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 common share are as follows: December 31, 2024 2023 2022 (number of shares in millions) Weighted average shares outstanding 2,155 2,056 2,025 Effect of dilutive options and RSUs 3 2 4 Diluted weighted average shares outstanding 2,158 2,058 2,029

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Purchase gas variance 74 15 2025 Under-recovery of fuel costs 4 75 2025 Deferred projects costs 1 90 — 2025 Other current regulatory assets 304 380 2025 Total current regulatory assets 2 (Note 9) 472 470 Long-term regulatory assets Deferred income taxes 3 4,698 4,456 Various Deferred projects costs 1 1,045 — Various Long-term debt 4 318 348 2032-2046 Negative salvage 5 136 180 Various Demand-side management costs 237 54 Various Pension plan receivable 6 266 1 Various Other long-term regulatory assets 447 198 Various Total long-term regulatory assets 2 7,147 5,237 Total regulatory assets 7,619 5,707 Current regulatory liabilities Purchase gas variance 292 31 2025 Regulatory liability related to US income taxes 7 44 — 2025 Other current regulatory liabilities 280 276 2025 Total current regulatory liabilities 8 (Note 16) 616 307 Long-term regulatory liabilities Future removal and site restoration reserves 9 2,964 1,693 Various Regulatory liability related to US income taxes 7 2,021 854 Various Pipeline future abandonment costs (Note 23) 826 745 Various Pension plan payable 6 59 143 Various Other long-term regulatory liabilities 242 86 Various Total long-term regulatory liabilities 8 6,112 3,521 Total regulatory liabilities 6,728 3,828 1 Represents the amounts anticipated to be collected from customers in East Ohio’s service areas for rider projects, including CEP, PIR and costs related to the Pipeline Safety Management Program. The recovery periods for these expenditures vary according to the stipulations outlined in the respective riders. For Enbridge Gas North Carolina, these amounts relate to pipeline integrity management which represent operating costs incurred to comply with federal regulatory requirements related to natural gas pipelines and have been deferred pending future approval of rate recovery. 2 Current regulatory assets are included in Other current assets, while long-term regulatory assets are included in Deferred amounts and other assets. 3 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, 2024 is net of regulatory deferred tax write-offs. 4 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. 5 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. 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 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 for our US Gas Transmission pipelines and by the respective state utility commission for each US Gas Distribution franchise. 8 Current regulatory liabilities are included in Other current liabilities, while long-term regulatory liabilities are included in Other long-term liabilities. 9 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the respective regulatory authorities, 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.
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, 2024 2023 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Purchase gas variance 74 15 2025 Under-recovery of fuel costs 4 75 2025 Deferred projects costs 1 90 — 2025 Other current regulatory assets 304 380 2025 Total current regulatory assets 2 (Note 9) 472 470 Long-term regulatory assets Deferred income taxes 3 4,698 4,456 Various Deferred projects costs 1 1,045 — Various Long-term debt 4 318 348 2032-2046 Negative salvage 5 136 180 Various Demand-side management costs 237 54 Various Pension plan receivable 6 266 1 Various Other long-term regulatory assets 447 198 Various Total long-term regulatory assets 2 7,147 5,237 Total regulatory assets 7,619 5,707 Current regulatory liabilities Purchase gas variance 292 31 2025 Regulatory liability related to US income taxes 7 44 — 2025 Other current regulatory liabilities 280 276 2025 Total current regulatory liabilities 8 (Note 16) 616 307 Long-term regulatory liabilities Future removal and site restoration reserves 9 2,964 1,693 Various Regulatory liability related to US income taxes 7 2,021 854 Various Pipeline future abandonment costs (Note 23) 826 745 Various Pension plan payable 6 59 143 Various Other long-term regulatory liabilities 242 86 Various Total long-term regulatory liabilities 8 6,112 3,521 Total regulatory liabilities 6,728 3,828 1 Represents the amounts anticipated to be collected from customers in East Ohio’s service areas for rider projects, including CEP, PIR and costs related to the Pipeline Safety Management Program. The recovery periods for these expenditures vary according to the stipulations outlined in the respective riders. For Enbridge Gas North Carolina, these amounts relate to pipeline integrity management which represent operating costs incurred to comply with federal regulatory requirements related to natural gas pipelines and have been deferred pending future approval of rate recovery. 2 Current regulatory assets are included in Other current assets, while long-term regulatory assets are included in Deferred amounts and other assets. 3 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, 2024 is net of regulatory deferred tax write-offs. 4 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. 5 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. 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 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 for our US Gas Transmission pipelines and by the respective state utility commission for each US Gas Distribution franchise. 8 Current regulatory liabilities are included in Other current liabilities, while long-term regulatory liabilities are included in Other long-term liabilities. 9 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the respective regulatory authorities, 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.

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Tables)	12 Months Ended
	Dec. 31, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]
Schedule 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 PSNC: September 30, 2024 1 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 303 Property, plant and equipment (b) 4,147 Long-term assets (c) 189 Current liabilities 277 Long-term debt (d) 1,529 Other long-term liabilities (e) 653 Deferred income tax liabilities 365 Goodwill (f) 895 Purchase price: Cash 2,710 1 In the fourth quarter of 2024, immaterial adjustments were made to the PSNC Acquisition purchase price allocation. a) Current assets consist primarily of cash, trade and other accounts receivable, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $70 million due to the short period to maturity. A provision of $2 million for expected credit loss associated with accounts receivable has been recorded. b) PSNC's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, distribution and storage assets. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value. c) Long-term assets consist primarily of $114 million of regulatory assets expected to be recovered from customers in future periods through rates and equity interests in a liquefied natural gas (LNG) storage facility in North Carolina and in an intrastate natural gas pipeline. d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $156 million with no corresponding regulatory offset. e) Other long-term liabilities consist primarily of regulatory liabilities expected to be refunded to customers in future periods through rates. f) Goodwill is primarily attributable to the existing assembled assets and workforce of PSNC that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides a platform for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible. The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Questar and Wexpro: May 31, 2024 1 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 380 Property, plant and equipment (b) 6,013 Long-term assets (c) 163 Current liabilities 416 Long-term debt (d) 1,343 Other long-term liabilities (e) 919 Deferred income tax liabilities 527 Goodwill (f) 793 Purchase price: Cash 4,144 1 In the fourth quarter of 2024, immaterial adjustments were made to the Questar Acquisition purchase price allocation. a) Current assets consist primarily of cash, trade and other accounts receivable and inventory. The fair value of trade receivables from customers approximates their carrying value of $202 million due to the short period to maturity. A provision of $9 million for expected credit loss associated with accounts receivable has been recorded. b) Questar's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, distribution and storage assets. Wexpro's property, plant and equipment consists of cost-of-service gas and oil properties developed and produced for Questar. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value. c) Long-term assets consist primarily of funds collected from Questar by Wexpro and held in trust to fund future AROs, as well as regulatory assets expected to be recovered from customers in future periods through rates. d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $301 million with no corresponding regulatory offset. e) Other long-term liabilities consist primarily of regulatory liabilities, expected to be refunded to customers in future periods through rates, as well as ARO. The fair value of the ARO liability was determined using a discounted cash flow approach. f) Goodwill is primarily attributable to the existing assembled assets and workforce of Questar and Wexpro that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides a platform for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible. The following table summarizes the estimated preliminary fair values that were assigned to the net assets of EOG: March 6, 2024 1 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 493 Property, plant and equipment (b) 7,276 Long-term assets (c) 1,689 Current liabilities 551 Long-term debt (d) 2,612 Other long-term liabilities (e) 1,001 Deferred income tax liabilities 1,045 Goodwill (f) 1,603 Purchase price: Cash 5,852 1 In the fourth quarter of 2024, immaterial adjustments were made to the EOG Acquisition purchase price allocation. a) Current assets consist primarily of trade and other accounts receivable, prepaid expenses, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $379 million due to the short period to maturity. A provision of $3 million for expected credit loss associated with accounts receivable has been recorded. b) EOG's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, gathering, distribution and storage assets. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value. c) Long-term assets consist primarily of overfunded pension plan assets of $367 million and $1.2 billion of regulatory assets expected to be recovered from customers in future periods through rates. Pension plan assets attributable to the workforce acquired from EOG were transferred in cash to an Enbridge-sponsored pension plan based on their fair value as at March 6, 2024. The fair value of plan assets was determined using unadjusted quoted market prices for identical investments. d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $478 million with no corresponding regulatory offset. e) Other long-term liabilities consist primarily of regulatory liabilities expected to be refunded to customers in future periods through rates. f) Goodwill is primarily attributable to the existing assembled assets and workforce of EOG that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides a platform for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible. The following table summarizes the estimated fair values that were assigned to the net assets of Tomorrow RNG: January 2, 2024 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 31 Intangible assets (a) 925 Property, plant and equipment (b) 174 Current liabilities 5 Goodwill (c) 223 Purchase price: Cash 584 Deferred consideration (d): Current portion of long-term debt 550 Long-term debt 207 Other adjustments 7 1,348 a) Intangible assets consist of long-term gas supply agreements with the respective facility's landfill owner. Fair value was determined using an income-based approach, specifically the multi-period excess earnings method, by estimating the present value of the after-tax cash flows attributable to the gas rights. The intangible assets will be amortized on a straight-line basis over the term of the respective agreement, inclusive of extension options, which range from 13 to 42 years (approximately nine years to the next extension period on a weighted-average basis). b) Tomorrow RNG's property, plant and equipment constitutes specialized landfill gas plant and equipment which collects gas produced by waste decomposition, treats and compresses the gas to pipeline specifications. The direct method of replacement cost was used to determine the majority of the fair value of property, plant and equipment. Adjustments were then applied for estimated physical deterioration. c) Goodwill is primarily attributable to expected future returns from a portfolio of both operating and scalable RNG assets, furthering the diversity of our renewable projects portfolio and accelerating progress toward our energy transition goals. The goodwill balance recognized has been assigned to our Gas Transmission segment and is tax deductible over 15 years. d) We entered into six non-interest bearing promissory notes due to Morrow Renewables, the total value of which represents deferred payments of $808 million (US$606 million) due within two years. The first and second payments are due on January 2, 2025 and December 31, 2025, respectively. The $757 million (US$568 million) recognized in the purchase price represents the fair value of deferred consideration at the date of acquisition using the imputed interest rate method over the terms of the notes. The following table summarizes the estimated 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 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 $72 million (US$53 million) to TGE's former common unit holders if performance milestones were met on certain projects. The $49 million (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.
Schedule of Supplemental Pro Forma Consolidated Financial Information	Our supplemental pro forma consolidated financial information for the years ended December 31, 2024 and 2023, including the results of operations for PSNC as if the PSNC Acquisition had been completed on January 1, 2023, is as follows: Year ended December 31, 2024 2023 (unaudited; millions of Canadian dollars) Operating revenues 54,116 44,614 Earnings attributable to common shareholders 1 5,149 5,944 1 Includes adjustment for pro forma interest expense on debt financing for the PSNC Acquisition of $48 million (after-tax of $37 million) for the year ended December 31, 2023. Our supplemental pro forma consolidated financial information for the years ended December 31, 2024 and 2023, including the results of operations for Questar and Wexpro as if the Questar Acquisition had been completed on January 1, 2023, is as follows: Year ended December 31, 2024 2023 (unaudited; millions of Canadian dollars) Operating revenues 54,698 45,918 Earnings attributable to common shareholders 1 5,193 6,005 1 Includes adjustment for pro forma interest expense on debt financing for the Questar Acquisition of $70 million (after-tax of $53 million) for the year ended December 31, 2023. Our supplemental pro forma consolidated financial information for the years ended December 31, 2024 and 2023, including the results of operations for EOG as if the EOG Acquisition had been completed on January 1, 2023, is as follows: Year ended December 31, 2024 2023 (unaudited; millions of Canadian dollars) Operating revenues 53,788 45,058 Earnings attributable to common shareholders 1 5,130 5,961 1 Includes adjustment for pro forma interest expense on debt financing for the EOG Acquisition of $100 million (after-tax of $77 million) for the year ended December 31, 2023.

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2024
Receivables [Abstract]
Schedule of Other Current Assets	December 31, 2024 2023 (millions of Canadian dollars) Derivative assets (Note 23) 557 623 Regulatory assets (Note 7) 472 470 Gas imbalances 517 209 Income taxes receivable 375 347 Other 849 791 2,770 2,440

INVENTORY (Tables)

INVENTORY (Tables)	12 Months Ended
	Dec. 31, 2024
Inventory Disclosure [Abstract]
Schedule of Inventory	December 31, 2024 2023 (millions of Canadian dollars) Natural gas 811 938 Crude oil 479 413 Other 198 128 1,488 1,479

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant And Equipment	Weighted Average December 31, Depreciation Rate 2024 2023 (millions of Canadian dollars) Pipelines 2.9 % 73,633 66,698 Facilities and equipment 3.2 % 43,439 37,634 Land and right-of-way 1 2.8 % 4,181 3,600 Gas mains, services and other 3.0 % 26,925 15,346 Storage 2.6 % 6,455 4,929 Wind turbines, solar panels and other 3.9 % 4,798 4,511 Other 8.6 % 3,987 1,652 Under construction — % 5,648 2,829 Total property, plant and equipment 2 169,066 137,199 Total accumulated depreciation 2 (37,962) (32,558) Property, plant and equipment, net 131,104 104,641 1 The measurement of weighted average depreciation rate excludes non-depreciable assets. 2 As at December 31, 2024, the cost and accumulated depreciation of leased assets accounted for as lessor operating leases was $5.3 billion and $2.3 billion, respectively (December 31, 2023 - $5.1 billion and $2.1 billion, respectively).

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Assets and Liabilities of Consolidated VIEs	The following table includes assets only 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, 2024 2023 (millions of Canadian dollars) Assets Current assets Cash and cash equivalents 448 442 Restricted cash 11 9 Trade receivables and unbilled revenues 138 144 Other current assets 5 8 Accounts receivable from affiliates 13 5 Inventory 13 11 628 619 Property, plant and equipment, net 6,934 7,105 Long-term investments 20 14 Restricted long-term investments and cash 141 106 Deferred amounts and other assets 145 148 Intangible assets, net 77 84 7,945 8,076 Liabilities Current liabilities Trade payables and accrued liabilities 108 83 Other current liabilities 124 145 Accounts payable to affiliates 22 4 254 232 Long-term debt — 1 Other long-term liabilities 1,133 971 Deferred income taxes 6 5 1,393 1,209 6,552 6,867
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, 2024 and 2023 are as follows: Carrying Maximum December 31, 2024 the VIE Loss (millions of Canadian dollars) Rampion Offshore Wind Limited 1 387 490 Vector Pipeline 2 193 314 Woodfibre LNG Limited Partnership 3 1,275 3,153 Whistler Parent JV 4 1,102 1,425 Other 3 168 501 3,125 5,883 Carrying Maximum December 31, 2023 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 5 105 130 Rampion Offshore Wind Limited 1 391 452 Vector Pipeline 2 191 320 Woodfibre LNG Limited Partnership 3 778 2,854 Fox Squirrel Solar LLC 6 312 661 Other 3 132 230 1,909 4,647 1 As at December 31, 2024 and 2023, our maximum exposure to loss includes parental guarantees that have been committed in project contracts in which we would be liable for in the event of default by the VIE and the carrying value of an affiliate dividend receivable of $73 million and nil, respectively. 2 Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US. As at December 31, 2024 and 2023, our maximum exposure to loss includes the carrying value of outstanding affiliate loans receivable of $16 million and $24 million, respectively, and our share of the VIE's available credit facility for $105 million. 3 As at December 31, 2024 and 2023, our maximum exposure to loss includes parental guarantees and funding obligations that have been committed in connection with the projects for which we would be liable in the event of default by the VIE(s). 4 In May 2024, Enbridge formed a joint venture (the Whistler Parent JV) in which we hold a 19.0% interest. Refer to Note 13 - Long-Term Investments . As at December 31, 2024, our maximum exposure to loss includes funding obligations that have been committed in project contracts in which we would be liable for in the event of default by the VIE. 5 In April 2024, Enbridge sold its interest in Aux Sable Liquid Products L.P. Refer to Note 13 - Long-Term Investments . As at December 31, 2023, our maximum exposure to loss included a guarantee by us for our respective share of the VIE's borrowing on a bank credit facility. 6 In November 2023, Enbridge acquired a 50.0% interest in Fox Squirrel Solar LLC. Refer to Note 13 - Long-Term Investments . As at December 31, 2024, Fox Squirrel Solar LLC no longer met the requirements of a VIE as a result of a VIE reconsideration event. As at December 31, 2023, our maximum exposure to loss included parental guarantees that had been committed in project contracts in which we would be liable for in the event of default by the VIE.

LONG-TERM INVESTMENTS (Tables)

LONG-TERM INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Long-Term Investments	December 31, Ownership 2024 2023 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines Cactus II Pipeline LLC 30.0 % 651 618 DCP Midstream, LLC (Class B Units) 1 90.0 % 1,554 1,486 Illinois Extension Pipeline Company, L.L.C. 65.0 % 608 584 MarEn Bakken Company LLC 2 75.0 % 2,296 1,819 Seaway Crude Holdings LLC 50.0 % 2,820 2,661 Other 30.0 % - 43.8 % 96 84 Gas Transmission Alliance Pipeline 3,5 50.0 % — 359 Aux Sable 4,5 42.7 % - 50.0 % — 229 DCP Midstream, LLC (Class A Units) 6 23.4 % 480 367 Delaware Basin Residue, LLC 7 15.0 % 319 — Gulfstream Natural Gas System, L.L.C. 50.0 % 1,316 1,224 NEXUS Gas Transmission, LLC 50.0 % 1,301 1,220 Sabal Trail Transmission, LLC 50.0 % 1,565 1,467 Southeast Supply Header, LLC 50.0 % 355 80 Steckman Ridge, LP 50.0 % 101 87 Vector Pipeline 60.0 % 193 191 Whistler Parent JV 8 19.0 % 1,102 — Woodfibre LNG Limited Partnership 30.0 % 1,275 777 Offshore - various joint ventures 22.0 % - 74.3 % 260 217 Other 21.3 % - 45.0 % 49 — Gas Distribution and Storage Other 17.0 % - 50.0 % 67 22 Renewable Power Generation East-West Tie Limited Partnership 24.1 % 106 132 EIH S.à r.l. 9 51.0 % 89 52 Fox Squirrel Solar LLC 50.0 % 783 312 Hohe See and Albatros Offshore Wind Facilities 49.9 % 1,606 1,701 Rampion Offshore Wind Limited 24.9 % 387 391 Other 16.4 % - 50.0 % 93 110 OTHER LONG-TERM INVESTMENTS Gas Transmission Ara Divert HoldCo, Inc. 116 106 Other 23 22 Gas Distribution and Storage Other 27 24 Renewable Power Generation Other 21 21 Eliminations and Other Other 10 1,032 430 20,691 16,793 1 We own 90.0% of the Class B units of DCP Midstream, LLC. This class of units represents DCP Midstream, LLC's 65.0% interest in Gray Oak Pipeline, LLC (Gray Oak), resulting in a 58.5% interest in Gray Oak through DCP Midstream, LLC. 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%. 2 MarEn Bakken Company LLC 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. 3 Includes Alliance Pipeline Limited Partnership in Canada and Alliance Pipeline L.P. in the US. 4 Includes Aux Sable Canada LP in Canada and Aux Sable Liquid Products L.P. and Aux Sable Midstream LLC in the US. 5 On April 1, 2024, we closed the sale of our 50.0% equity interest in the Alliance Pipeline and our interest in Aux Sable to Pembina Pipeline Corporation for $3.1 billion, including $0.3 billion of non-recourse debt. 6 We own 23.4% of the Class A units of DCP Midstream, LLC. These units represent DCP Midstream, LLC's 56.5% interest in DCP Midstream, LP (DCP), resulting in a 13.2% effective interest in DCP by us. 7 On October 31, 2024, we acquired an effective 15.0% interest in Delaware Basin Residue, LLC (DBR) for consideration of $303 million (US$220 million). DBR owns transportation and storage assets in West Texas, serving as the primary supply point for the Whistler Pipeline. 8 On May 29, 2024, we formed a joint venture with WhiteWater/I Squared Capital and MPLX LP. We hold a 19.0% interest in the joint venture, which owns a 100% interest in the Rio Bravo Pipeline project. Additionally, we have a 25.0% special interest in the Rio Bravo Pipeline project, resulting in a 39.3% effective interest in the Rio Bravo Pipeline project by us. 9 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%). 10 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, 2024 2023 2022 (millions of Canadian dollars) Operating revenues 20,657 22,586 30,026 Operating expenses 14,692 17,111 23,835 Earnings 5,177 4,818 5,123 Earnings attributable to Enbridge 2,304 1,816 2,056 December 31, 2024 2023 (millions of Canadian dollars) Current assets 8,611 5,842 Non-current assets 69,381 61,141 Current liabilities 7,240 6,194 Non-current liabilities 27,491 23,957 Noncontrolling interests 4,979 4,124

INTANGIBLE ASSETS (Tables)

INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Intangible Assets	December 31, 2024 Weighted Average Amortization Rate Cost Accumulated Amortization Net (millions of Canadian dollars) Software 10.9 % 2,109 (1,222) 887 Power purchase agreements 4.5 % 58 (26) 32 Project agreement 1 4.0 % 173 (52) 121 Customer relationships 8.6 % 2,856 (975) 1,881 Biogas rights agreements 3.4 % 999 (34) 965 Other intangible assets 5.8 % 665 (234) 431 Under development — % 270 — 270 7,130 (2,543) 4,587 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 1 Represents a project agreement acquired from the merger of Enbridge and Spectra Energy.

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	Liquids Pipelines Gas Transmission Gas Distribution and Storage Renewable Power Generation Consolidated (millions of Canadian dollars) Balance at January 1, 2023 8,549 18,106 5,397 388 32,440 Foreign exchange and other (205) (425) — (8) (638) Acquisition 3 — 46 — — 46 Balance at December 31, 2023 1,2 8,344 17,727 5,397 380 31,848 Dispositions 4 — (1,026) — — (1,026) Foreign exchange and other 672 1,354 204 34 2,264 Acquisitions 5 — 223 3,291 — 3,514 Balance at December 31, 2024 1,2 9,016 18,278 8,892 414 36,600 1 Gross goodwill as at December 31, 2024 and 2023 was $40.7 billion and $35.9 billion, respectively. 2 Accumulated impairment as at December 31, 2024 and 2023 was $4.1 billion. 3 In 2023, we recorded $46 million of goodwill related to the acquisition of Aitken Creek. Refer to Note 8 - Acquisitions and Disposition . 4 In 2024, we derecognized $1.0 billion of goodwill related to the sale of our interests in the Alliance Pipeline and Aux Sable. Refer to Note 13 - Long-Term Investments . 5 In 2024, we recorded $895 million of goodwill related to the PSNC Acquisition, $793 million of goodwill related to the Questar Acquisition, $1.6 billion of goodwill related to the EOG Acquisition, and $223 million of goodwill related to the RNG Facilities Acquisition. Refer to Note 8 - Acquisitions and Disposition .

OTHER CURRENT LIABILITIES (Tabl

OTHER CURRENT LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2024
Payables and Accruals [Abstract]
Schedule of Other Current Liabilities	December 31, 2024 2023 (millions of Canadian dollars) Dividends payable 2,088 1,975 Deferred credits 1,072 1,177 Derivative liabilities (Note 23) 1,335 738 Taxes payable 959 596 Regulatory liabilities (Note 7) 616 307 Federal carbon program liability 498 376 Asset retirement obligations (Note 18) 120 136 Other 553 354 7,241 5,659

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
Schedule of Debt	December 31, Weighted Average Interest Rate 8 Maturity 2024 2023 (millions of Canadian dollars) Enbridge Inc. US dollar senior notes 4.8 % 2025 - 2054 19,703 14,636 Medium-term notes 4.5 % 2025 - 2064 9,900 8,598 Sustainability-linked bonds 4.7 % 2032 - 2033 7,146 6,751 Fixed-to-fixed subordinated term notes 1 7.4 % 2054 - 2084 9,372 7,156 Fixed-to-floating rate subordinated term notes 2 5.8 % 2077 - 2078 6,139 5,828 Floating rate notes — 791 Fixed-to-floating non-call notes — 923 Commercial paper and credit facility draws 3.7 % 2025 - 2029 5,843 3,177 Other 3 12 17 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 4.8 % 2026 - 2029 4,707 670 Other 3 276 263 Enbridge Energy Partners, L.P. Senior notes 6.5 % 2025 - 2045 3,524 3,231 Enbridge Gas Inc. Medium-term notes 4.1 % 2025 - 2053 9,970 10,185 Debentures 8.7 % 2025 125 210 Commercial paper and credit facility draws 3.4 % 2026 530 400 Other 3 1 2 Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 4.0 % 2040 736 791 Enbridge Pipelines Inc. Medium-term notes 4 4.2 % 2025 - 2053 5,425 5,425 Debentures — 200 Commercial paper and credit facility draws 3.8 % 2026 509 449 Other 3 2 4 Enbridge Southern Lights LP Senior notes 4.0 % 2040 183 214 Spectra Energy Capital, LLC Senior notes 7.1 % 2032 - 2038 248 228 Algonquin Gas Transmission, LLC Senior notes 4.4 % 2029 - 2034 1,222 1,121 East Tennessee Natural Gas, LLC Senior notes 5.7 % 2034 662 251 Texas Eastern Transmission, LP Senior notes 4.7 % 2028 - 2048 3,667 3,362 Spectra Energy Partners, LP Senior notes 4.2 % 2025 - 2045 3,164 4,220 Blauracke GmbH Senior notes 2.1 % 2032 471 521 The East Ohio Gas Company Senior notes 3.1 % 2025 - 2052 3,308 — Other 3 24 — Questar Gas Company Senior notes 4.2 % 2027 - 2052 2,028 — Public Service Company of North Carolina, Incorporated Senior notes 5.0 % 2026 - 2054 1,798 — Enbridge Holdings (Tomorrow RNG), LLC Senior notes 4.9 % 2025 817 — Westcoast Energy Inc. Medium-term notes 5.4 % 2025 - 2041 875 1,225 Debentures 8.1 % 2025 - 2026 275 275 Fair value adjustment (468) 514 Other 5 (522) (439) Total debt 6 101,672 81,199 Current maturities (7,729) (6,084) Short-term borrowings 7 (529) (400) Long-term debt 93,414 74,715 1 For an initial five 2 For an initial five 3 Primarily finance lease obligations. 4 Included in medium-term notes is $100 million with a maturity date of 2112. 5 Primarily unamortized discounts, premiums and debt issuance costs. 6 2024 - $40 billion, US$43 billion and €316 million; 2023 - $37 billion, US$33 billion and €359 million. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment. 7 Weighted average interest rates on outstanding commercial paper were 3.4% as at December 31, 2024 (2023 - 5.2%). 8 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2024.
Schedule of Committed Credit Facilities	The following table provides details of our committed credit facilities as at December 31, 2024: Maturity 1 Total Facilities Draws 2 Available (millions of Canadian dollars) Enbridge Inc. 2025-2049 8,840 5,843 2,997 Enbridge (U.S.) Inc. 2026-2029 10,813 4,707 6,106 Enbridge Pipelines Inc. 2026 2,000 509 1,491 Enbridge Gas Inc. 2026 2,500 530 1,970 Total committed credit facilities 24,153 11,589 12,564 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, 2024, we completed the following long-term debt issuances totaling US$5.7 billion and $1.8 billion: Company Issue Date Principal Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. April 2024 5.25% senior notes due April 2027 US$750 April 2024 5.30% senior notes due April 2029 US$750 April 2024 5.63% senior notes due April 2034 US$1,200 April 2024 5.95% senior notes due April 2054 US$800 June 2024 7.38% fixed-to-fixed subordinated notes due March 2055 1 US$500 June 2024 7.20% fixed-to-fixed subordinated notes due June 2054 2 US$700 August 2024 4.21% medium-term notes due February 2030 $600 August 2024 4.73% medium-term notes due August 2034 $800 August 2024 5.32% medium-term notes due August 2054 $400 Algonquin Gas Transmission, LLC July 2024 5.95% senior notes due July 2034 US$350 East Tennessee Natural Gas, LLC December 2024 5.72% senior notes due December 2034 US$460 Questar Gas Company December 2024 5.33% senior notes due December 2034 US$200 1 For the initial 5.5 years, the notes carry a fixed interest rate. On March 15, 2030, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.12%. 2 For the initial 9.75 years, the notes carry a fixed interest rate. On June 27, 2034, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 2.97%.
Schedule of Long-Term Debt Repayments	During the year ended December 31, 2024, we completed the following long-term debt repayments totaling US$3.9 billion, $1.4 billion, and €43 million, respectively: Company Repayment Date Principal Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. February 2024 Floating rate notes 1 US$600 February 2024 2.15% senior notes US$400 March 2024 5.97% senior notes 2 US$700 June 2024 3.50% senior notes US$500 November 2024 3.95% medium-term notes $500 Enbridge Gas Inc. August 2024 3.15% medium-term notes $215 December 2024 9.85 % debentures $85 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2024 3.98% senior notes US$89 Enbridge Pipelines Inc. February 2024 8.20% debentures $200 Enbridge Southern Lights LP January, July and December 2024 4.01% senior notes $31 Westcoast Energy Inc. September 2024 3.43% medium-term notes $350 Spectra Energy Partners, LP March 2024 4.75% senior notes US$1,000 Blauracke GmbH April and October 2024 2.10% senior notes €43 Algonquin Gas Transmission, LLC July 2024 3.51% senior notes US$350 Questar Gas Company December 2024 2.98% senior notes US$40 East Tennessee Natural Gas, LLC December 2024 3.10% senior notes US$190 1 Notes carried an interest rate set to equal the SOFR plus a margin of 63 basis points. 2 The notes carried an original maturity date in March 2026, and were callable in March 2024, which was one year after their issuance.
Schedule of Maturities	As at December 31, 2024, 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 1 101,819 7,724 7,379 4,704 3,056 13,578 65,378 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, 2024 2023 2022 (millions of Canadian dollars) Debentures and term notes 4,123 3,439 2,910 Commercial paper and credit facility draws 439 519 388 Amortization of fair value adjustment 18 (45) (45) Capitalized interest (161) (101) (74) 4,419 3,812 3,179

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 (millions of Canadian dollars) Obligations at beginning of year 493 488 Liabilities acquired 185 1 Liabilities incurred 3 — Liabilities settled (139) (23) Change in estimate and other 51 5 Foreign currency translation adjustment 40 (6) Accretion expense 33 28 Obligations at end of year 666 493 Presented as follows: Other current liabilities (Note 16) 120 136 Other long-term liabilities 546 357 666 493

NONCONTROLLING INTERESTS (Table

NONCONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 (millions of Canadian dollars) Algonquin Gas Transmission, LLC 414 384 Enbridge Athabasca Midstream Investor Limited Partnership 1,073 1,086 Maritimes & Northeast Pipeline, L.L.C. 606 559 Renewable energy assets 786 885 Maritimes & Northeast Pipeline Limited Partnership 109 111 Other 5 4 2,993 3,029

SHARE CAPITAL (Tables)

SHARE CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
Schedule of Common Shares	COMMON SHARES 2024 2023 2022 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 2,125 69,180 2,025 64,760 2,026 64,799 Shares issued, net of issue costs 51 2,489 103 4,485 — — Shares issued on exercise of stock options 1 39 — 3 2 53 Shares issued on vesting of RSUs, net of tax 1 30 — 12 — — Share repurchases at stated value 1 — — (3) (80) (3) (88) Other — — — — — (4) Balance at end of year 2,178 71,738 2,125 69,180 2,025 64,760 1 Reflects the repurchase and cancellation of common shares under our normal course issuer bid. On May 15, 2024, we filed prospectus supplements in Canada and the US to establish an at-the-market equity issuance program (the ATM Program) that allowed us to issue and sell, at our discretion, up to $2.75 billion (or the US dollar equivalent) of our common shares from treasury to the public from time to time at the market prices prevailing at the time of sale through the Toronto Stock Exchange, the New York Stock Exchange (NYSE) or any other marketplace in Canada or the US where the common shares may be traded. During the period from May 15, 2024 to July 31, 2024, 51,298,629 common shares were issued and sold under the ATM Program at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.50 billion ($2.48 billion, net of aggregate commissions paid of $16.3 million and other issuance costs). On August 1, 2024, we terminated the ATM Program. Net proceeds from sales of common shares under the ATM Program were used to partially fund the Questar Acquisition and PSNC Acquisition and to pay related fees and expenses. 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 were also used to finance a portion of the aggregate cash consideration payable for the Acquisitions discussed in Note 8 - Acquisitions and Disposition .
Schedule of Preference Shares and Characteristics of Preference Shares	PREFERENCE SHARES 2024 2023 2022 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 20 500 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 18 454 18 454 20 500 Preference Shares, Series G 1 2 46 2 46 — — Preference Shares, Series H 12 291 12 291 14 350 Preference Shares, Series I 2 2 59 2 59 — — 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 22 562 24 600 24 600 Preference Shares, Series 4 3 2 38 — — — — 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 19 20 500 20 500 20 500 Issuance costs (135) (135) (135) Balance at end of year 6,818 6,818 6,818 1 On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G. 2 On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I. 3 On September 1, 2024, 1,502,775 of the outstanding Preference Shares, Series 3 were converted into Preference Shares, Series 4. 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 5.41 % $1.35300 $25 March 1, 2028 Series E Preference Shares, Series F 5.54 % $1.38452 $25 June 1, 2028 Series G Preference Shares, Series G 5 6.15 % $1.51644 $25 June 1, 2028 Series F Preference Shares, Series H 6.11 % $1.52800 $25 September 1, 2028 Series I Preference Shares, Series I 6 5.76 % $1.42028 $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 6.70 % $1.67400 $25 December 1, 2028 Series O Preference Shares, Series P 7 5.92 % $1.47952 $25 March 1, 2029 Series Q Preference Shares, Series R 8 6.31 % $1.57852 $25 June 1, 2029 Series S Preference Shares, Series 1 6.70 % US$1.67592 US$25 June 1, 2028 Series 2 Preference Shares, Series 3 9 5.29 % $1.32200 $25 September 1, 2029 Series 4 Preference Shares, Series 4 10 6.02 % $1.48440 $25 September 1, 2029 Series 3 Preference Shares, Series 5 11 6.68 % US$1.67076 US$25 March 1, 2029 Series 6 Preference Shares, Series 7 12 5.99 % $1.49700 $25 March 1, 2029 Series 8 Preference Shares, Series 9 13 5.67 % $1.41800 $25 December 1, 2029 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 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, Series I and Series 4 contain a feature where the dividend rate resets on a quarterly basis. These Dividend Rates are presented in the table above on an annualized basis using the most recent quarterly dividend rate reset. 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 G was decreased to $0.37911 from $0.43014 on December 1, 2024 due to reset on a quarterly basis. 6 The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.35507 from $0.40589 on December 1, 2024 due to reset on a quarterly basis. 7 The quarterly dividend per share paid on Preference Shares, Series P was increased to $0.36988 from $0.27369 on March 1, 2024 due to reset of the annual dividend on March 1, 2024. 8 The quarterly dividend per share paid on Preference Shares, Series R was increased to $0.39463 from $0.25456 on June 1, 2024 due to reset of the annual dividend on June 1, 2024. 9 The quarterly dividend per share paid on Preference Shares, Series 3 was increased to $0.33050 from $0.23356 on September 1, 2024 due to reset of the annual dividend on September 1, 2024. 10 On September 1, 2024, 1,502,775 of the outstanding Preference Shares, Series 3 were converted into Preference Shares, Series 4. The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to $0.37110 from $0.42206 on December 1, 2024 due to reset on a quarterly basis following the date of issuance. 11 The quarterly dividend per share paid on Preference Shares, Series 5 was increased to US$0.41769 from US$0.33596 on March 1, 2024 due to reset of the annual dividend on March 1, 2024. 12 The quarterly dividend per share paid on Preference Shares, Series 7 was increased to $0.37425 from $0.27806 on March 1, 2024 due to reset of the annual dividend on March 1, 2024. 13 The quarterly dividend per share paid on Preference Shares, Series 9 was increased to $0.35450 from $0.25606 on December 1, 2024 due to reset of the annual dividend on December 1, 2024.

STOCK OPTION AND STOCK UNIT P_2

STOCK OPTION AND STOCK UNIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]
Schedule of Outstanding Stock Options	December 31, 2024 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 28,729 50.79 Options granted 5,036 46.36 Options exercised 1 (7,328) 49.27 Options cancelled or expired (1,113) 51.78 Options outstanding at end of year 25,324 50.31 5.7 70 Options vested at end of year 2 15,602 51.33 4.2 37 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2024, 2023 and 2022 was $18 million, $2 million and $66 million, respectively, and cash received on exercise was $1 million, nil and $3 million, respectively. 2 The total fair value of ISOs vested during the years ended December 31, 2024, 2023 and 2022 was $17 million, $20 million and $21 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, 2024 2023 2022 Fair value per option (Canadian dollars) 1 4.07 6.05 5.07 Valuation assumptions Expected option term (years) 2 6 6 6 Expected volatility 3 21.1 % 22.2 % 21.9 % Expected dividend yield 4 8.1 % 6.7 % 6.5 % Risk-free interest rate 5 3.8 % 3.5 % 1.8 % 1 Options granted to US employees are based on the NYSE prices. The option value and assumptions shown are based on a weighted average of the US and Canadian options. The fair value per option for the years ended December 31, 2024, 2023 and 2022 were $3.53, $5.38 and $4.78, respectively, for Canadian employees and US$3.58, US$5.23 and US$4.62, respectively, for US employees. 2 The expected option term is six years based on historical exercise practice and five years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada's Canadian bond yields and the US Treasury bond yields at the grant date.
Share-Based Payment Arrangement, Performance Shares, Activity	December 31, 2024 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 3,180 Units granted 1,444 Units cancelled (104) Units matured 1 (1,355) Dividend reinvestment 237 Units outstanding at end of year 3,402 1.6 244 1 The total amount paid during the years ended December 31, 2024, 2023 and 2022 for PSUs was $65 million, $123 million and $90 million, respectively.
Schedule of Outstanding Stock Units	December 31, 2024 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 3,571 50.69 Units granted 1,758 48.50 Units cancelled (112) 51.38 Units matured 1 (1,910) 49.99 Dividend reinvestment 284 50.94 Units outstanding at end of year 3,591 51.10 1.0 187 1 The total amount paid during the years ended December 31, 2024, 2023 and 2022 for RSUs was $40 million, $56 million and $32 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, 2024
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, 2024, 2023 and 2022 are as follows: Cash Flow Hedges Excluded Components of Fair Value Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2024 320 (23) (728) 2,653 11 70 2,303 Other comprehensive income/(loss) retained in AOCI 79 (42) (1,305) 5,799 (9) 323 4,845 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 31 — — — — — 31 Commodity contracts 2 (1) — — — — — (1) Foreign exchange contracts 3 — 53 — — — — 53 Amortization of pension and OPEB actuarial gain 4 — — — — — (21) (21) 109 11 (1,305) 5,799 (9) 302 4,907 Tax impact Income tax on amounts retained in AOCI (15) 10 — — (1) (75) (81) Income tax on amounts reclassified to earnings (7) (12) — — — 5 (14) (22) (2) — — (1) (70) (95) Balance as at December 31, 2024 407 (14) (2,033) 8,452 1 302 7,115 Cash Flow Hedges Excluded Components of Fair Value Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2023 121 (35) (1,137) 4,348 5 218 3,520 Other comprehensive income/(loss) retained in AOCI 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 3 — (47) — — — — (47) Amortization of pension and OPEB actuarial gain 4 — — — — — (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 Components of Fair Value Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2022 (897) — (166) 56 (5) (84) (1,096) Other comprehensive income/(loss) retained in AOCI 1,125 (35) (971) 4,292 (6) 411 4,816 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 186 — — — — — 186 Foreign exchange contracts 3 (4) — — — — — (4) Other contracts 5 4 — — — — — 4 Amortization of pension and OPEB actuarial gain 4 — — — — — (14) (14) Other — — — — 16 — 16 1,311 (35) (971) 4,292 10 397 5,004 Tax impact Income tax on amounts retained in AOCI (250) — — — — (99) (349) Income tax on amounts reclassified to earnings (43) — — — — 4 (39) (293) — — — — (95) (388) Balance as at December 31, 2022 121 (35) (1,137) 4,348 5 218 3,520 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Transportation and other services revenues in the Consolidated Statements of Earnings. 3 Reported within Interest expense and Other income/(expense) in the Consolidated Statements of Earnings. 4 These components are included in the computation of net periodic benefit credit and are reported within Other income/(expense) in the Consolidated Statements of Earnings. 5 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

RISK MANAGEMENT AND FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2024
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. December 31, 2024 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 — 78 47 125 (29) 96 Interest rate contracts 44 — 23 67 (39) 28 Commodity contracts 2 — 360 362 (191) 171 Other contracts — — 3 3 — 3 46 78 433 557 (259) 298 Deferred amounts and other assets Foreign exchange contracts — — 83 83 (71) 12 Interest rate contracts 9 — 137 146 (27) 119 Commodity contracts — — 197 197 (39) 158 9 — 417 426 (137) 289 Other current liabilities Foreign exchange contracts — (73) (731) (804) 29 (775) Interest rate contracts (58) — (22) (80) 39 (41) Commodity contracts — — (451) (451) 191 (260) (58) (73) (1,204) (1,335) 259 (1,076) Other long-term liabilities Foreign exchange contracts — — (1,579) (1,579) 71 (1,508) Interest rate contracts — — (80) (80) 27 (53) Commodity contracts (1) — (238) (239) 39 (200) (1) — (1,897) (1,898) 137 (1,761) Total net derivative asset/(liability) Foreign exchange contracts — 5 (2,180) (2,175) — (2,175) Interest rate contracts (5) — 58 53 — 53 Commodity contracts 1 — (132) (131) — (131) Other contracts — — 3 3 — 3 (4) 5 (2,251) (2,250) — (2,250) December 31, 2023 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Fair Value Hedges Non-Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Other current assets Foreign exchange contracts — 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)
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: 2024 2023 As at December 31, 2025 2026 2027 2028 2029 Thereafter Total Total Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) 1,245 — — — — — 1,245 1,860 Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) 6,406 5,627 4,811 3,522 1,248 — 21,614 24,747 Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) 30 28 32 — — — 90 120 Foreign exchange contracts - Euro forwards - sell (millions of Euro) 126 121 81 67 66 129 590 731 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) 2,296 1,737 676 49 13 — 4,771 9,018 Interest rate contracts - short-term receive fixed rate (millions of Canadian dollars) — — — — — — — 2,015 Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 1 4,531 753 — — — — 5,284 5,162 Interest rate contracts - costless collar (millions of Canadian dollars) 1,938 268 104 6 — — 2,316 1,139 Equity contracts (millions of Canadian dollars) — — — — — — — 47 Commodity contracts - natural gas (billions of cubic feet) 2 154 79 37 11 5 2 288 86 Commodity contracts - crude oil (millions of barrels) 2 6 15 1 1 1 1 25 6 Commodity contracts - power (megawatt per hour (MW/H)) 61 24 (31) (49) (30) — (5) 3 (22) 3 1 Represents the notional amount of long-term debt issuances hedged. 2 Represents the notional amount of net purchase/(sale). 3 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, 2024 2023 (millions of Canadian dollars) Unrealized loss on derivative (3) (132) Unrealized gain on hedged item 6 131 Realized gain/(loss) on derivative 26 (47) Realized loss on hedged item (79) — The following table presents the effect of cash flow hedges and fair value hedges on our consolidated earnings and comprehensive income, before the effect of income taxes: Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts — — 3 Interest rate contracts 67 201 1,151 Commodity contracts 19 68 (53) Other contracts 1 (2) (4) Fair value hedges Foreign exchange contracts (42) 15 (35) 45 282 1,062 Amount of (income)/loss reclassified from AOCI to earnings Foreign exchange contracts 1 53 — 13 Interest rate contracts 2 31 28 186 Commodity contracts 3 (1) — — Other contracts 4 — — 4 83 28 203 1 Reported within Interest expense and Other income/(expense) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues in the Consolidated Statements of Earnings. 4 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, 2024 2023 2022 (millions of Canadian dollars) Foreign exchange contracts 1 (2,033) 1,292 (1,344) Interest rate contracts 2 112 (63) 10 Commodity contracts 3 (163) (41) 50 Other contracts 4 2 (8) 4 Total unrealized derivative fair value gain/(loss), net (2,082) 1,180 (1,280) 1 For the respective years ended, reported within Transportation and other services revenues (2024 - nil ; 2023 - $645 million gain; 2022 - $238 million loss) and Other income/(expense) (2024 - $2,033 million loss; 2023 - $647 million gain; 2022 - $1,106 million loss) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 For the respective years ended, reported within Transportation and other services revenues (2024 - $23 million loss; 2023 - $35 million loss; 2022 - $13 million gain), Commodity sales (2024 - $92 million loss; 2023 - $153 million gain; 2022 - $89 million gain), Commodity costs (2024 - $31 million loss; 2023 - $94 million loss; 2022 - $102 million loss) and Operating and administrative expense (2024 - $17 million loss; 2023 - $65 million loss; 2022 - $50 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, 2024 2023 (millions of Canadian dollars) Canadian financial institutions 344 457 US financial institutions 128 252 European financial institutions 116 107 Asian financial institutions 53 121 Other 1 332 125 973 1,062 1 Other is comprised of commodity clearing house and crude oil, natural gas and power 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, 2024 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 125 — 125 Interest rate contracts — 67 — 67 Commodity contracts 34 72 256 362 Other contracts — 3 — 3 34 267 256 557 Long-term derivative assets Foreign exchange contracts — 83 — 83 Interest rate contracts — 146 — 146 Commodity contracts 1 14 182 197 Other contracts — — — — 1 243 182 426 Financial liabilities Current derivative liabilities Foreign exchange contracts — (804) — (804) Interest rate contracts — (80) — (80) Commodity contracts (52) (116) (283) (451) Other contracts — — — — (52) (1,000) (283) (1,335) Long-term derivative liabilities Foreign exchange contracts — (1,579) — (1,579) Interest rate contracts — (80) — (80) Commodity contracts (1) (31) (207) (239) Other contracts — — — — (1) (1,690) (207) (1,898) Total net derivative asset/(liability) Foreign exchange contracts — (2,175) — (2,175) Interest rate contracts — 53 — 53 Commodity contracts (18) (61) (52) (131) Other contracts — 3 — 3 (18) (2,180) (52) (2,250) 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 derivative asset/(liability) Foreign exchange contracts — (152) — (152) Interest rate contracts — (156) — (156) Commodity contracts 6 29 (131) (96) Other contracts — — — — 6 (279) (131) (404)
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, 2024 Fair Value Unobservable Input Minimum Price/Volatility Maximum Price/Volatility Weighted Average Price/Volatility Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas (5) Forward gas price 3.73 9.85 4.12 $/mmbtu 2 Crude (13) Forward crude price 73.54 104.42 97.44 $/barrel Power (44) Forward power price 31.17 229.29 68.51 $/MW/H Commodity contracts - physical 1 Natural gas (80) Forward gas price 1.40 22.57 4.12 $/mmbtu 2 Crude 22 Forward crude price 77.31 118.28 99.76 $/barrel Power (98) Forward power price 12.94 211.42 70.30 $/MW/H Commodity options 3 Natural gas 166 Forward gas price 2.44 7.09 4.44 $/mmbtu 2 Price volatility 3 % 77 % 50 % (52) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 One million British thermal units (mmbtu). 3 Commodity options contracts are valued using an option model valuation technique.
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, 2024 2023 (millions of Canadian dollars) Level 3 net derivative liability at beginning of year (131) (136) Total gain/(loss), unrealized Included in earnings 1 (92) (48) Included in OCI 19 67 Included in regulatory assets/liabilities 130 — Settlements 22 (14) Level 3 net derivative liability at end of year (52) (131) 1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Schedule of Income Tax Rate Reconciliation	INCOME TAX RATE RECONCILIATION Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Earnings before income taxes 7,299 7,879 4,542 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 1,095 1,182 681 Increase/(decrease) resulting from: Provincial and state income taxes 1 183 411 108 Foreign and other statutory rate differentials 2 340 187 295 Effects of rate-regulated accounting 3.4 (192) (106) (122) Write-off of regulatory deferrals 3,5 4 115 — Part VI.1 tax, net of federal Part I deduction 3,6 73 66 76 US Minimum Tax 148 100 107 Non-taxable portion of gain on sale of investmen t 3,7 (147) — — Valuation allowance 3 (2) (12) 6 Accounting impairment of non-deductible goodwill 3,8 148 — 370 Noncontrolling interests 3,9 (30) 19 9 Investment and production tax credits (23) (47) — Other 3 71 (94) 74 Income tax expense 1,668 1,821 1,604 Effective income tax rate 22.9 % 23.1 % 35.3 % 1 The change in provincial and state income taxes from 2023 to 2024 reflects the decrease in earnings from Canadian operations partially offset by an increase in earnings from US operations before considering the non-deductible goodwill impairment to the Gas Transmission segment. Refer to Note 13 - Long-Term Investments . 2 The change in foreign and other statutory rate differentials from 2023 to 2024 reflects the increase in earnings from US operations before considering the non-deductible goodwill impairment to the Gas Transmission segment. Refer to Note 13 - Long-Term Investments. 3 T he provincial and state tax component of these items is included in the Provincial and state income taxes above. 4 The amount in 2024 includes the effects of rate regulated accounting attributable to the Acquisitions. Refer to Note 8 - Acquisitions and Disposition. 5 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 . 6 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada. 7 The amount in 2024 represents the federal component of the non-taxable portion of the gain on sales relating to Alliance Pipeline and Aux Sable. Refer to Note 13 - Long-Term Investments . 8 The amounts relates to the federal impact of the non-deductible goodwill impairment to the Gas Transmissions segment. Refer to Note 13 - Long-Term Investments and Note 15 - Goodwill . 9 The amount in 2023 and 2022 includes the federal tax impact of impairments to Chapman Ranch and Magic Valley attributable to non-controlling interests in those respective years. 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, 2024 2023 2022 (millions of Canadian dollars) Earnings before income taxes Canada 1,035 2,233 583 US 5,231 4,620 2,865 Other 1,033 1,026 1,094 7,299 7,879 4,542 Current income taxes Canada 248 100 360 US 578 191 201 Other 123 110 86 949 401 647 Deferred income taxes Canada (299) 456 (358) US 1,013 974 1,309 Other 5 (10) 6 719 1,420 957 Income tax expense 1,668 1,821 1,604
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, 2024 2023 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (11,368) (9,202) Investments (9,043) (7,765) Regulatory assets (1,940) (1,338) Other (251) (52) Total deferred income tax liabilities (22,602) (18,357) Deferred income tax assets Financial instruments 740 271 Loss carryforwards 1,272 1,745 Other 2,088 1,798 Total deferred income tax assets 4,100 3,814 Less valuation allowance (298) (147) Total deferred income tax assets, net 3,802 3,667 Net deferred income tax liabilities, net (18,800) (14,690) Presented as follows: Total deferred income tax assets 796 341 Total deferred income tax liabilities (19,596) (15,031) Net deferred income tax liabilities, net (18,800) (14,690)
Schedule of Unrecognized Tax Benefits	UNRECOGNIZED TAX BENEFITS Year ended December 31, 2024 2023 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 45 55 Gross decreases for tax positions of prior year (2) (2) Change in translation of foreign currency 4 (1) Lapses of statute of limitations (16) (7) Unrecognized tax benefits at end of year 31 45

PENSION AND OTHER POSTRETIREM_2

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 2024 2023 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 4,092 3,630 1,036 1,029 Service cost 103 81 60 40 Interest cost 186 184 69 47 Participant contributions 32 31 — — Actuarial (gain)/loss 1 — 359 (98) 31 Benefits paid (210) (193) (100) (76) Transfer in — — 569 — Foreign currency exchange rate changes — — 119 (29) Other — — (7) (6) Projected benefit obligation at end of year 2 4,203 4,092 1,648 1,036 Change in plan assets Fair value of plan assets at beginning of year 4,528 4,234 1,052 1,080 Actual return on plan assets 627 427 197 78 Employer contributions 23 27 5 5 Participant contributions 32 31 — — Benefits paid (210) (193) (100) (76) Transfer in — — 900 — Foreign currency exchange rate changes — — 146 (29) Other — 2 (6) (6) Fair value of plan assets at end of year 3 5,000 4,528 2,194 1,052 Overfunded status at end of year 797 436 546 16 Presented as follows: Deferred amounts and other assets 943 636 653 116 Other current liabilities (10) (8) (6) (5) Other long-term liabilities (136) (192) (101) (95) 797 436 546 16 1 Primarily due to the increase in the discount rate and changes in benefit assumptions and member data used to measure the defined benefit obligations (2023 - primarily due to the decrease in the discount rates used to measure the benefit obligation). 2 The accumulated benefit obligation for our Canadian pension plans was $3.9 billion and $3.8 billion as at December 31, 2024 and 2023, respectively. The accumulated benefit obligation for our US pension plans was $1.6 billion and $1.0 billion as at December 31, 2024 and 2023, respectively. 3 Assets in the amount of $18 million (2023 - $14 million) and $80 million (2023 - $62 million), related to our Canadian and US non-registered supplemental pension plan obligations, respectively, 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, 2024 2023 2024 2023 (millions of Canadian dollars) Accumulated benefit obligation 404 394 107 99 Fair value of plan assets 283 243 — — Canada US December 31, 2024 2023 2024 2023 (millions of Canadian dollars) Projected benefit obligation 428 416 107 99 Fair value of plan assets 283 243 — —
Schedule of Amounts Recognized in AOCI	The amount of pre-tax AOCI relating to our pension plans are as follows: Canada US December 31, 2024 2023 2024 2023 (millions of Canadian dollars) Net actuarial (gain)/loss (122) 51 (42) 74 Prior service cost — — 5 1 Total amount recognized in AOCI 1 (122) 51 (37) 75 1 Excludes amounts related to CTA. The amount of pre-tax AOCI relating to our OPEB plans are as follows: Canada US December 31, 2024 2023 2024 2023 (millions of Canadian dollars) Net actuarial gain (99) (82) (103) (96) Prior service credit — (1) (16) (22) Total amount recognized in AOCI 1 (99) (83) (119) (118) 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, 2024 2023 2022 2024 2023 2022 (millions of Canadian dollars) Service cost 1 103 81 131 60 40 43 Interest cost 2 186 184 127 69 47 24 Expected return on plan assets 2 (304) (271) (295) (131) (77) (85) Amortization/settlement of net actuarial (gain)/loss 2 4 — 8 7 (4) — Amortization/curtailment of prior service credit 2 — — — (4) — (2) Net periodic benefit (credit)/cost (11) (6) (29) 1 6 (20) Defined contribution benefit cost 12 12 10 — — — Net pension (credit)/cost recognized in Earnings 1 6 (19) 1 6 (20) Amount recognized in OCI: Amortization/settlement of net actuarial (gain)/loss — — (2) — 4 — Amortization/curtailment of prior service credit — — — 4 — 2 Net actuarial (gain)/loss arising during the year (173) 115 (288) (116) 30 (52) Total amount recognized in OCI (173) 115 (290) (112) 34 (50) Total amount recognized in Comprehensive income (172) 121 (309) (111) 40 (70) 1 Reported within Operating and administrative in the Consolidated Statements of Earnings. 2 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, 2024 2023 2022 2024 2023 2022 (millions of Canadian dollars) Service cost 1 3 3 4 3 1 1 Interest cost 2 10 11 7 7 6 3 Expected return on plan assets 2 — — — (15) (11) (12) Amortization/settlement of net actuarial gain 2 (5) (6) (1) (5) (6) (6) Amortization/curtailment of prior service credit 2 (1) — — (6) (8) (7) Net periodic benefit (credit)/cost recognized in Earnings 7 8 10 (16) (18) (21) Amount recognized in OCI: Amortization/settlement of net actuarial gain 5 6 1 5 6 6 Amortization/curtailment of prior service credit 1 — — 6 8 7 Net actuarial (gain)/loss arising during the year (22) 13 (67) (12) — (4) Total amount recognized in OCI (16) 19 (66) (1) 14 9 Total amount recognized in Comprehensive income (9) 27 (56) (17) (4) (12) 1 Reported within Operating and administrative in the Consolidated Statements of Earnings. 2 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 2024 2023 2022 2024 2023 2022 Projected benefit obligation Discount rate 4.7 % 4.6 % 5.1 % 5.5 % 4.7 % 4.9 % Rate of salary increase 3.0 % 3.0 % 2.9 % 2.6 % 2.6 % 2.8 % Cash balance interest credit rate N/A N/A N/A 4.0 % 4.5 % 4.3 % Net periodic benefit cost Discount rate 4.6 % 5.3 % 3.2 % 4.8 % 4.9 % 2.6 % Rate of return on plan assets 6.8 % 6.5 % 6.6 % 7.3 % 7.4 % 7.4 % Rate of salary increase 3.0 % 2.9 % 2.9 % 2.8 % 2.8 % 2.8 % Cash balance interest credit rate N/A N/A N/A 4.4 % 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 2024 2023 2022 2024 2023 2022 Accumulated postretirement benefit obligation Discount rate 4.7 % 4.6 % 5.3 % 5.3 % 4.7 % 4.9 % Net periodic benefit cost Discount rate 4.6 % 5.3 % 3.2 % 5.5 % 4.9 % 2.4 % Rate of return on plan assets N/A N/A N/A 6.7 % 5.9 % 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, 2024 2023 2024 2023 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 228 211 129 136 Service cost 3 3 3 1 Interest cost 10 11 7 6 Participant contributions — — 5 5 Actuarial (gain)/loss 1 (21) 13 (9) 4 Benefits paid (10) (10) (20) (20) Transfer in — — 46 — Foreign currency exchange rate changes — — 16 (3) Accumulated postretirement benefit obligation at end of year 210 228 177 129 Change in plan assets Fair value of plan assets at beginning of year — — 187 185 Actual return on plan assets — — 22 14 Employer contributions 10 10 7 7 Participant contributions — — 5 5 Benefits paid (10) (10) (20) (20) Transfer in — — 55 — Foreign currency exchange rate changes — — 20 (4) Other — — 2 — Fair value of plan assets at end of year — — 278 187 Overfunded/(underfunded) status at end of year (210) (228) 101 58 Presented as follows: Deferred amounts and other assets — — 113 73 Other current liabilities (11) (12) — — Other long-term liabilities (199) (216) (12) (15) (210) (228) 101 58 1 Primarily due to the increase in the discount rate and changes in benefit assumptions and member data used to measure the defined benefit obligation (2023 - primarily due to decrease 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, 2024 2023 2024 2023 (millions of Canadian dollars) Accumulated benefit obligation 210 228 100 78 Fair value of plan assets — — 88 63
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 2024 2023 2024 2023 Health care cost trend rate assumed for next year 4.0 % 4.0 % 3.2 % 4.7 % Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.0 % 4.0 % 3.7 % 3.3 % Year that the rate reaches the ultimate trend rate N/A N/A 2023 - 2046 2022 - 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 2024 2023 Allocation 2024 2023 Equity securities 46.2 % 39.1 % 41.4 % 43.4 % 44.8 % 39.5 % Fixed income securities 23.0 % 31.6 % 29.6 % 23.2 % 33.0 % 19.4 % Alternatives 1 30.8 % 29.3 % 29.0 % 33.4 % 22.2 % 41.1 % 1 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Fund values are based on the net asset value of the funds that invest directly in the aforementioned underlying investments. The values of the investments have been estimated using the capital accounts representing the plan's ownership interest in the funds.
Schedule of Changes in Fair Value of Plan Assets	The following table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level: Canada US Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2024 Cash and cash equivalents 201 — — 201 57 — — 57 Equity securities 4 Canada — 3 — 3 — — — — Global 134 1,817 — 1,951 27 954 — 981 Fixed income securities 4 Government — 543 — 543 — 194 — 194 Corporate — 838 — 838 — 474 — 474 Alternatives 5 — — 1,464 1,464 — — 488 488 Total pension plan assets at fair value 335 3,201 1,464 5,000 84 1,622 488 2,194 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 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 $77 million (2023 - $61 million) of indirectly held related party equity and fixed income securities investments. 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, 2024 2023 2024 2023 (millions of Canadian dollars) Balance at beginning of year 1,290 1,291 433 445 Unrealized and realized gains/(losses) 104 (41) 63 (12) Purchases and settlements, net 70 40 (8) — Balance at end of year 1,464 1,290 488 433 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, 2024 Cash and cash equivalents 4 — — 4 Equity securities US — 52 — 52 Global — 93 — 93 Fixed income securities Government 71 6 — 77 Corporate — 19 — 19 Alternatives 4 — — 33 33 Total OPEB plan assets at fair value 75 170 33 278 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 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, 2024 2023 (millions of Canadian dollars) Balance at beginning of year 29 28 Unrealized and realized gains 5 1 Purchases and settlements, net (1) — Balance at end of year 33 29
Schedule of Expected Benefit Payments and Employer Contributions	Year ending December 31, 2025 2026 2027 2028 2029 2030-2034 (millions of Canadian dollars) Pension Canada 214 220 226 232 238 1,285 US 117 120 123 123 120 625 OPEB Canada 11 12 12 12 12 64 US 16 16 16 16 16 71

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
Schedule of Supplemental Statements of Financial Position	Supplemental Statements of Financial Position Information December 31, 2024 December 31, 2023 (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 785 669 Operating lease liabilities - current 3 121 98 Operating lease liabilities - long-term 3 738 652 Total operating lease liabilities 859 750 Finance leases Finance lease right-of-use assets, net 4 294 287 Finance lease liabilities - current 5 16 19 Finance lease liabilities - long-term 5 300 264 Total finance lease liabilities 316 283 Weighted average remaining lease term Operating leases 14 years 12 years Finance leases 31 years 31 years Weighted average discount rate Operating leases 4.8 % 4.5 % Finance leases 5.8 % 5.7 % 1 Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2024 were $42 million (December 31, 2023 - $42 million), $6 million (December 31, 2023 - $5 million) and $37 million (December 31, 2023 - $38 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, 2024, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance (millions of Canadian dollars) 2025 148 31 2026 134 30 2027 123 23 2028 97 23 2029 65 22 Thereafter 685 531 Total undiscounted lease payments 1,252 660 Less imputed interest (393) (344) Total 859 316
Schedule of Lessee, Finance Lease Liability, Maturity	As at December 31, 2024, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance (millions of Canadian dollars) 2025 148 31 2026 134 30 2027 123 23 2028 97 23 2029 65 22 Thereafter 685 531 Total undiscounted lease payments 1,252 660 Less imputed interest (393) (344) Total 859 316
Schedule of Operating Lease, Lease Income	Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Operating lease income 229 241 266 Variable lease income 321 299 321 Total lease income 1 550 540 587 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, 2024, 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) 2025 221 2026 202 2027 197 2028 198 2029 199 Thereafter 1,415 Future lease payments 2,432

OTHER INCOME_(EXPENSE) (Tables)

OTHER INCOME/(EXPENSE) (Tables)	12 Months Ended
	Dec. 31, 2024
Other Income and Expenses [Abstract]
Schedule of Other Income and Expenses	Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Realized foreign currency gain/(loss) 121 (129) 92 Unrealized foreign currency gain/(loss) (2,199) 821 (1,094) Net defined pension and OPEB credit 188 135 239 Other 564 397 174 (1,326) 1,224 (589)

CHANGES IN OPERATING ASSETS A_2

CHANGES IN OPERATING ASSETS AND LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2024
CHANGES IN OPERATING ASSETS AND LIABILITIES
Schedule of Changes in Operating Assets and Liabilities	Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Trade receivables and unbilled revenues (1,638) 1,125 (572) Accounts receivable from affiliates (23) 18 17 Inventory 177 763 (599) Other current and non-current assets (426) 1,301 (394) Trade payables and accrued liabilities 1,383 (1,542) 585 Accounts payable to affiliates (8) (66) 16 Interest payable 157 199 58 Other current and long-term liabilities 245 513 877 (133) 2,311 (12)

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2024
Related Party Transactions [Abstract]
Schedule of Our Transactions with Equity Investees	Our transactions with significantly influenced investees are as follows: Year ended December 31, 2024 2023 2022 (millions of Canadian dollars) Transportation and other revenues 181 169 185 Commodity sales — — 51 Operating and administrative 1 637 625 503 Commodity costs 2 22 63 778 Gas distribution costs 147 140 136 1 During the years ended December 31, 2024, 2023 and 2022, we had Operating and administrative costs from the Seaway Crude Pipeline System of $650 million, $632 million and $495 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
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Schedule of Commitments	As at December 31, 2024, 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 14,019 4,260 2,047 1,755 1,535 1,200 3,222 Maintenance agreements 2 452 57 56 57 36 36 210 Right-of-ways commitments 3 981 52 48 53 49 49 730 Total 15,452 4,369 2,151 1,865 1,620 1,285 4,162 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
	Dec. 31, 2024
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2024 Operating revenues 11,038 11,336 14,882 16,217 53,473 Operating income 2,711 2,273 2,218 2,447 9,649 Earnings 1,565 2,001 1,447 618 5,631 Earnings attributable to controlling interests 1,512 1,943 1,391 595 5,441 Earnings attributable to common shareholders 1,419 1,848 1,293 493 5,053 Earnings per common share Basic 0.67 0.86 0.59 0.23 2.34 Diluted 0.67 0.86 0.59 0.23 2.34 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

BUSINESS OVERVIEW (Details)

BUSINESS OVERVIEW (Details) - facility	Jan. 02, 2024	Dec. 31, 2024
Product Information [Line Items]
Number of production facilities acquired	6
Aux Sable | Significantly Influenced Investees | Gas Transmission
Product Information [Line Items]
Ownership interest (as percent)		42.70%
Aux Sable Canada LP | Significantly Influenced Investees | Gas Transmission
Product Information [Line Items]
Ownership interest (as percent)		50%

SIGNIFICANT ACCOUNTING POLICI_3

SIGNIFICANT ACCOUNTING POLICIES - Revenue Recognition (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 372
Largest Non-Affiliated Customer | Sales Revenue, Net | Customer Concentration Risk
Disaggregation of Revenue [Line Items]
Concentration (percent)	10%	10%	10%
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 97	$ 210	$ 238

SIGNIFICANT ACCOUNTING POLICI_4

SIGNIFICANT ACCOUNTING POLICIES - Current Expected Credit Losses (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Accounting Policies [Abstract]
Allowance for doubtful accounts receivable	$ 119	$ 100

SIGNIFICANT ACCOUNTING POLICI_5

SIGNIFICANT ACCOUNTING POLICIES - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2024 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, 2024
Performance Stock Units (PSUs)
STOCK-BASED COMPENSATION
Vesting period (in years)	3 years
Annual vesting (as percent)	33.33%
Restricted Stock Units (RSU)
STOCK-BASED COMPENSATION
Vesting period (in years)	3 years

REVENUE - Major Products and Se

REVENUE - Major Products and Services (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									$ 25,939	$ 24,199	$ 23,916
Total revenue	$ 16,217	$ 14,882	$ 11,336	$ 11,038	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 53,473	43,649	53,309
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]									Total revenue
Net gain (loss) on derivative									$ 23	(97)	(431)
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									12,213	12,132	11,518
Gas Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									6,010	5,780	5,384
Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									7,527	6,028	6,733
Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									189	259	281
Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									17,521	17,389	16,493
Transportation revenue | Revision of Prior Period, Reclassification, Adjustment
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers										(602)	(584)
Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									1,337	1,073	893
Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											22
Gas distribution sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									6,734	5,461	6,227
Gas distribution sales | Revision of Prior Period, Reclassification, Adjustment
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers										602	584
Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									189	259	281
Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									158	17
Revenue not from contract with customers									26,860	18,964	29,150
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									674	486	243
Business Segments
Disaggregation of Revenue [Line Items]
Total revenue									52,438	42,189	49,911
Business Segments | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									12,213	12,132	11,518
Total revenue									38,183	29,882	37,174
Business Segments | Gas Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									6,010	5,780	5,384
Total revenue									6,199	5,854	5,426
Business Segments | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									7,527	6,028	6,733
Total revenue									7,542	5,976	6,729
Business Segments | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									189	259	281
Total revenue									514	477	582
Business Segments | Transportation revenue | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									11,958	11,875	11,283
Business Segments | Transportation revenue | Gas Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									5,279	5,302	5,012
Business Segments | Transportation revenue | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									284	212	198
Business Segments | Transportation revenue | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Storage and other revenue | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									255	257	235
Business Segments | Storage and other revenue | Gas Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									573	461	350
Business Segments | Storage and other revenue | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									509	355	308
Business Segments | Storage and other revenue | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Gas gathering and processing revenue | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											0
Business Segments | Gas gathering and processing revenue | Gas Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											22
Business Segments | Gas gathering and processing revenue | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											0
Business Segments | Gas gathering and processing revenue | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											0
Business Segments | Gas distribution sales | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Gas distribution sales | Gas Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Gas distribution sales | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									6,734	5,461	6,227
Business Segments | Gas distribution sales | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Electricity and transmission revenue | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Electricity and transmission revenue | Gas Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Electricity and transmission revenue | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business Segments | Electricity and transmission revenue | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									189	259	281
Business Segments | Commodity sales | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Revenue not from contract with customers									25,689	17,494	25,740
Business Segments | Commodity sales | Gas Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									158	17
Revenue not from contract with customers									99	0	0
Business Segments | Commodity sales | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Revenue not from contract with customers									0	0	0
Business Segments | Commodity sales | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0
Revenue not from contract with customers									0	0	0
Business Segments | Other Revenue | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									281	257	(81)
Business Segments | Other Revenue | Gas Transmission
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									70	72	39
Business Segments | Other Revenue | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									4	(58)	(20)
Business Segments | Other Revenue | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									319	215	305
Eliminations and Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Total revenue									1,035	1,460	3,398
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
Eliminations and Other | Gas distribution sales
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	0
Revenue not from contract with customers									1,072	1,470	3,410
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									(37)	(10)	(12)
Total revenue									(1,904)	916	(1,118)
Intersegment revenue | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	(1)	(3)
Intersegment revenue | Gas Transmission
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									20	2	3
Intersegment revenue | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									11	6	16
Intersegment revenue | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									$ 6	$ 3	$ (4)

REVENUE - Contract Balances (De

REVENUE - Contract Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Contract Receivables	$ 3,764	$ 2,802
Contract Assets	330	400
Contract Liabilities	$ 2,828	$ 2,591

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)
Revenue from Contract with Customer [Abstract]
Contract with customer, liability, revenue recognized	$ 372
Increase (decrease) in contract with customers, liability	532
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligations expected to be fulfilled in future periods	$ 62,600
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period (in years)	1 year
Performance obligations expected to be fulfilled in future periods	$ 10,400
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period (in years)	4 years
Performance obligations expected to be fulfilled in future periods	$ 25,200
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period (in years)
Performance obligations expected to be fulfilled in future periods	$ 27,000

REVENUE - Recognition and Measu

REVENUE - Recognition and Measurement of Revenues (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 25,939	$ 24,199	$ 23,916
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	295	155	127
Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	25,644	24,044	23,789
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	12,213	12,132	11,518
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	12,213	12,132	11,518
Gas Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	6,010	5,780	5,384
Gas Transmission | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	158	17	0
Gas Transmission | Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	5,852	5,763	5,384
Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	7,527	6,028	6,733
Gas Distribution and Storage | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	137	138	127
Gas Distribution and Storage | Transferred Over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	7,390	5,890	6,606
Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	189	259	281
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	$ 189	$ 259	$ 281

SEGMENTED INFORMATION - Schedul

SEGMENTED INFORMATION - Schedule of Reporting Information by Segment (Details) $ in Millions, $ in Millions			3 Months Ended								12 Months Ended
	Aug. 17, 2022 CAD ($)	Aug. 17, 2022 USD ($)	Dec. 31, 2024 CAD ($)	Sep. 30, 2024 CAD ($)	Jun. 30, 2024 CAD ($)	Mar. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Sep. 30, 2023 CAD ($)	Jun. 30, 2023 CAD ($)	Mar. 31, 2023 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Segmented Information
Revenues			$ 16,217	$ 14,882	$ 11,336	$ 11,038	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 53,473	$ 43,649	$ 53,309
Operating and administrative											(9,427)	(8,600)	(8,219)
Impairment of goodwill											0	0	(2,465)
Income from equity investments											2,304	1,816	2,056
Gain on disposition of equity investments											1,091	0	0
Gain on joint venture merger transaction	$ 1,100	$ 832									0	0	1,076
Earnings before interest, income taxes and depreciation and amortization											18,789	15,388	13,156
Depreciation and amortization											(5,167)	(4,613)	(4,317)
Interest expense (Note 17)											(4,419)	(3,812)	(3,179)
Earnings before income taxes											7,299	7,879	4,542
Capital expenditures											6,834	4,708	4,690
Property, plant and equipment, net			131,104				104,641				131,104	104,641	104,460
Business Segments
Segmented Information
Revenues											52,438	42,189	49,911
Commodity and gas distribution costs											(27,910)	(20,012)	(29,204)
Operating and administrative											(9,397)	(8,585)	(8,116)
Impairment of long-lived assets											(190)	(419)	(493)
Impairment of goodwill													(2,465)
Income from equity investments											2,321	1,837	2,060
Gain on disposition of equity investments											1,091
Gain on joint venture merger transaction													1,076
Other income											436	378	387
Business Segments | Liquids Pipelines
Segmented Information
Revenues											38,183	29,882	37,174
Commodity and gas distribution costs											(25,283)	(17,106)	(25,495)
Operating and administrative											(4,495)	(4,659)	(4,318)
Impairment of long-lived assets											(2)	145	(258)
Impairment of goodwill													0
Income from equity investments											1,051	1,007	785
Gain on disposition of equity investments											0
Gain on joint venture merger transaction													0
Other income											77	114	53
Earnings before interest, income taxes and depreciation and amortization											9,531	9,383	7,941
Capital expenditures											1,157	1,158	1,418
Property, plant and equipment, net			53,863				51,855				53,863	51,855	53,573
Business Segments | Gas Transmission
Segmented Information
Revenues											6,199	5,854	5,426
Commodity and gas distribution costs											(130)	(15)	0
Operating and administrative											(2,322)	(2,380)	(2,254)
Impairment of long-lived assets											(162)	0	0
Impairment of goodwill													(2,465)
Income from equity investments											812	688	1,133
Gain on disposition of equity investments											1,063
Gain on joint venture merger transaction													1,076
Other income											196	117	210
Earnings before interest, income taxes and depreciation and amortization											5,656	4,264	3,126
Capital expenditures											2,571	1,944	1,690
Property, plant and equipment, net			34,683				31,016				34,683	31,016	29,666
Business Segments | Gas Distribution and Storage
Segmented Information
Revenues											7,542	5,976	6,729
Commodity and gas distribution costs											(2,501)	(2,871)	(3,693)
Operating and administrative											(2,276)	(1,285)	(1,289)
Impairment of long-lived assets											(3)	(281)	0
Impairment of goodwill													0
Income from equity investments											3	2	1
Gain on disposition of equity investments											0
Gain on joint venture merger transaction													0
Other income											104	51	79
Earnings before interest, income taxes and depreciation and amortization											2,869	1,592	1,827
Capital expenditures											2,386	1,451	1,499
Property, plant and equipment, net			38,636				18,766				38,636	18,766	17,857
Business Segments | Renewable Power Generation
Segmented Information
Revenues											514	477	582
Commodity and gas distribution costs											4	(20)	(16)
Operating and administrative											(304)	(261)	(255)
Impairment of long-lived assets											(23)	(283)	(235)
Impairment of goodwill													0
Income from equity investments											455	140	141
Gain on disposition of equity investments											28
Gain on joint venture merger transaction													0
Other income											59	96	45
Earnings before interest, income taxes and depreciation and amortization											733	149	262
Capital expenditures											661	100	50
Property, plant and equipment, net			3,612				2,706				3,612	2,706	3,082
Eliminations and Other
Segmented Information
Revenues											(1,904)	916	(1,118)
Capital expenditures											59	55	33
Property, plant and equipment, net			$ 310				$ 298				$ 310	$ 298	$ 282

SEGMENTED INFORMATION - Geograp

SEGMENTED INFORMATION - Geographic Information and Property, Plant and Equipment (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Geographic Information
Revenues	$ 16,217	$ 14,882	$ 11,336	$ 11,038	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 53,473	$ 43,649	$ 53,309
Property, plant and equipment, net	131,104				104,641				131,104	104,641	104,460
Canada
Geographic Information
Revenues									22,001	23,781	27,498
Property, plant and equipment, net	48,873				48,570				48,873	48,570
US
Geographic Information
Revenues									31,472	19,868	$ 25,811
Property, plant and equipment, net	$ 82,231				$ 56,071				$ 82,231	$ 56,071

EARNINGS PER COMMON SHARE - Nar

EARNINGS PER COMMON SHARE - Narrative (Details) - Share options - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Antidilutive securities
Anti-dilutive stock options excluded from diluted earnings per common share calculation (in shares)	14.6	19.3	10.4
Weighted average exercise price of antidilutive securities (in Canadian dollars per share)	$ 54.37	$ 54.42	$ 56.49

EARNINGS PER COMMON SHARE - Wei

EARNINGS PER COMMON SHARE - Weighted Average Shares Outstanding (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Earnings Per Share [Abstract]
Weighted average shares outstanding (in shares)	2,155	2,056	2,025
Effect of dilutive options and RSUs (in shares)	3	2	4
Diluted weighted average shares outstanding (in shares)	2,158	2,058	2,029

REGULATORY MATTERS - Liquids Pi

REGULATORY MATTERS - Liquids Pipelines (Narrative) (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Public Utilities, General Disclosures [Line Items]
Total regulatory asset	$ 7,619	$ 5,707
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Total regulatory asset	$ 2,000	$ 1,900

REGULATORY MATTERS -Southern Li

REGULATORY MATTERS -Southern Lights Pipeline (Narrative) (Details) - CAD ($) $ in Millions	1 Months Ended
	Feb. 29, 2024	Dec. 31, 2024	Dec. 31, 2023
Public Utilities, General Disclosures [Line Items]
Total regulatory asset		$ 7,619	$ 5,707
Regulatory liabilities		$ 6,728	3,828
Southern Lights Pipeline
Public Utilities, General Disclosures [Line Items]
Total regulatory asset			92
Regulatory agreement term	5 years
Regulatory liabilities			151
Deferred tax liabilities, regulatory assets			$ 23

REGULATORY MATTERS - Enbridge G

REGULATORY MATTERS - Enbridge Gas Distribution Inc. (Narrative) (Details) - Gas Distribution - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2023	Dec. 31, 2024	Dec. 18, 2024	Dec. 17, 2024
Enbridge Gas Ontario
Public Utilities, General Disclosures [Line Items]
Term of incentive regulation framework (in years)		5 years
Incremental expense of capitalized overheads		$ 50
Inflation stretch factor (as percent)		0.28%
Public utilities, approved, earnings sharing mechanism, additional share of earnings ( as percent)		90%
Enbridge Gas Ontario | Minimum
Public Utilities, General Disclosures [Line Items]
Earnings allowed to be retained under earnings sharing mechanism (as percent)		1%
Enbridge Gas Ontario | Maximum
Public Utilities, General Disclosures [Line Items]
Earnings allowed to be retained under earnings sharing mechanism (as percent)		3%
Enbridge Gas Ohio
Public Utilities, General Disclosures [Line Items]
Increase in base rate	$ 212
Proposed ROE (as percent)	10.40%
Authorized ROE (as percent)	10.38%
Annual revenue			$ 60	$ 212
Percentage of replacement under PIR program	25%
Interest rate (as a percent)	6.50%

REGULATORY MATTERS - Schedule o

REGULATORY MATTERS - Schedule of Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	$ 472	$ 470
Total long - term regulatory assets	7,147	5,237
Total regulatory assets	7,619	5,707
Regulatory Liabilities [Line Items]
Total current regulatory liabilities	616	307
Total long - term regulatory liabilities	6,112	3,521
Total regulatory liabilities	6,728	3,828
Purchase gas variance
Regulatory Liabilities [Line Items]
Total current regulatory liabilities	292	31
U.S income Taxes
Regulatory Liabilities [Line Items]
Total current regulatory liabilities	44	0
Total long - term regulatory liabilities	2,021	854
Other regulatory assets (liabilities)
Regulatory Liabilities [Line Items]
Total current regulatory liabilities	280	276
Total long - term regulatory liabilities	242	86
Future removal and restoration reserves
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities	2,964	1,693
Pipeline future abandonment costs
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities	826	745
Pension plan receivable
Regulatory Liabilities [Line Items]
Total long - term regulatory liabilities	59	143
Purchase gas variance
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	74	15
Under-recovery of fuel costs
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	4	75
Other regulatory assets (liabilities)
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	304	380
Total long - term regulatory assets	447	198
Deferred income taxes
Regulatory Assets [Line Items]
Total long - term regulatory assets	4,698	4,456
Deferred project costs
Regulatory Assets [Line Items]
Total current regulatory assets (Note9)	90	0
Total long - term regulatory assets	1,045	0
Long-term debt
Regulatory Assets [Line Items]
Total long - term regulatory assets	318	348
Negative salvage
Regulatory Assets [Line Items]
Total long - term regulatory assets	136	180
Demand-side management costs
Regulatory Assets [Line Items]
Total long - term regulatory assets	237	54
Pension plan receivable
Regulatory Assets [Line Items]
Total long - term regulatory assets	$ 266	$ 1

ACQUISITIONS AND DISPOSITIONS -

ACQUISITIONS AND DISPOSITIONS - Narrative (Details) $ in Millions, $ in Millions												3 Months Ended	7 Months Ended	10 Months Ended	12 Months Ended
	Sep. 30, 2024 CAD ($)	Sep. 30, 2024 USD ($)	May 31, 2024 CAD ($)	May 31, 2024 USD ($)	Mar. 06, 2024 CAD ($)	Mar. 06, 2024 USD ($)	Jan. 02, 2024 CAD ($) facility	Jan. 02, 2024 USD ($) facility	Nov. 01, 2023 CAD ($)	Sep. 27, 2022 CAD ($)	Sep. 27, 2022 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Jan. 02, 2024 USD ($)	Sep. 27, 2022 USD ($)
Business Acquisition [Line Items]
Number of production facilities acquired | facility							6	6
Public Service Company of North Carolina, Incorporated
Business Acquisition [Line Items]
Ownership interest acquired (as percent)	100%	100%
Purchase price	$ 2,700	$ 2,000
Cash	$ 2,710
Earnings attributable to common shareholders												$ 50			$ 5,149	$ 5,944
Operating revenues												$ 284			54,116	44,614
Questar Gas Company
Business Acquisition [Line Items]
Ownership interest acquired (as percent)			100%	100%
Purchase price			$ 4,100	$ 3,000
Cash			$ 4,144
Earnings attributable to common shareholders													$ 75		5,193	6,005
Operating revenues													$ 755		54,698	45,918
The East Ohio Gas Company
Business Acquisition [Line Items]
Purchase price					$ 5,800	$ 4,300
Revenues generated by acquiree														$ 1,200
Earnings generated by acquiree														$ 190
Cash					$ 5,852
Earnings attributable to common shareholders															5,130	5,961
Operating revenues															$ 53,788	$ 45,058
RNG Facilities
Business Acquisition [Line Items]
Purchase price							$ 1,348	$ 1,000
Cash							$ 584	$ 439
Remaining consideration payable, payment period							2 years	2 years
Contingent consideration payable							$ 757										$ 568
Aitken Creek Gas Storage
Business Acquisition [Line Items]
Cash									$ 400
Tri Global Energy, LLC
Business Acquisition [Line Items]
Purchase price										$ 344
Cash										295	$ 215
Contingent future payment (up to)										$ 72								$ 53
Aitken Creek Gas Storage Facility
Business Acquisition [Line Items]
Ownership interest acquired (as percent)									93.80%
Purchase price									$ 467
Cash									$ 397
Aitken Creek North Gas Storage Facility
Business Acquisition [Line Items]
Ownership interest acquired (as percent)									100%

ACQUISITIONS AND DISPOSITIONS_2

ACQUISITIONS AND DISPOSITIONS - Schedule of Estimated Fair Values Assigned to Net Assets and Final Purchase Price Allocation (Details) $ in Millions

Sep. 30, 2024 CAD ($)

Sep. 30, 2024 USD ($)

May 31, 2024 CAD ($)

May 31, 2024 USD ($)

Mar. 06, 2024 CAD ($)

Mar. 06, 2024 USD ($)

Jan. 02, 2024 CAD ($) promissoryNote

Jan. 02, 2024 USD ($)

Nov. 01, 2023 CAD ($)

Sep. 27, 2022 CAD ($)

Sep. 27, 2022 USD ($)

Dec. 31, 2024 CAD ($)

Jan. 02, 2024 USD ($) promissoryNote

Dec. 31, 2023 CAD ($)

Mar. 31, 2023 CAD ($)

Dec. 31, 2022 CAD ($)

Sep. 27, 2022 USD ($)

Fair value of net assets acquired:

Goodwill

$ 36,600,000,000

$ 31,848,000,000

$ 32,440,000,000

Deferred Consideration

Goodwill expected tax deductible period (in years)

15 years

Public Service Company of North Carolina, Incorporated

Fair value of net assets acquired:

Current assets

$ 303,000,000

Property, plant and equipment

4,147,000,000

Long-term assets

189,000,000

Current liabilities

277,000,000

Long-term debt

1,529,000,000

Other long-term liabilities

653,000,000

Deferred income tax liabilities

365,000,000

Goodwill

895,000,000

Purchase price:

Cash

2,710,000,000

Deferred Consideration

Purchase price

2,700,000,000

$ 2,000

Expected credit loss

2,000,000

Regulatory assets

114,000,000

Fair value adjustment of long-term debt

156,000,000

Fair value adjustment of regulatory offset

0

$ 0

Public Service Company of North Carolina, Incorporated | Carrying value

Deferred Consideration

Trade receivables

$ 70,000,000

Questar Gas Company

Fair value of net assets acquired:

Current assets

$ 380,000,000

Property, plant and equipment

6,013,000,000

Long-term assets

163,000,000

Current liabilities

416,000,000

Long-term debt

1,343,000,000

Other long-term liabilities

919,000,000

Deferred income tax liabilities

527,000,000

Goodwill

793,000,000

Purchase price:

Cash

4,144,000,000

Deferred Consideration

Purchase price

4,100,000,000

$ 3,000

Expected credit loss

9,000,000

Fair value adjustment of long-term debt

301,000,000

Fair value adjustment of regulatory offset

0

Questar Gas Company | Carrying value

Deferred Consideration

Trade receivables

$ 202,000,000

The East Ohio Gas Company

Fair value of net assets acquired:

Current assets

493,000,000

Property, plant and equipment

7,276,000,000

Long-term assets

1,689,000,000

Current liabilities

551,000,000

Long-term debt

2,612,000,000

Other long-term liabilities

1,001,000,000

Deferred income tax liabilities

1,045,000,000

Goodwill

1,603,000,000

Purchase price:

Cash

5,852,000,000

Deferred Consideration

Purchase price

5,800,000,000

$ 4,300

Expected credit loss

3,000,000

Overfunded pension plan assets

367,000,000

Regulatory assets

1,200,000,000

Fair value adjustment of long-term debt

478,000,000

The East Ohio Gas Company | Carrying value

Deferred Consideration

Trade receivables

$ 379,000,000

RNG Facilities

Fair value of net assets acquired:

Current assets

$ 31,000,000

Property, plant and equipment

174,000,000

Current liabilities

5,000,000

Goodwill

223,000,000

Purchase price:

Cash

584,000,000

$ 439

Deferred Consideration

Current portion of long-term debt

550,000,000

Long-term debt

207,000,000

Other adjustments

7,000,000

Purchase price

1,348,000,000

$ 1,000

Intangible assets

$ 925,000,000

Amortized on a straight-line basis over an weighted-average useful life (in years)

9 years

9 years

Goodwill expected tax deductible period (in years)

15 years

15 years

Number Of Non-Interest Promissory Notes | promissoryNote

6

6

Remaining consideration payable, payment period

2 years

2 years

Assumed debt

$ 757,000,000

$ 568

RNG Facilities | Non-Interest Bearing Promissory Notes | Notes Payable, Other Payables

Deferred Consideration

Contingent future payment (up to)

$ 808,000,000

$ 606

RNG Facilities | Minimum

Deferred Consideration

Amortized on a straight-line basis over an expected useful life (in years)

13 years

13 years

RNG Facilities | Maximum

Deferred Consideration

Amortized on a straight-line basis over an expected useful life (in years)

42 years

42 years

Aitken Creek Gas Storage Facility

Fair value of net assets acquired:

Current assets

$ 105,000,000

Property, plant and equipment

466,000,000

Current liabilities

20,000,000

Long-term debt

130,000,000

Goodwill

46,000,000

Purchase price:

Cash

397,000,000

Additional consideration

70,000,000

$ 70,000,000

Deferred Consideration

Purchase price

$ 467,000,000

Tri Global Energy, LLC

Fair value of net assets acquired:

Current assets

$ 5,000,000

Property, plant and equipment

3,000,000

Long-term investments

8,000,000

Long-term assets

3,000,000

Current liabilities

61,000,000

Long-term debt

18,000,000

Long-term debt

105,000,000

Goodwill

392,000,000

Purchase price:

Cash

295,000,000

$ 215

Additional consideration

49,000,000

$ 36

Deferred Consideration

Purchase price

344,000,000

Intangible assets

$ 117,000,000

Goodwill expected tax deductible period (in years)

15 years

15 years

Contingent future payment (up to)

$ 72,000,000

$ 53

ACQUISITIONS AND DISPOSITIONS_3

ACQUISITIONS AND DISPOSITIONS - Schedule of Supplemental Pro Forma Consolidated Financial Information (Details) - CAD ($) $ in Millions	3 Months Ended	7 Months Ended	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2023
Public Service Company of North Carolina, Incorporated
Business Acquisition [Line Items]
Operating revenues	$ 284		$ 54,116	$ 44,614
Earnings attributable to common shareholders	$ 50		5,149	5,944
Pro forma interest expense				48
Pro forma interest expense, net of tax				37
Questar Gas Company
Business Acquisition [Line Items]
Operating revenues		$ 755	54,698	45,918
Earnings attributable to common shareholders		$ 75	5,193	6,005
Pro forma interest expense				70
Pro forma interest expense, net of tax				53
The East Ohio Gas Company
Business Acquisition [Line Items]
Operating revenues			53,788	45,058
Earnings attributable to common shareholders			$ 5,130	5,961
Pro forma interest expense				100
Pro forma interest expense, net of tax				$ 77

ACQUISITIONS AND DISPOSITIONS_4

ACQUISITIONS AND DISPOSITIONS - Asset Acquisition (Narrative) (Details) - Apr. 03, 2023 - Tres Palacios Holdings LLC $ in Millions, $ in Millions	CAD ($)	USD ($)	USD ($)
Asset Acquisition [Line Items]
Payments to acquire oil and gas property and equipment	$ 451	$ 335
Property, plant and equipment, additions	790	$ 588
Property, plant, and equipment, right-of-use asset	254		$ 189
Current liabilities long term debt	7		5
Noncurrent liabilities long term debt	$ 248		$ 184

ACQUISITIONS AND DISPOSITIONS_5

ACQUISITIONS AND DISPOSITIONS - Dispositions (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Oct. 06, 2022	Oct. 05, 2022 CAD ($) _community pipeline
Dispositions | 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
Gain (loss) on disposal of interest	$ 0
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 | Dispositions | 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%
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]
Noncontrolling interest (percent)		88.40%

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Receivables [Abstract]
Derivative assets (Note 23)	$ 557	$ 623
Regulatory assets (Note 7)	472	470
Gas imbalances	517	209
Income taxes receivable	375	347
Other	849	791
Other current assets	$ 2,770	$ 2,440

INVENTORY (Details)

INVENTORY (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Inventory Disclosure [Abstract]
Natural gas	$ 811	$ 938
Crude oil	479	413
Other	198	128
Total Inventory	$ 1,488	$ 1,479

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 169,066	$ 137,199
Total accumulated depreciation	(37,962)	(32,558)
Property, plant and equipment, net	$ 131,104	104,641
Pipelines
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (as percent)	2.90%
Total property, plant and equipment	$ 73,633	66,698
Facilities and equipment
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (as percent)	3.20%
Total property, plant and equipment	$ 43,439	37,634
Land and right-of-way
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (as percent)	2.80%
Total property, plant and equipment	$ 4,181	3,600
Gas mains, services and other
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (as percent)	3%
Total property, plant and equipment	$ 26,925	15,346
Storage
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (as percent)	2.60%
Total property, plant and equipment	$ 6,455	4,929
Wind turbines, solar panels and other
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (as percent)	3.90%
Total property, plant and equipment	$ 4,798	4,511
Other
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (as percent)	8.60%
Total property, plant and equipment	$ 3,987	1,652
Under construction
Property, Plant and Equipment [Line Items]
Weighted average depreciation rate (as percent)	0%
Total property, plant and equipment	$ 5,648	2,829
Leased assets
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	5,300	5,100
Total accumulated depreciation	$ (2,300)	$ (2,100)

PROPERTY, PLANT AND EQUIPMENT_2

PROPERTY, PLANT AND EQUIPMENT - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Depreciation expense	$ 4,600	$ 4,000	$ 3,800
Chapman Ranch Wind Farm
Property, Plant and Equipment [Line Items]
Impairment loss		$ 251
Magic Valley Wind Farm
Property, Plant and Equipment [Line Items]
Impairment loss			227
Bakken Pipeline System
Property, Plant and Equipment [Line Items]
Impairment loss			$ 183

VARIABLE INTEREST ENTITIES - Sc

VARIABLE INTEREST ENTITIES - Schedule of Assets and Liabilities of Consolidated VIEs (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 1,803	$ 5,901
Restricted cash	92	84
Other current assets	2,770	2,440
Inventory	1,488	1,479
Current assets	13,163	14,399
Property, plant and equipment, net	131,104	104,641	$ 104,460
Long-term investments	20,691	16,793
Restricted long-term investments and cash	998	717
Deferred amounts and other assets	11,034	8,041
Intangible assets, net	4,587	3,537
Total assets	218,973	180,317
Current liabilities
Trade payables and accrued liabilities	7,060	4,308
Other current liabilities	7,241	5,659
Accounts payable to affiliates	22	26
Current liabilities	23,812	17,435
Long-term debt	93,414	74,715
Other long-term liabilities	13,258	8,653
Deferred income taxes	19,596	15,031
Liabilities	150,080	115,834
Variable Interest Entity, Primary Beneficiary
Current assets
Cash and cash equivalents	448	442
Restricted cash	11	9
Trade receivables and unbilled revenues	138	144
Other current assets	5	8
Inventory	13	11
Current assets	628	619
Property, plant and equipment, net	6,934	7,105
Long-term investments	20	14
Restricted long-term investments and cash	141	106
Deferred amounts and other assets	145	148
Intangible assets, net	77	84
Total assets	7,945	8,076
Current liabilities
Other current liabilities	124	145
Current liabilities	254	232
Long-term debt	0	1
Other long-term liabilities	1,133	971
Deferred income taxes	6	5
Liabilities	1,393	1,209
Net assets	6,552	6,867
Variable Interest Entity, Primary Beneficiary | Related Party
Current assets
Accounts receivable from affiliates	13	5
Current liabilities
Accounts payable to affiliates	22	4
Variable Interest Entity, Primary Beneficiary | Nonrelated Party
Current liabilities
Trade payables and accrued liabilities	$ 108	$ 83

VARIABLE INTEREST ENTITIES - _2

VARIABLE INTEREST ENTITIES - Schedule of the Carrying Amount of Interest in VIEs (Details) - CAD ($) $ in Millions	Dec. 31, 2024	May 29, 2024	Dec. 31, 2023	Nov. 30, 2023	Nov. 15, 2023
Woodfibre LNG LP | Significantly Influenced Investees | Gas Transmission
VARIABLE INTEREST ENTITY
Ownership interest (as percent)	30%
Whistler Parent JV
VARIABLE INTEREST ENTITY
Ownership interest (as percent)		19%
Whistler Parent JV | Significantly Influenced Investees | Gas Transmission
VARIABLE INTEREST ENTITY
Ownership interest (as percent)	19%	19%
Fox Squirrel Solar LLC
VARIABLE INTEREST ENTITY
Ownership interest (as percent)					50%
Fox Squirrel Solar LLC | Affiliated Entity | Renewable Power Generation
VARIABLE INTEREST ENTITY
Ownership interest (as percent)				50%
Fox Squirrel Solar LLC | Significantly Influenced Investees | Renewable Power Generation
VARIABLE INTEREST ENTITY
Ownership interest (as percent)	50%
Variable Interest Entity, Not Primary Beneficiary
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	$ 3,125		$ 1,909
Maximum exposure to loss	5,883		4,647
Variable Interest Entity, Not Primary Beneficiary | Aux Sable Liquid Products, L.P.
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE			105
Maximum exposure to loss			130
Variable Interest Entity, Not Primary Beneficiary | Rampion Offshore Wind Limited
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	387		391
Maximum exposure to loss	490		452
Variable Interest Entity, Not Primary Beneficiary | Rampion Offshore Wind Limited | Affiliated Entity
VARIABLE INTEREST ENTITY
Affiliate loan receivable	73		0
Variable Interest Entity, Not Primary Beneficiary | Vector Pipeline L.P.
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	193		191
Maximum exposure to loss	314		320
Variable Interest Entity, Not Primary Beneficiary | Vector Pipeline L.P. | Affiliated Entity
VARIABLE INTEREST ENTITY
Affiliate loan receivable	16		24
Credit facility provided	105		105
Variable Interest Entity, Not Primary Beneficiary | Woodfibre LNG LP
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	1,275		778
Maximum exposure to loss	3,153		2,854
Variable Interest Entity, Not Primary Beneficiary | Whistler Parent JV
VARIABLE INTEREST ENTITY
Carrying amount of investment in VIE	1,102
Maximum exposure to loss	1,425
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	168		132
Maximum exposure to loss	$ 501		$ 230

LONG-TERM INVESTMENTS - Schedul

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

12 Months Ended

Oct. 31, 2024 CAD ($)

Oct. 31, 2024 USD ($)

Apr. 01, 2024 CAD ($)

Jan. 09, 2023 CAD ($)

Jan. 09, 2023 USD ($)

Dec. 31, 2024 CAD ($)

Dec. 31, 2023 CAD ($)

Dec. 31, 2022 CAD ($)

May 29, 2024

May 28, 2024

Nov. 15, 2023

Mar. 18, 2021 project

Schedule of Equity Method Investments [Line Items]

Total long-term investments

$ 20,691

$ 16,793

Proceeds from sale of equity method investments

0

0

$ 522

Proceeds from non-recourse debt

99

71

$ 0

Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Total long-term investments

$ 20,691

16,793

Cactus II Pipeline LLC | Long-Term Investments | Liquids Pipelines

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

30%

Equity method investments

$ 651

618

DCP Midstream, LLC | Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

56.50%

DCP Midstream, LLC | Long-Term Investments | Class A units

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

23.40%

DCP Midstream, LLC | Long-Term Investments | Class B units

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

90%

DCP Midstream, LLC | Long-Term Investments | Liquids Pipelines

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

90%

Equity method investments

$ 1,554

1,486

DCP Midstream, LLC | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

23.40%

Equity method investments

$ 480

367

Illinois Extension Pipeline Company, L.L.C. | Long-Term Investments | Liquids Pipelines

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

65%

Equity method investments

$ 608

584

MarEn Bakken Company LLC | Long-Term Investments | Liquids Pipelines

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

75%

Equity method investments

$ 2,296

1,819

Seaway Crude Holdings LLC | Long-Term Investments | Liquids Pipelines

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Equity method investments

$ 2,820

2,661

Other | Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Other long-term investments

1,032

430

Other | Long-Term Investments | Liquids Pipelines

Schedule of Equity Method Investments [Line Items]

Equity method investments

$ 96

84

Other | Long-Term Investments | Liquids Pipelines | Minimum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

30%

Other | Long-Term Investments | Liquids Pipelines | Maximum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

43.80%

Other | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Other long-term investments

$ 23

22

Other | Long-Term Investments | Gas Distribution and Storage

Schedule of Equity Method Investments [Line Items]

Equity method investments

67

22

Other long-term investments

$ 27

24

Other | Long-Term Investments | Gas Distribution and Storage | Minimum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

17%

Other | Long-Term Investments | Gas Distribution and Storage | Maximum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Other | Long-Term Investments | Renewable Power Generation

Schedule of Equity Method Investments [Line Items]

Equity method investments

$ 93

110

Other long-term investments

$ 21

21

Other | Long-Term Investments | Renewable Power Generation | Minimum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

16.40%

Other | Long-Term Investments | Renewable Power Generation | Maximum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Other | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Equity method investments

$ 49

0

Other | Long-Term Investments | Gas Transmission | Minimum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

21.30%

Other | Long-Term Investments | Gas Transmission | Maximum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

45%

Alliance Pipeline | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Equity method investments

$ 0

359

Aux Sable | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

42.70%

Equity method investments

$ 0

229

Aux Sable | Long-Term Investments | Gas Transmission | Minimum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

42.70%

Aux Sable | Long-Term Investments | Gas Transmission | Maximum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Delaware Basin Residue, LLC | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

15%

15%

15%

Equity method investments

$ 319

0

Payments to acquire equity method investments

$ 303

$ 220

Gulfstream Natural Gas System, L.L.C. | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Equity method investments

$ 1,316

1,224

NEXUS Gas Transmission, LLC | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Equity method investments

$ 1,301

1,220

Sabal Trail Transmission, LLC | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Equity method investments

$ 1,565

1,467

Southeast Supply Header, LLC | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Equity method investments

$ 355

80

Steckman Ridge, LP | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Equity method investments

$ 101

87

Vector Pipeline Limited | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

60%

Equity method investments

$ 193

191

Whistler Parent JV

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

19%

Whistler Parent JV | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

19%

19%

Equity method investments

$ 1,102

0

Woodfibre LNG LP | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

30%

Equity method investments

$ 1,275

777

Offshore - various joint ventures | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Equity method investments

$ 260

217

Offshore - various joint ventures | Long-Term Investments | Gas Transmission | Minimum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

22%

Offshore - various joint ventures | Long-Term Investments | Gas Transmission | Maximum

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

74.30%

East-West Tie Limited Partnership | Long-Term Investments | Renewable Power Generation

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

24.10%

Equity method investments

$ 106

132

EIH S.a.r.l. | Long-Term Investments | Renewable Power Generation

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

51%

Equity method investments

$ 89

52

Fox Squirrel Solar LLC

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Fox Squirrel Solar LLC | Long-Term Investments | Renewable Power Generation

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Equity method investments

$ 783

312

Hohe See and Albatros Offshore Wind Facilities | Long-Term Investments | Renewable Power Generation

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

49.90%

Equity method investments

$ 1,606

1,701

Rampion Offshore Wind Limited | Long-Term Investments | Renewable Power Generation

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

24.90%

Equity method investments

$ 387

391

Ara Divert HoldCo, Inc. | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Other long-term investments

$ 116

$ 106

Gray Oak Pipeline, LLC | Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

68.50%

68.50%

58.50%

Equity method investment direct ownership interest (as percent)

0.100

0.100

Cash consideration

$ 230

$ 172

Gray Oak Pipeline, LLC | Long-Term Investments | DCP Midstream, LLC

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

65%

Bakken Pipeline LLC | Long-Term Investments | MarEn Bakken Company LLC

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

49%

Bakken Pipeline System | Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

27.60%

Bakken Pipeline System | Long-Term Investments | Bakken Pipeline LLC

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

75%

Pembina Pipeline Corporation | Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Proceeds from sale of equity method investments

$ 3,100

Proceeds from non-recourse debt

$ 300

DCP Midstream, LP | Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

13.20%

Rio Bravo

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

25%

100%

Special ownership interest (percent)

39.30%

Rio Bravo | Long-Term Investments | Whistler Parent JV

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

100%

Rio Bravo | Long-Term Investments | Gas Transmission

Schedule of Equity Method Investments [Line Items]

Special ownership interest (percent)

25%

Eolien Maritime France Sas | Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

50%

Number of offshore wind projects | project

3

Saint-Nazaire | Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

25.50%

Fécamp | Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

17.90%

Calvados | Long-Term Investments

Schedule of Equity Method Investments [Line Items]

Ownership interest (as percent)

21.70%

LONG-TERM INVESTMENTS - Narrati

LONG-TERM INVESTMENTS - Narrative (Details) - CAD ($) $ in Billions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
Goodwill of investee	$ 3.7	$ 3.5
Amortizable assets of investee	1.7	1.7
Dividends received from equity investments	$ 2.9	$ 3.1	$ 2.6

LONG-TERM INVESTMENTS - Sched_2

LONG-TERM INVESTMENTS - Schedule of Combined Financial Information (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income statement information
Revenues	$ 16,217	$ 14,882	$ 11,336	$ 11,038	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 53,473	$ 43,649	$ 53,309
Earnings	618	1,447	2,001	1,565	1,568	623	2,001	1,866	5,631	6,058	2,938
Earnings attributable to controlling interests	595	$ 1,391	$ 1,943	$ 1,512	1,818	$ 621	$ 1,935	$ 1,817	5,441	6,191	3,003
Balance sheet information
Current assets	13,163				14,399				13,163	14,399
Current liabilities	23,812				17,435				23,812	17,435
Noncontrolling interests	2,993				3,029				2,993	3,029
Unconsolidated equity method investments
Income statement information
Revenues									20,657	22,586	30,026
Operating expenses									14,692	17,111	23,835
Earnings									5,177	4,818	5,123
Earnings attributable to controlling interests									2,304	1,816	$ 2,056
Balance sheet information
Current assets	8,611				5,842				8,611	5,842
Non-current assets	69,381				61,141				69,381	61,141
Current liabilities	7,240				6,194				7,240	6,194
Non-current liabilities	27,491				23,957				27,491	23,957
Noncontrolling interests	$ 4,979				$ 4,124				$ 4,979	$ 4,124

LONG-TERM INVESTMENTS - Disposi

LONG-TERM INVESTMENTS - Disposition (Details) $ in Millions, $ in Millions			12 Months Ended
	Aug. 17, 2022 CAD ($)	Aug. 17, 2022 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Apr. 01, 2024 CAD ($)	Mar. 31, 2024
Schedule of Equity Method Investments [Line Items]
Gain on sale	$ 1,100	$ 832	$ 0	$ 0	$ 1,076
Goodwill			36,600	31,848	32,440
Gas Transmission
Schedule of Equity Method Investments [Line Items]
Goodwill			18,278	$ 17,727	$ 18,106
Disposal Group, Alliance Pipeline And Aux Sable
Schedule of Equity Method Investments [Line Items]
Gain on sale			$ 1,100
Disposal Group, Alliance Pipeline And Aux Sable | Gas Transmission
Schedule of Equity Method Investments [Line Items]
Goodwill						$ 1,000
Disposal Group, Alliance Pipeline And Aux Sable | Pembina Pipeline Corporation
Schedule of Equity Method Investments [Line Items]
Disposal group, consideration						3,100
Non-recourse debt						$ 327
Alliance Pipeline | Disposal Group, Alliance Pipeline And Aux Sable
Schedule of Equity Method Investments [Line Items]
Ownership interest (as percent)							50%

LONG-TERM INVESTMENTS - Equity

LONG-TERM INVESTMENTS - Equity Investment Transaction (Details) € in Millions, $ in Millions, $ in Millions									12 Months Ended
	May 29, 2024 CAD ($)	May 29, 2024 USD ($)	Nov. 15, 2023 CAD ($)	Nov. 15, 2023 USD ($)	Nov. 03, 2023 CAD ($)	Nov. 03, 2023 EUR (€)	Aug. 17, 2022 CAD ($)	Aug. 17, 2022 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	May 28, 2024	Nov. 03, 2023 EUR (€)	Aug. 16, 2022
Schedule of Equity Method Investments [Line Items]
Long-term debt									$ 101,819
Proceeds from sale of equity method investments							$ 522	$ 404
Gain on joint venture merger transaction							$ 1,100	$ 832	$ 0	$ 0	$ 1,076
Whistler Parent JV
Schedule of Equity Method Investments [Line Items]
Ownership interest (as percent)	19%	19%
Cash consideration includes an upfront payment	$ 487	$ 357
Reduction to property, plant and equipment, net and increase to long-term investments	$ 321	$ 235
Whistler Parent JV | WhiteWaterI Squared
Schedule of Equity Method Investments [Line Items]
Ownership interest (as percent)	50.60%	50.60%
Whistler Parent JV | MPLX
Schedule of Equity Method Investments [Line Items]
Ownership interest (as percent)	30.40%	30.40%
Rio Bravo
Schedule of Equity Method Investments [Line Items]
Ownership interest (as percent)	25%	25%										100%
Capital Expenditure, Discontinued Operations		$ 150
Fox Squirrel Solar LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as percent)			50%	50%
Cash consideration includes an upfront payment			$ 157	$ 115
Investment company committed capital threshold amount			$ 591	$ 426
Hohe See Offshore And Albatros Offshore Wind Farm
Schedule of Equity Method Investments [Line Items]
Ownership interest (as percent)					49.90%								49.90%
Ownership interest acquired additionally (as a percent)					24.45%								24.45%
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
Schedule of Equity Method Investments [Line Items]
Ownership interest acquired additionally (as a percent)					49%								49%
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 percent)							58.50%	58.50%						22.80%
DCP LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as percent)							13.20%	13.20%						28.30%

INTANGIBLE ASSETS - Schedule of

INTANGIBLE ASSETS - Schedule of Intangible Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
INTANGIBLE ASSETS
Cost	$ 7,130	$ 5,552
Accumulated Amortization	(2,543)	(2,015)
Net	$ 4,587	$ 3,537
Software
INTANGIBLE ASSETS
Weighted Average Amortization Rate	10.90%	12%
Cost	$ 2,109	$ 1,921
Accumulated Amortization	(1,222)	(1,090)
Net	$ 887	$ 831
Power purchase agreements
INTANGIBLE ASSETS
Weighted Average Amortization Rate	4.50%	4.30%
Cost	$ 58	$ 58
Accumulated Amortization	(26)	(24)
Net	$ 32	$ 34
Project agreement
INTANGIBLE ASSETS
Weighted Average Amortization Rate	4%	4%
Cost	$ 173	$ 158
Accumulated Amortization	(52)	(41)
Net	$ 121	$ 117
Customer relationships
INTANGIBLE ASSETS
Weighted Average Amortization Rate	8.60%	8.60%
Cost	$ 2,856	$ 2,636
Accumulated Amortization	(975)	(675)
Net	$ 1,881	$ 1,961
Biogas rights agreements
INTANGIBLE ASSETS
Weighted Average Amortization Rate	3.40%
Cost	$ 999
Accumulated Amortization	(34)
Net	$ 965
Other intangible assets
INTANGIBLE ASSETS
Weighted Average Amortization Rate	5.80%	8.20%
Cost	$ 665	$ 603
Accumulated Amortization	(234)	(185)
Net	$ 431	$ 418
Under development
INTANGIBLE ASSETS
Weighted Average Amortization Rate	0%	0%
Cost	$ 270	$ 176
Accumulated Amortization	0	0
Net	$ 270	$ 176

INTANGIBLE ASSETS - Narrative (

INTANGIBLE ASSETS - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense for intangible assets	$ 530	$ 535	$ 483
2025	558
2026	558
2027	558
2028	558
2029	$ 558

GOODWILL (Details)

GOODWILL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 31,848	$ 32,440
Foreign exchange and other	2,264	(638)
Dispositions	(1,026)
Acquisition	3,514	46
Goodwill, ending balance	36,600	31,848
Goodwill, gross at end of period	40,700	35,900
Goodwill accumulated impairment	4,100	4,100
Goodwill, written off related to sale of business unit	1,026
Aitken Creek Gas Storage Facility
Goodwill [Roll Forward]
Acquisition		46
Public Service Company of North Carolina, Incorporated
Goodwill [Roll Forward]
Acquisition	895
Questar Gas Company
Goodwill [Roll Forward]
Acquisition	793
The East Ohio Gas Company
Goodwill [Roll Forward]
Acquisition	1,600
RNG Facilities
Goodwill [Roll Forward]
Acquisition	223
Disposal Group, Alliance Pipeline And Aux Sable
Goodwill [Roll Forward]
Dispositions	(1,000)
Goodwill, written off related to sale of business unit	1,000
Liquids Pipelines
Goodwill [Roll Forward]
Goodwill, beginning balance	8,344	8,549
Foreign exchange and other	672	(205)
Dispositions	0
Acquisition	0	0
Goodwill, ending balance	9,016	8,344
Goodwill, written off related to sale of business unit	0
Gas Transmission
Goodwill [Roll Forward]
Goodwill, beginning balance	17,727	18,106
Foreign exchange and other	1,354	(425)
Dispositions	(1,026)
Acquisition	223	46
Goodwill, ending balance	18,278	17,727
Goodwill, written off related to sale of business unit	1,026
Gas Distribution and Storage
Goodwill [Roll Forward]
Goodwill, beginning balance	5,397	5,397
Foreign exchange and other	204	0
Dispositions	0
Acquisition	3,291	0
Goodwill, ending balance	8,892	5,397
Goodwill, written off related to sale of business unit	0
Renewable Power Generation
Goodwill [Roll Forward]
Goodwill, beginning balance	380	388
Foreign exchange and other	34	(8)
Dispositions	0
Acquisition	0	0
Goodwill, ending balance	414	$ 380
Goodwill, written off related to sale of business unit	$ 0

OTHER CURRENT LIABILITIES (Deta

OTHER CURRENT LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Payables and Accruals [Abstract]
Dividends payable	$ 2,088	$ 1,975
Deferred credits	1,072	1,177
Derivative liabilities	1,335	738
Taxes payable	959	596
Regulatory liabilities	616	307
Federal carbon program liability	498	376
Asset retirement obligations	120	136
Other	553	354
Other current liabilities	$ 7,241	$ 5,659

DEBT - Schedule of Debt (Detail

DEBT - Schedule of Debt (Details) € in Millions, $ in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2024 EUR (€)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 EUR (€)
DEBT
Total debt	$ 101,672			$ 81,199
Fair value adjustment	(468)			514
Other	(522)			(439)
Current maturities	(7,729)			(6,084)
Short-term borrowings	(529)			(400)
Long-term debt	93,414			74,715
Long-term debt	$ 40,000	$ 43	€ 316	$ 37,000	$ 33	€ 359
Weighted average interest rate (as a percent)	3.40%	3.40%	3.40%	5.20%	5.20%	5.20%
US dollar senior notes | Enbridge Inc.
DEBT
Weighted average interest rate (as percent)	4.80%	4.80%	4.80%
Total debt	$ 19,703			$ 14,636
Medium-term notes | Enbridge Gas Inc.
DEBT
Weighted average interest rate (as percent)	4.10%	4.10%	4.10%
Total debt	$ 9,970			10,185
Medium-term notes | Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (as percent)	4.20%	4.20%	4.20%
Total debt	$ 5,425			5,425
Carrying value	$ 100
Medium-term notes | Westcoast Energy Inc.
DEBT
Weighted average interest rate (as percent)	5.40%	5.40%	5.40%
Total debt	$ 875			1,225
Medium-term notes | Enbridge Inc.
DEBT
Weighted average interest rate (as percent)	4.50%	4.50%	4.50%
Total debt	$ 9,900			8,598
Sustainability-linked bonds | Enbridge Inc.
DEBT
Weighted average interest rate (as percent)	4.70%	4.70%	4.70%
Total debt	$ 7,146			6,751
Fixed-to-fixed subordinated term notes | Enbridge Inc.
DEBT
Weighted average interest rate (as percent)	7.40%	7.40%	7.40%
Total debt	$ 9,372			7,156
Fixed-to-fixed subordinated term notes | Enbridge Inc. | Initial Period
DEBT
Term of fixed rate (in years)	5 years
Fixed-to-fixed subordinated term notes | Enbridge Inc. | Period Two
DEBT
Term of fixed rate (in years)	5 years 6 months
Fixed-to-fixed subordinated term notes | Enbridge Inc. | Period Three
DEBT
Term of fixed rate (in years)	9 years 9 months
Fixed-to-fixed subordinated term notes | Enbridge Inc. | Period Four
DEBT
Term of fixed rate (in years)	10 years
Fixed-to-floating rate subordinated term notes | Enbridge Inc.
DEBT
Weighted average interest rate (as percent)	5.80%	5.80%	5.80%
Total debt	$ 6,139			5,828
Fixed-to-floating rate subordinated term notes | Enbridge Inc. | Initial Period
DEBT
Term of fixed rate (in years)	5 years
Fixed-to-floating rate subordinated term notes | Enbridge Inc. | Period Two
DEBT
Term of fixed rate (in years)	10 years
Floating rate notes | Enbridge Inc.
DEBT
Total debt	$ 0			791
Fixed-to-floating non-call notes | Enbridge Inc.
DEBT
Weighted average interest rate (as percent)
Total debt	$ 0			923
Commercial paper and credit facility draws | Enbridge (U.S.) Inc.
DEBT
Weighted average interest rate (as percent)	4.80%	4.80%	4.80%
Total debt	$ 4,707			670
Commercial paper and credit facility draws | Enbridge Gas Inc.
DEBT
Weighted average interest rate (as percent)	3.40%	3.40%	3.40%
Total debt	$ 530			400
Commercial paper and credit facility draws | Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (as percent)	3.80%	3.80%	3.80%
Total debt	$ 509			449
Commercial paper and credit facility draws | Enbridge Inc.
DEBT
Weighted average interest rate (as percent)	3.70%	3.70%	3.70%
Total debt	$ 5,843			3,177
Senior notes | Enbridge Energy Partners, L.P.
DEBT
Weighted average interest rate (as percent)	6.50%	6.50%	6.50%
Total debt	$ 3,524			3,231
Senior notes | Enbridge Pipelines (Southern Lights) L.L.C.
DEBT
Weighted average interest rate (as percent)	4%	4%	4%
Total debt	$ 736			791
Senior notes | Enbridge Southern Lights LP
DEBT
Weighted average interest rate (as percent)	4%	4%	4%
Total debt	$ 183			214
Senior notes | Spectra Energy Capital, LLC
DEBT
Weighted average interest rate (as percent)	7.10%	7.10%	7.10%
Total debt	$ 248			228
Senior notes | Algonquin Gas Transmission, LLC
DEBT
Weighted average interest rate (as percent)	4.40%	4.40%	4.40%
Total debt	$ 1,222			1,121
Senior notes | East Tennessee Natural Gas, LLC
DEBT
Weighted average interest rate (as percent)	5.70%	5.70%	5.70%
Total debt	$ 662			251
Senior notes | Texas Eastern Transmission, LP
DEBT
Weighted average interest rate (as percent)	4.70%	4.70%	4.70%
Total debt	$ 3,667			3,362
Senior notes | Spectra Energy Partners, LP
DEBT
Weighted average interest rate (as percent)	4.20%	4.20%	4.20%
Total debt	$ 3,164			4,220
Senior notes | Blauracke GmbH
DEBT
Weighted average interest rate (as percent)	2.10%	2.10%	2.10%
Total debt	$ 471			521
Senior notes | The East Ohio Gas Company
DEBT
Weighted average interest rate (as percent)	3.10%	3.10%	3.10%
Total debt	$ 3,308			0
Senior notes | Questar Gas Company
DEBT
Weighted average interest rate (as percent)	4.20%	4.20%	4.20%
Total debt	$ 2,028			0
Senior notes | Public Service Company of North Carolina, Incorporated
DEBT
Weighted average interest rate (as percent)	5%	5%	5%
Total debt	$ 1,798			0
Senior notes | Enbridge Holdings (Tomorrow RNG), LLC
DEBT
Weighted average interest rate (as percent)	4.90%	4.90%	4.90%
Total debt	$ 817			0
Debentures | Enbridge Gas Inc.
DEBT
Weighted average interest rate (as percent)	8.70%	8.70%	8.70%
Total debt	$ 125			210
Debentures | Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (as percent)
Total debt	$ 0			200
Debentures | Westcoast Energy Inc.
DEBT
Weighted average interest rate (as percent)	8.10%	8.10%	8.10%
Total debt	$ 275			275
Other | Enbridge (U.S.) Inc.
DEBT
Total debt	276			263
Other | Enbridge Gas Inc.
DEBT
Total debt	1			2
Other | Enbridge Pipelines Inc.
DEBT
Total debt	2			4
Other | The East Ohio Gas Company
DEBT
Total debt	24			0
Other | Enbridge Inc.
DEBT
Total debt	$ 12			$ 17

DEBT - Schedule of Committed Cr

DEBT - Schedule of Committed Credit Facilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)
Committed credit facilities
DEBT
Total Facilities	$ 24,153
Draws	11,589
Available	$ 12,564
Term out option period (in years)	1 year
Enbridge (U.S.) Inc.
DEBT
Total Facilities	$ 10,813
Draws	4,707
Available	6,106
Enbridge Pipelines Inc.
DEBT
Total Facilities	2,000
Draws	509
Available	1,491
Enbridge Gas Inc.
DEBT
Total Facilities	2,500
Draws	530
Available	1,970
Enbridge Inc.
DEBT
Total Facilities	8,840
Draws	5,843
Available	$ 2,997

DEBT - Narrative (Details)

DEBT - Narrative (Details) $ in Millions					1 Months Ended				12 Months Ended
	Sep. 30, 2024 USD ($)	May 31, 2024 USD ($)	Mar. 06, 2024 USD ($)	Jan. 02, 2024 USD ($)	Oct. 31, 2024 CAD ($)	Jul. 31, 2024 CAD ($)	Jun. 30, 2024 USD ($)	Jan. 31, 2024 CAD ($)	Dec. 31, 2024 CAD ($)	Mar. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)
Line of Credit Facility [Line Items]
Long-term debt (Note 17)									$ 93,414,000,000		$ 74,715,000,000
The East Ohio Gas Company
Line of Credit Facility [Line Items]
Increase (decrease) in debt			$ 1,900
RNG Facilities
Line of Credit Facility [Line Items]
Increase (decrease) in debt				$ 568
Questar Acquisition
Line of Credit Facility [Line Items]
Increase (decrease) in debt		$ 1,000
Public Service Company of North Carolina, Incorporated
Line of Credit Facility [Line Items]
Increase (decrease) in debt	$ 1,100
Enbridge Gas Inc.
Line of Credit Facility [Line Items]
Credit facility capacity									2,500,000,000
Available									1,970,000,000
Enbridge Pipelines Inc.
Line of Credit Facility [Line Items]
Credit facility capacity									2,000,000,000
Available									1,491,000,000
Commercial paper and credit facility draws
Line of Credit Facility [Line Items]
Long-term debt (Note 17)									10,300,000,000		3,800,000,000
Committed credit facilities
Line of Credit Facility [Line Items]
Credit facility capacity									$ 24,153,000,000
Term out option period (in years)									1 year
Available									$ 12,564,000,000
Committed credit facilities | Delayed-Draw Term Loan Facility Maturing In March 2049
Line of Credit Facility [Line Items]
Credit facility capacity										$ 200,000,000
Committed credit facilities | 364-Day Extendible Credit Facility | Enbridge Gas Inc.
Line of Credit Facility [Line Items]
Term of credit facility						364 days
Term out option period (in years)						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 (in years)						1 year
Non-Revolving Term Loan Facility | Non-Revolving Term Loan Facility Maturing In June 2029
Line of Credit Facility [Line Items]
Credit facility capacity							$ 250
Term of credit facility							5 years
Revolving Credit Facility | 364-Day Extendible Credit Facility
Line of Credit Facility [Line Items]
Credit facility capacity						$ 8,800,000,000
Term of credit facility						364 days
Term out option period (in years)						1 year
Revolving Credit Facility | Five-Year Credit Facilities
Line of Credit Facility [Line Items]
Credit facility capacity						$ 7,800,000,000
Term of credit facility						5 years
Revolving Credit Facility | Term Loan Maturing In July 2027
Line of Credit Facility [Line Items]
Term of credit facility						3 years
Uncommitted Credit Facilities
Line of Credit Facility [Line Items]
Credit facility capacity									1,400,000,000		1,100,000,000
Available									$ 931,000,000		$ 572,000,000
Weighted average standby fee (as a percent)									0.10%
Letter of Credit
Line of Credit Facility [Line Items]
Line of credit facility, increase (decrease)					$ 200,000,000			$ 146,000,000

DEBT - Schedule of Long-term De

DEBT - Schedule of Long-term Debt Issuances (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2024 CAD ($)	Aug. 31, 2024 CAD ($)	Jul. 31, 2024 USD ($)	Jun. 30, 2024 USD ($)	Apr. 30, 2024 USD ($)
Long-Term Debt
Debt Instrument [Line Items]
Principal amount	$ 5,700	$ 1,800
Enbridge Inc. | 5.25% Senior Notes Due April 2027
Debt Instrument [Line Items]
Interest rate (as a percent)						5.25%
Principal amount						$ 750
Enbridge Inc. | 5.30% Senior Notes Due April 2029
Debt Instrument [Line Items]
Interest rate (as a percent)						5.30%
Principal amount						$ 750
Enbridge Inc. | 5.63% Senior Notes Due April 2034
Debt Instrument [Line Items]
Interest rate (as a percent)						5.63%
Principal amount						$ 1,200
Enbridge Inc. | 5.95% Senior Notes Due April 2054
Debt Instrument [Line Items]
Interest rate (as a percent)						5.95%
Principal amount						$ 800
Enbridge Inc. | Fixed-to-Fixed Subordinated Notes Due March 2055
Debt Instrument [Line Items]
Interest rate (as a percent)					7.38%
Principal amount					$ 500
Enbridge Inc. | Fixed-to-Fixed Subordinated Note Due June 2054
Debt Instrument [Line Items]
Interest rate (as a percent)					7.20%
Principal amount					$ 700
Enbridge Inc. | 4.21% medium-term notes due February 2030
Debt Instrument [Line Items]
Interest rate (as a percent)			4.21%
Principal amount			$ 600
Enbridge Inc. | 4.73% medium-term notes due August 2034
Debt Instrument [Line Items]
Interest rate (as a percent)			4.73%
Principal amount			$ 800
Enbridge Inc. | 5.32% medium-term notes due August 2054
Debt Instrument [Line Items]
Interest rate (as a percent)			5.32%
Principal amount			$ 400
Enbridge Inc. | Initial Period | Fixed-to-Fixed Subordinated Notes Due March 2055
Debt Instrument [Line Items]
Term of credit facility	5 years 6 months
Enbridge Inc. | Initial Period | Fixed-to-Fixed Subordinated Note Due June 2054
Debt Instrument [Line Items]
Term of credit facility	9 years 9 months
Enbridge Inc. | Period Two | Fixed-to-Fixed Subordinated Notes Due March 2055
Debt Instrument [Line Items]
Basis spread on variable rate (as percent)	3.12%
Enbridge Inc. | Period Two | Fixed-to-Fixed Subordinated Note Due June 2054
Debt Instrument [Line Items]
Basis spread on variable rate (as percent)	2.97%
Algonquin Gas Transmission, LLC | 5.95% senior notes due July 2034
Debt Instrument [Line Items]
Interest rate (as a percent)				5.95%
Principal amount				$ 350
East Tennessee Natural Gas, LLC | 5.73% senior notes due December 2034
Debt Instrument [Line Items]
Interest rate (as a percent)	5.72%	5.72%
Principal amount	$ 460
Questar Gas Company | 5.33% senior notes due December 2034
Debt Instrument [Line Items]
Interest rate (as a percent)	5.33%	5.33%
Principal amount	$ 200

DEBT - Schedule of Long-Term _2

DEBT - Schedule of Long-Term Debt Repayments (Details) € in Millions, $ in Millions, $ in Millions	1 Months Ended										7 Months Ended		12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2024 CAD ($)	Nov. 30, 2024 CAD ($)	Sep. 30, 2024 CAD ($)	Aug. 31, 2024 CAD ($)	Jul. 31, 2024 USD ($)	Jun. 30, 2024 USD ($)	Mar. 31, 2024 USD ($)	Feb. 29, 2024 USD ($)	Feb. 29, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Oct. 31, 2024 EUR (€)	Dec. 31, 2024 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 EUR (€)
Long-Term Debt
Debt Instrument [Line Items]
Extinguishment of debt													$ 3,900	$ 1,400	€ 43
Enbridge Gas Inc. | 3.15% medium-term notes
Debt Instrument [Line Items]
Interest rate (as a percent)					3.15%
Extinguishment of debt					$ 215
Enbridge Gas Inc. | 9.85% debentures
Debt Instrument [Line Items]
Interest rate (as a percent)	9.85%	9.85%									9.85%		9.85%	9.85%	9.85%
Extinguishment of debt		$ 85
Enbridge Pipelines (Southern Lights) L.L.C. | 3.98% Senior Notes Due 2040
Debt Instrument [Line Items]
Interest rate (as a percent)	3.98%	3.98%									3.98%		3.98%	3.98%	3.98%
Extinguishment of debt											$ 89
Enbridge Pipelines Inc. | 8.20% Debentures
Debt Instrument [Line Items]
Interest rate (as a percent)									8.20%	8.20%
Extinguishment of debt										$ 200
Enbridge Southern Lights LP | 4.01% Senior Notes
Debt Instrument [Line Items]
Interest rate (as a percent)	4.01%	4.01%									4.01%		4.01%	4.01%	4.01%
Extinguishment of debt														$ 31
Westcoast Energy Inc. | 3.43% Medium-Term Notes
Debt Instrument [Line Items]
Interest rate (as a percent)				3.43%
Extinguishment of debt				$ 350
Spectra Energy Partners, LP | 4.75% Senior Notes
Debt Instrument [Line Items]
Interest rate (as a percent)								4.75%
Extinguishment of debt								$ 1,000
Blauracke GmbH | 2.10% Senior Notes
Debt Instrument [Line Items]
Interest rate (as a percent)												2.10%
Extinguishment of debt | €												€ 43
Algonquin Gas Transmission, LLC | 3.51% senior notes
Debt Instrument [Line Items]
Interest rate (as a percent)						3.51%
Extinguishment of debt						$ 350
Questar Gas Company | 2.98% senior notes
Debt Instrument [Line Items]
Interest rate (as a percent)	2.98%	2.98%									2.98%		2.98%	2.98%	2.98%
Extinguishment of debt	$ 40
East Tennessee Natural Gas, LLC | 3.10% senior notes
Debt Instrument [Line Items]
Interest rate (as a percent)	3.10%	3.10%									3.10%		3.10%	3.10%	3.10%
Extinguishment of debt	$ 190
Enbridge Inc. | 2.15% Senior Notes
Debt Instrument [Line Items]
Interest rate (as a percent)									2.15%	2.15%
Extinguishment of debt									$ 400
Enbridge Inc. | 5.97% Senior Notes
Debt Instrument [Line Items]
Interest rate (as a percent)								5.97%
Extinguishment of debt								$ 700
Debt instrument, callable term								1 year
Enbridge Inc. | 3.50% Senior Notes
Debt Instrument [Line Items]
Interest rate (as a percent)							3.50%
Extinguishment of debt							$ 500
Enbridge Inc. | 3.95% Senior Notes
Debt Instrument [Line Items]
Interest rate (as a percent)			3.95%
Extinguishment of debt			$ 500
Enbridge Inc. | Floating Rate Notes
Debt Instrument [Line Items]
Extinguishment of debt									$ 600
Basis spread on variable rate (as percent)													0.63%	0.63%	0.63%

DEBT - Schedule of Maturities (

DEBT - Schedule of Maturities (Details) $ in Millions	Dec. 31, 2024 CAD ($)
Debt Disclosure [Abstract]
Total	$ 101,819
Less than 1 year	7,724
2 years	7,379
3 years	4,704
4 years	3,056
5 years	13,578
Thereafter	$ 65,378

DEBT - Schedule of Interest Exp

DEBT - Schedule of Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
DEBT
Capitalized interest	$ (161)	$ (101)	$ (74)
Total interest expense	4,419	3,812	3,179
Spectra Energy Capital, LLC
DEBT
Amortization of fair value adjustment	18	(45)	(45)
Debentures and term notes
DEBT
Interest expense on debt	4,123	3,439	2,910
Commercial paper and credit facility draws
DEBT
Interest expense on debt	$ 439	$ 519	$ 388

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Reconciliation of movements in the Company's ARO
Obligations at beginning of year	$ 493	$ 488
Liabilities acquired	185	1
Liabilities incurred	3	0
Liabilities settled	(139)	(23)
Change in estimate and other	51	5
Foreign currency translation adjustment	40	(6)
Accretion expense	33	28
Obligations at end of year	666	493
Other current liabilities	120	136
Other long-term liabilities	546	357
Asset retirement obligations	$ 666	$ 493
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, 2024	Dec. 31, 2023
NONCONTROLLING INTERESTS
Noncontrolling interests	$ 2,993	$ 3,029
Algonquin Gas Transmission, LLC
NONCONTROLLING INTERESTS
Noncontrolling interests	414	384
Enbridge Athabasca Midstream Investor Limited Partnership
NONCONTROLLING INTERESTS
Noncontrolling interests	1,073	1,086
Maritimes & Northeast Pipeline, L.L.C.
NONCONTROLLING INTERESTS
Noncontrolling interests	606	559
Renewable energy assets
NONCONTROLLING INTERESTS
Noncontrolling interests	786	885
Maritimes & Northeast Pipeline Limited Partnership
NONCONTROLLING INTERESTS
Noncontrolling interests	109	111
Other
NONCONTROLLING INTERESTS
Noncontrolling interests	$ 5	$ 4

SHARE CAPITAL - Schedule of Com

SHARE CAPITAL - Schedule of Common Shares (Details) $ / shares in Units, $ in Millions			3 Months Ended	12 Months Ended
	May 15, 2024 CAD ($)	Sep. 08, 2023 CAD ($) $ / shares shares	Jul. 31, 2024 CAD ($) $ / shares shares	Dec. 31, 2024 CAD ($) shares	Dec. 31, 2023 CAD ($) shares	Dec. 31, 2022 CAD ($) shares	Jul. 31, 2024 $ / shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance at beginning of period (in shares) | shares				2,125,000,000
Shares issued, net of issue costs (in shares) | shares				51,000,000	103,000,000	0
Shares issued, net of issue costs				$ 2,489	$ 4,485	$ 0
Shares issued on vesting of RSU, net of tax (in shares) | shares				1,000,000	0	0
Shares issued on vesting of RSUs, net of tax				$ 30	$ 12	$ 0
Balance at end of period (in shares) | shares				2,178,000,000	2,125,000,000
At-The-Market Offering
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common shares that can be sold under the ATM Program	$ 2,750
Sale of stock, consideration received on transaction			$ 2,500
Sale of stock, consideration received on transaction, net			2,480
Payments of stock issuance costs			$ 16.3
Public Offering Member
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Sale of stock, consideration received on transaction		$ 4,600
Sale of stock, number of shares issued in transaction (shares) | shares		102,913,500
Sale of stock, price per share (in Canadian dollars per share and US dollars per share) | $ / shares		$ 44.70
Common Shares
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Balance at beginning of period (in shares) | shares				2,125,000,000	2,025,000,000	2,026,000,000
Balance at beginning of period, amount				$ 69,180	$ 64,760	$ 64,799
Shares issued on exercise of stock options (in shares) | shares				1,000,000	0	2,000,000
Shares issued on exercise of stock options				$ 39	$ 3	$ 53
Share repurchases at stated value (in shares) | shares				0	(3,000,000)	(3,000,000)
Share repurchases at stated value				$ 0	$ (80)	$ (88)
Other ( in shares) | shares				0	0	0
Other				$ 0	$ 0	$ (4)
Balance at end of period (in shares) | shares				2,178,000,000	2,125,000,000	2,025,000,000
Balance at end of period, amount				$ 71,738	$ 69,180	$ 64,760
Common Shares | At-The-Market Offering
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Sale of stock, number of shares issued in transaction (shares) | shares			51,298,629
Sale of stock, price per share (in Canadian dollars per share and US dollars per share) | (per share)			$ 48.72				$ 35.77

SHARE CAPITAL - Schedule of Pre

SHARE CAPITAL - Schedule of Preference Shares and Characteristics of Preference Shares (Details) $ / shares in Units, $ in Millions				3 Months Ended							12 Months Ended
	Sep. 01, 2024 shares	Sep. 01, 2023 shares	Jun. 01, 2023 shares	Dec. 31, 2024 CAD ($) $ / shares shares	Sep. 30, 2024 $ / shares	Jun. 30, 2024 $ / shares	Mar. 31, 2024 $ / shares	Mar. 31, 2024 $ / shares	Dec. 31, 2023 CAD ($) $ / shares shares	Dec. 31, 2023 CAD ($) $ / shares shares	Dec. 31, 2024 CAD ($) $ / shares shares	Dec. 31, 2024 CAD ($) $ / shares $ / shares shares	Dec. 31, 2023 CAD ($) shares	Dec. 31, 2022 CAD ($) shares	Dec. 31, 2024 $ / shares
Preferred Shares
Share Capital
Preferred stock, value, outstanding | $				$ 6,818					$ 6,818	$ 6,818	$ 6,818	$ 6,818	$ 6,818	$ 6,818
Issuance costs | $											$ (135)		$ (135)	$ (135)
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference shares conversion ratio				1							1	1
Preference Shares, Series A
Share Capital
Dividend (in Canadian dollars per share)											$ 1.37500
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	5,000,000	5,000,000	5,000,000
Preferred stock, value, outstanding | $				$ 125					$ 125	$ 125	$ 125	$ 125	$ 125	$ 125
Dividend rate (percent)											5.50%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Dividend rate reset period (in years)											5 years
Preference Shares, Series B
Share Capital
Dividend (in Canadian dollars per share)											$ 1.30052
Preference Shares, Series B | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares				20,000,000					20,000,000	20,000,000	20,000,000	20,000,000	20,000,000	20,000,000
Preferred stock, value, outstanding | $				$ 500					$ 500	$ 500	$ 500	$ 500	$ 500	$ 500
Dividend rate (percent)											5.20%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
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%	2.40%
Preference Shares, Series D
Share Capital
Dividend (in Canadian dollars per share)											$ 1.35300
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	18,000,000	18,000,000	18,000,000
Preferred stock, value, outstanding | $				$ 450					$ 450	$ 450	$ 450	$ 450	$ 450	$ 450
Dividend rate (percent)											5.41%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series F
Share Capital
Dividend (in Canadian dollars per share)											$ 1.38452
Preference Shares, Series F | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares				18,000,000					18,000,000	18,000,000	18,000,000	18,000,000	18,000,000	20,000,000
Preferred stock, value, outstanding | $				$ 454					$ 454	$ 454	$ 454	$ 454	$ 454	$ 500
Dividend rate (percent)											5.54%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Conversion of stock, shares converted (shares) | shares			1,827,695
Preference Shares, Series G
Share Capital
Dividend (in Canadian dollars per share)				$ 0.37911	$ 0.43014						$ 1.51644
Preference Shares, Series G | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares				2,000,000					2,000,000	2,000,000	2,000,000	2,000,000	2,000,000	0
Preferred stock, value, outstanding | $				$ 46					$ 46	$ 46	$ 46	$ 46	$ 46	$ 0
Dividend rate (percent)											6.15%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Conversion of stock, shares issued (shares) | 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%	2.50%
Preference Shares, Series H
Share Capital
Dividend (in Canadian dollars per share)											$ 1.52800
Preference Shares, Series H | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares				12,000,000					12,000,000	12,000,000	12,000,000	12,000,000	12,000,000	14,000,000
Preferred stock, value, outstanding | $				$ 291					$ 291	$ 291	$ 291	$ 291	$ 291	$ 350
Dividend rate (percent)											6.11%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Conversion of stock, shares converted (shares) | shares		2,350,602
Preference Shares, Series I
Share Capital
Dividend (in Canadian dollars per share)				$ 0.35507	0.40589						$ 1.42028
Preference Shares, Series I | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares				2,000,000					2,000,000	2,000,000	2,000,000	2,000,000	2,000,000	0
Preferred stock, value, outstanding | $				$ 59					$ 59	$ 59	$ 59	$ 59	$ 59	$ 0
Dividend rate (percent)											5.76%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Conversion of stock, shares issued (shares) | shares		2,350,602
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%	2.10%
Preference Shares, Series L
Share Capital
Dividend (in Canadian dollars per share)												$ 1.46448
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	16,000,000	16,000,000	16,000,000
Preferred stock, value, outstanding | $				$ 411					$ 411	$ 411	$ 411	$ 411	$ 411	$ 411
Dividend rate (percent)											5.86%
Per share base redemption value (in Canadian dollars per shares)															$ 25
Preference Shares, Series N
Share Capital
Dividend (in Canadian dollars per share)											$ 1.67400
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	18,000,000	18,000,000	18,000,000
Preferred stock, value, outstanding | $				$ 450					$ 450	$ 450	$ 450	$ 450	$ 450	$ 450
Dividend rate (percent)											6.70%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series P
Share Capital
Dividend (in Canadian dollars per share)							$ 0.36988		$ 0.27369		$ 1.47952
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	16,000,000	16,000,000	16,000,000
Preferred stock, value, outstanding | $				$ 400					$ 400	$ 400	$ 400	$ 400	$ 400	$ 400
Dividend rate (percent)											5.92%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series R
Share Capital
Dividend (in Canadian dollars per share)						$ 0.39463	0.25456				$ 1.57852
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	16,000,000	16,000,000	16,000,000
Preferred stock, value, outstanding | $				$ 400					$ 400	$ 400	$ 400	$ 400	$ 400	$ 400
Dividend rate (percent)											6.31%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series 1
Share Capital
Dividend (in Canadian dollars per share)												$ 1.67592
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	16,000,000	16,000,000	16,000,000
Preferred stock, value, outstanding | $				$ 411					$ 411	$ 411	$ 411	$ 411	$ 411	$ 411
Dividend rate (percent)											6.70%
Per share base redemption value (in Canadian dollars per shares)															25
Preference Shares, Series 3
Share Capital
Dividend (in Canadian dollars per share)					0.33050	$ 0.23356					$ 1.32200
Conversion of stock, shares converted (shares) | shares	1,502,775
Preference Shares, Series 3 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares				22,000,000					24,000,000	24,000,000	22,000,000	22,000,000	24,000,000	24,000,000
Preferred stock, value, outstanding | $				$ 562					$ 600	$ 600	$ 562	$ 562	$ 600	$ 600
Dividend rate (percent)											5.29%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series 4
Share Capital
Dividend (in Canadian dollars per share)				$ 0.37110	0.42206						$ 1.48440
Conversion of stock, shares issued (shares) | shares	1,502,775
Preference Shares, Series 4 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares				2,000,000					0	0	2,000,000	2,000,000	0	0
Preferred stock, value, outstanding | $				$ 38					$ 0	$ 0	$ 38	$ 38	$ 0	$ 0
Dividend rate (percent)											6.02%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series 5
Share Capital
Dividend (in Canadian dollars per share)								$ 0.41769		$ 0.33596		$ 1.67076
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	8,000,000	8,000,000	8,000,000
Preferred stock, value, outstanding | $				$ 206					$ 206	$ 206	$ 206	$ 206	$ 206	$ 206
Dividend rate (percent)											6.68%
Per share base redemption value (in Canadian dollars per shares)															$ 25
Preference Shares, Series 7
Share Capital
Dividend (in Canadian dollars per share)							$ 0.37425		$ 0.27806		$ 1.49700
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	10,000,000	10,000,000	10,000,000
Preferred stock, value, outstanding | $				$ 250					$ 250	$ 250	$ 250	$ 250	$ 250	$ 250
Dividend rate (percent)											5.99%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series 9
Share Capital
Dividend (in Canadian dollars per share)				$ 0.35450	$ 0.25606						$ 1.41800
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	11,000,000	11,000,000	11,000,000
Preferred stock, value, outstanding | $				$ 275					$ 275	$ 275	$ 275	$ 275	$ 275	$ 275
Dividend rate (percent)											5.67%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series 11
Share Capital
Dividend (in Canadian dollars per share)											$ 0.98452
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	20,000,000	20,000,000	20,000,000
Preferred stock, value, outstanding | $				$ 500					$ 500	$ 500	$ 500	$ 500	$ 500	$ 500
Dividend rate (percent)											3.94%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series 13
Share Capital
Dividend (in Canadian dollars per share)											$ 0.76076
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	14,000,000	14,000,000	14,000,000
Preferred stock, value, outstanding | $				$ 350					$ 350	$ 350	$ 350	$ 350	$ 350	$ 350
Dividend rate (percent)											3.04%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series 15
Share Capital
Dividend (in Canadian dollars per share)											$ 0.74576
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	11,000,000	11,000,000	11,000,000
Preferred stock, value, outstanding | $				$ 275					$ 275	$ 275	$ 275	$ 275	$ 275	$ 275
Dividend rate (percent)											2.98%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Preference Shares, Series 19
Share Capital
Dividend (in Canadian dollars per share)											$ 1.55300
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	20,000,000	20,000,000	20,000,000
Preferred stock, value, outstanding | $				$ 500					$ 500	$ 500	$ 500	$ 500	$ 500	$ 500
Dividend rate (percent)											6.21%
Per share base redemption value (in Canadian dollars per shares)				$ 25							$ 25	$ 25
Dividend rate reset period (in years)											5 years
Preference Shares, Series 19 | Preferred Shares | Minimum
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%	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%	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%	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%	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%	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%	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%	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%	2.60%
Preference Shares, Series 14 | Preferred Shares | 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)				2.70%							2.70%	2.70%
Preference Shares, Series 16 | Preferred Shares | 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)				2.70%							2.70%	2.70%
Preference Shares, Series 20 | Preferred Shares | 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)				3.20%							3.20%	3.20%
Preference Shares, Series M | 3-Month Government Of Canada Treasury Bill
Share Capital
Dividend rate -spread on variable rate (percent)				3.20%							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%	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%	2.80%

SHARE CAPITAL - Shareholder Rig

SHARE CAPITAL - Shareholder Rights Plan (Details)	Dec. 31, 2024
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, 2024 CAD ($) compensationPlan shares	Dec. 31, 2023 CAD ($) shares	Dec. 31, 2022 CAD ($) shares
STOCK-BASED COMPENSATION
Number of long-term incentive compensation plans | compensationPlan	3
Compensation expense	$ 186	$ 154	$ 260
Common stock, shares authorized | shares	181	181	181
Incentive Stock Options
STOCK-BASED COMPENSATION
Compensation expense	$ 19	$ 18	$ 15
Vesting period (in years)	4 years
Expiration term (in years)	10 years
Unrecognized compensation cost related to non-vested share-based compensation arrangements granted	$ 12
Weighted average period over which compensation cost is expected to be recognized (in years)	2 years
Performance Stock Units (PSUs)
STOCK-BASED COMPENSATION
Compensation expense	$ 75	$ 59	$ 169
Vesting period (in years)	3 years
Weighted average period over which compensation cost is expected to be recognized (in years)	2 years
Period prior to the maturity of the grant for which weighted average share price is used to calculate cash awards (in days)	20 days
Performance multiplier	1.38	1.1	1
Unrecognized compensation expense related to non-vested units granted	$ 109
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	$ 92	$ 77	$ 76
Vesting period (in years)	3 years
Weighted average period over which compensation cost is expected to be recognized (in years)	1 year
Period prior to the maturity of the grant for which weighted average share price is used to calculate cash awards (in days)	20 days
Unrecognized compensation expense related to non-vested units granted	$ 67

STOCK OPTION AND STOCK UNIT P_4

STOCK OPTION AND STOCK UNIT PLANS - Schedule of Outstanding Stock Options (Details) - Incentive Stock Options - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Number
Options outstanding at beginning of year (in shares)	28,729
Options granted (in shares)	5,036
Options exercised (in shares)	(7,328)
Options cancelled or expired (in shares)	(1,113)
Options outstanding at end of year (in shares)	25,324	28,729
Options vested at end of year (in shares)	15,602
Weighted Average Exercise Price
Options outstanding at beginning of year (in Canadian dollars per share)	$ 50.79
Options granted (in Canadian dollars per share)	46.36
Options exercised (in Canadian dollars per share)	49.27
Options cancelled or expired (in Canadian dollars per share)	51.78
Options outstanding at end of year (in Canadian dollars per share)	50.31	$ 50.79
Options vested at end of year (in Canadian dollars per share)	$ 51.33
Weighted Average Remaining Contractual Life (years)
Options outstanding at end of year	5 years 8 months 12 days
Options vested at end of year	4 years 2 months 12 days
Aggregate Intrinsic Value
Options outstanding at end of year	$ 70
Options vested at end of year	37
Stock options, additional disclosures
Total intrinsic value of awards exercised	18	$ 2	$ 66
Cash received on exercise of awards	1	0	3
Total fair value of options vested	$ 17	$ 20	$ 21

STOCK OPTION AND STOCK UNIT P_5

STOCK OPTION AND STOCK UNIT PLANS - Schedule of Weighted Average Assumptions Used to Determine the Fair Value of Stock Options Granted (Details) - Incentive Stock Options	12 Months Ended
	Dec. 31, 2024 $ / shares	Dec. 31, 2023 $ / shares	Dec. 31, 2022 $ / shares	Dec. 31, 2024 $ / shares	Dec. 31, 2023 $ / shares	Dec. 31, 2022 $ / shares
Weighted average assumptions used to determine the fair value of options
Fair value per option (in Canadian dollars per share)	$ 4.07	$ 6.05	$ 5.07
Expected option term (in years)	6 years	6 years	6 years
Expected volatility (as a percent)	21.10%	22.20%	21.90%
Expected dividend yield (as a percent)	8.10%	6.70%	6.50%
Risk-free interest rate (as a percent)	3.80%	3.50%	1.80%
Expected option term - historical exercise practice (in years)	6 years
Canadian Employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in Canadian dollars per share)	$ 3.53	$ 5.38	$ 4.78
United States Employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in Canadian dollars per share)				$ 3.58	$ 5.23	$ 4.62
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, 2024	Dec. 31, 2023	Dec. 31, 2022
Number
Dividend reinvestment (in shares)	237
Performance Stock Units (PSUs)
Number
Units outstanding at beginning of year (in shares)	3,180
Units granted (in shares)	1,444
Units cancelled (in shares)	(104)
Units matured (in shares)	(1,355)
Units outstanding at end of year (in shares)	3,402	3,180
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	1 year 7 months 6 days
Aggregate Intrinsic Value
Units outstanding at end of year	$ 244
Stock units, additional disclosures
Total amount paid	$ 65	$ 123	$ 90
Restricted Stock Units (RSU)
Number
Units outstanding at beginning of year (in shares)	3,571
Units granted (in shares)	1,758
Units cancelled (in shares)	(112)
Units matured (in shares)	(1,910)
Dividend reinvestment (in shares)	284
Units outstanding at end of year (in shares)	3,591	3,571
Weighted Average Grant Date Fair Value
Units outstanding at beginning of year	$ 50.69
Units granted	48.50
Units cancelled	51.38
Units matured	49.99
Dividend reinvestment	50.94
Units outstanding at end of year	$ 51.10	$ 50.69
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	1 year
Aggregate Intrinsic Value
Units outstanding at end of year	$ 187
Stock units, additional disclosures
Total amount paid	$ 40	$ 56	$ 32

COMPONENTS OF ACCUMULATED OTH_3

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Changes in AOCI
Balance at beginning of year	$ 64,483	$ 63,398
Other comprehensive income/(loss) retained in AOCI	4,845	(1,144)	$ 4,816
Other			16
Other comprehensive (income)/loss reclassified to earnings	4,907	(1,187)	5,004
Income tax on amounts retained in AOCI	(81)	(33)	(349)
Income tax on amounts reclassified to earnings	(14)	3	(39)
Tax impact	(95)	(30)	(388)
Balance at end of year	68,893	64,483	63,398
Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	31	28	186
Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(1)
Foreign exchange contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	53	(47)	(4)
Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings			4
Total
Changes in AOCI
Balance at beginning of year	2,303	3,520	(1,096)
Balance at end of year	7,115	2,303	3,520
Cash Flow Hedges
Changes in AOCI
Balance at beginning of year	320	121	(897)
Other comprehensive income/(loss) retained in AOCI	79	232	1,125
Other			0
Other comprehensive (income)/loss reclassified to earnings	109	260	1,311
Income tax on amounts retained in AOCI	(15)	(47)	(250)
Income tax on amounts reclassified to earnings	(7)	(14)	(43)
Tax impact	(22)	(61)	(293)
Balance at end of year	407	320	121
Cash Flow Hedges | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	31	28	186
Cash Flow Hedges | Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(1)
Cash Flow Hedges | Foreign exchange contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	0	0	(4)
Cash Flow Hedges | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings			4
Excluded Components of Fair Value Hedges
Changes in AOCI
Balance at beginning of year	(23)	(35)	0
Other comprehensive income/(loss) retained in AOCI	(42)	62	(35)
Other comprehensive (income)/loss reclassified to earnings	11	15	(35)
Income tax on amounts retained in AOCI	10	(14)
Income tax on amounts reclassified to earnings	(12)	11
Tax impact	(2)	(3)	0
Balance at end of year	(14)	(23)	(35)
Excluded Components of Fair Value Hedges | Foreign exchange contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	53	(47)
Net Investment Hedges
Changes in AOCI
Balance at beginning of year	(728)	(1,137)	(166)
Other comprehensive income/(loss) retained in AOCI	(1,305)	409	(971)
Other comprehensive (income)/loss reclassified to earnings	(1,305)	409	(971)
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	(2,033)	(728)	(1,137)
Cumulative Translation Adjustment
Changes in AOCI
Balance at beginning of year	2,653	4,348	56
Other comprehensive income/(loss) retained in AOCI	5,799	(1,695)	4,292
Other			0
Other comprehensive (income)/loss reclassified to earnings	5,799	(1,695)	4,292
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	8,452	2,653	4,348
Equity Investees
Changes in AOCI
Balance at beginning of year	11	5	(5)
Other comprehensive income/(loss) retained in AOCI	(9)	6	(6)
Other			16
Other comprehensive (income)/loss reclassified to earnings	(9)	6	10
Income tax on amounts retained in AOCI	(1)
Income tax on amounts reclassified to earnings	0		0
Tax impact	(1)	0	0
Balance at end of year	1	11	5
Pension and OPEB Adjustment
Changes in AOCI
Balance at beginning of year	70	218	(84)
Other comprehensive income/(loss) retained in AOCI	323	(158)	411
Other comprehensive (income)/loss reclassified to earnings	(21)	(24)	(14)
Other comprehensive (income)/loss reclassified to earnings	302	(182)	397
Income tax on amounts retained in AOCI	(75)	28	(99)
Income tax on amounts reclassified to earnings	5	6	4
Tax impact	(70)	34	(95)
Balance at end of year	$ 302	$ 70	$ 218

RISK MANAGEMENT AND FINANCIAL_3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Market Risk (Details)	Dec. 31, 2024
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Policy limit increase (as percent)	30%
Derivative, average fixed interest rate (as percent)	3.60%
Floating-To-Fixed Interest Rate Swaps
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Derivative, average fixed interest rate (as percent)	3.40%

RISK MANAGEMENT AND FINANCIAL_4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Total Derivative Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	$ (2,250)	$ (404)
Total net derivative instruments	(2,250)	(404)
Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2,251)	(278)
Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(4)	(122)
Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	5	(4)
Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2,175)	(152)
Total net derivative instruments	(2,175)	(152)
Foreign exchange contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2,180)	(148)
Foreign exchange contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative 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 derivative asset/(liability)	5	$ (4)
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	53	(156)
Total net derivative instruments	53	$ (156)
Derivative liability, statement of financial position [Extensible Enumeration]		Other long-term liabilities
Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	58	$ (52)
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
Total net derivative asset/(liability)	(5)	$ (104)
Interest rate contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	$ 0
Derivative liability, statement of financial position [Extensible Enumeration]		Other long-term liabilities
Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(131)	$ (96)
Total net derivative instruments	(131)	(96)
Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(132)	(78)
Commodity contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	1	(18)
Commodity contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Other contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	3	1
Derivative liabilities, total gross derivative instruments as presented		(1)
Total net derivative asset/(liability)	3	0
Derivative assets, amounts available for offset	0	(1)
Derivative liabilities, amounts available for offset		1
Derivative assets, total net derivative instruments	3	0
Derivative liabilities, total net derivative instruments		0
Total net derivative instruments	3	0
Other contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	3	1
Derivative liabilities, total gross derivative instruments as presented		(1)
Total net derivative asset/(liability)	3	0
Other contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Derivative liabilities, total gross derivative instruments as presented		0
Total net derivative asset/(liability)	0	0
Other contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Derivative liabilities, total gross derivative instruments as presented		0
Total net derivative asset/(liability)	0	0
Other current assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	557	623
Derivative assets, amounts available for offset	(259)	(335)
Derivative assets, total net derivative instruments	$ 298	$ 288
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	$ 433	$ 551
Other current assets | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	46	31
Other current assets | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	78	41
Other current assets | Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	125	139
Derivative assets, amounts available for offset	(29)	(32)
Derivative assets, total net derivative instruments	96	107
Other current assets | Foreign exchange contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	47	98
Other current assets | Foreign exchange contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Other current assets | Foreign exchange contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	78	41
Other current assets | Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	67	65
Derivative assets, amounts available for offset	(39)	(32)
Derivative assets, total net derivative instruments	28	33
Other current assets | Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	23	34
Other current assets | Interest rate contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	44	31
Other current assets | Interest rate contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Other current assets | Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	362	418
Derivative assets, amounts available for offset	(191)	(270)
Derivative assets, total net derivative instruments	171	148
Other current assets | Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	360	418
Other current assets | Commodity contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	2	0
Other current assets | Commodity contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	426	463
Derivative assets, amounts available for offset	(137)	(184)
Derivative assets, total net derivative instruments	$ 289	$ 279
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	$ 417	$ 396
Deferred amounts and other assets | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	9	51
Deferred amounts and other assets | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	16
Deferred amounts and other assets | Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	83	335
Derivative assets, amounts available for offset	(71)	(122)
Derivative assets, total net derivative instruments	12	213
Deferred amounts and other assets | Foreign exchange contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	83	319
Deferred amounts and other assets | Foreign exchange contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Deferred amounts and other assets | Foreign exchange contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	16
Deferred amounts and other assets | Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	146	53
Derivative assets, amounts available for offset	(27)	(21)
Derivative assets, total net derivative instruments	119	32
Deferred amounts and other assets | Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	137	2
Deferred amounts and other assets | Interest rate contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	9	51
Deferred amounts and other assets | Interest rate contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Deferred amounts and other assets | Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	197	75
Derivative assets, amounts available for offset	(39)	(41)
Derivative assets, total net derivative instruments	158	34
Deferred amounts and other assets | Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	197	75
Deferred amounts and other assets | Commodity contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Deferred amounts and other assets | Commodity contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, total gross derivative instruments as presented	0	0
Other current liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(1,335)	(738)
Derivative liabilities, amounts available for offset	259	335
Derivative liabilities, total net derivative instruments	$ (1,076)	$ (403)
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	$ (1,204)	$ (500)
Other current liabilities | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(58)	(194)
Other current liabilities | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(73)	(44)
Other current liabilities | Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(804)	(128)
Derivative liabilities, amounts available for offset	29	32
Derivative liabilities, total net derivative instruments	(775)	(96)
Other current liabilities | Foreign exchange contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(731)	(84)
Other current liabilities | Foreign exchange contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	0	0
Other current liabilities | Foreign exchange contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(73)	(44)
Other current liabilities | Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(80)	(186)
Derivative liabilities, amounts available for offset	39	32
Derivative liabilities, total net derivative instruments	(41)	(154)
Other current liabilities | Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(22)	(3)
Other current liabilities | Interest rate contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(58)	(183)
Other current liabilities | Interest rate contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	0	0
Other current liabilities | Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(451)	(423)
Derivative liabilities, amounts available for offset	191	270
Derivative liabilities, total net derivative instruments	(260)	(153)
Other current liabilities | Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(451)	(412)
Other current liabilities | Commodity contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	0	(11)
Other current liabilities | Commodity contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	0	0
Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(1,898)	(752)
Derivative liabilities, amounts available for offset	137	184
Derivative liabilities, total net derivative instruments	$ (1,761)	$ (568)
Derivative liability, statement of financial position [Extensible Enumeration]	Other long-term liabilities	Other long-term liabilities
Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	$ (1,897)	$ (725)
Other long-term liabilities | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(1)	(10)
Other long-term liabilities | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	0	(17)
Other long-term liabilities | Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(1,579)	(498)
Derivative liabilities, amounts available for offset	71	122
Derivative liabilities, total net derivative instruments	(1,508)	(376)
Other long-term liabilities | Foreign exchange contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(1,579)	(481)
Other long-term liabilities | Foreign exchange contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	0	0
Other long-term liabilities | Foreign exchange contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	0	(17)
Other long-term liabilities | Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(80)	(88)
Derivative liabilities, amounts available for offset	27	21
Derivative liabilities, total net derivative instruments	(53)	(67)
Other long-term liabilities | Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(80)	(85)
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	0	(3)
Other long-term liabilities | Interest rate contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	0	0
Other long-term liabilities | Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(239)	(166)
Derivative liabilities, amounts available for offset	39	41
Derivative liabilities, total net derivative instruments	(200)	(125)
Other long-term liabilities | Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(238)	(159)
Other long-term liabilities | Commodity contracts | Cash flow hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	(1)	(7)
Other long-term liabilities | Commodity contracts | Fair value hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, total gross derivative instruments as presented	$ 0	$ 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, 2024 USD ($) MWh Bcf MMBbls	Dec. 31, 2024 GBP (£) MWh Bcf MMBbls	Dec. 31, 2024 EUR (€) MWh Bcf MMBbls	Dec. 31, 2024 JPY (¥) MWh Bcf MMBbls	Dec. 31, 2024 CAD ($) MWh Bcf MMBbls	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
Foreign exchange contracts - United States dollar or GBP or Japanese yen forwards - purchase
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2025	$ 1,245			¥ 84,800
2026	0			0
2027	0			0
2028	0			0
2029	0			0
Thereafter	0			0
Total notional principal	1,245			¥ 84,800		$ 1,860			¥ 84,800
Foreign exchange contracts - United States dollar or GBP forwards - sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2025	6,406	£ 30	€ 126
2026	5,627	28	121
2027	4,811	32	81
2028	3,522	0	67
2029	1,248	0	66
Thereafter	0	0	129
Total notional principal	$ 21,614	£ 90	€ 590			$ 24,747	£ 120	€ 731
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2025					$ 2,296
2026					1,737
2027					676
2028					49
2029					13
Thereafter					0
Total notional principal					4,771					$ 9,018
Interest rate contract for short term debt receive fixed rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2025					0
2026					0
2027					0
2028					0
2029					0
Thereafter					0
Total notional principal					0					2,015
Interest rate contract - long term debt - Pay Fixed Rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2025					4,531
2026					753
2027					0
2028					0
2029					0
Thereafter					0
Total notional principal					5,284					5,162
Interest rate contract for costless collar
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2025					1,938
2026					268
2027					104
2028					6
2029					0
Thereafter					0
Total notional principal					2,316					1,139
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2025					0
2026					0
2027					0
2028					0
2029					0
Thereafter					0
Total notional principal					$ 0					$ 47
Commodity contracts | Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2025 notional quantity (bcf / mmbbls) | Bcf	154	154	154	154	154
2026 notional quantity (bcf / mmbbls) | Bcf	79	79	79	79	79
2027 notional quantity (bcf / mmbbls) | Bcf	37	37	37	37	37
2028 notional quantity (bcf / mmbbls) | Bcf	11	11	11	11	11
2029 notional quantity (bcf / mmbbls) | Bcf	5	5	5	5	5
Thereafter notional quantity (bcf / mmbbls) | Bcf	2	2	2	2	2
Total notional quantity (bcf / mmbbls) | Bcf	288	288	288	288	288	86	86	86	86	86
Commodity contracts | Crude
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2025 notional quantity (bcf / mmbbls) | MMBbls	6	6	6	6	6
2026 notional quantity (bcf / mmbbls) | MMBbls	15	15	15	15	15
2027 notional quantity (bcf / mmbbls) | MMBbls	1	1	1	1	1
2028 notional quantity (bcf / mmbbls) | MMBbls	1	1	1	1	1
2029 notional quantity (bcf / mmbbls) | MMBbls	1	1	1	1	1
Thereafter notional quantity (bcf / mmbbls) | MMBbls	1	1	1	1	1
Total notional quantity (bcf / mmbbls) | MMBbls	25	25	25	25	25	6	6	6	6	6
Commodity contracts | Power | Net purchase
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2025 notional quantity (MWH) | MWh	61	61	61	61	61
2026 notional quantity (MWH) | MWh	24	24	24	24	24
Commodity contracts | Power | Net sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2027 notional quantity (MWH) | MWh	(31)	(31)	(31)	(31)	(31)
2028 notional quantity (MWH) | MWh	(49)	(49)	(49)	(49)	(49)
2029 notional quantity (MWH) | MWh	(30)	(30)	(30)	(30)	(30)
Thereafter notional quantity (MWH) | MWh	0	0	0	0	0
Total notional quantity (MWH) | MWh	(5)	(5)	(5)	(5)	(5)	(22)	(22)	(22)	(22)	(22)

RISK MANAGEMENT AND FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value Derivatives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Realized gain/(loss) on derivative	$ 23	$ (97)	$ (431)
Interest rate contracts | Fair value hedges
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Unrealized loss on derivative	(3)	(132)
Unrealized gain on hedged item	6	131
Realized gain/(loss) on derivative	26	(47)
Realized loss on hedged item	$ (79)	$ 0

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, 2024	Dec. 31, 2023	Dec. 31, 2022
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	$ 45	$ 282	$ 1,062
Amount of (income)/loss reclassified from AOCI to earnings	$ 83	28	203
Period to hedge exposures to the variability of cash flows for all forecasted transactions (in years)	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	$ 0
Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (income)/loss reclassified from AOCI to earnings	53	0	13
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	0	3
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	(42)	15	(35)
Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (income)/loss reclassified from AOCI to earnings	31	28	186
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	67	201	1,151
Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (income)/loss reclassified from AOCI to earnings	(1)	0	0
Commodity contracts | Cash flow hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	19	68	(53)
Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (income)/loss reclassified from AOCI to earnings	0	0	4
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	$ 1	$ (2)	$ (4)

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value Derivatives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	$ (2,082)	$ 1,180	$ (1,280)
Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(2,082)	1,180	(1,280)
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	(2,033)	1,292	(1,344)
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	0	645	(238)
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	(2,033)	647	(1,106)
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	112	(63)	10
Commodity contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(163)	(41)	50
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	(23)	(35)	13
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	(92)	153	89
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	(31)	(94)	(102)
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	(17)	(65)	50
Other contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	$ 2	$ (8)	$ 4

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Liquidity and Credit Risk (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
LIQUIDITY RISK AND CREDIT RISK
Rolling time period over which the company forecasts cash requirements (in months)	12 months
Period of anticipated requirements for which the company maintains sufficient liquidity through committed credit facilities (in years)	1 year
Derivative Instruments
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 973	$ 1,062
Derivative Instruments | Canadian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	344	457
Derivative Instruments | US financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	128	252
Derivative Instruments | European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	116	107
Derivative Instruments | Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	53	121
Derivative Instruments | Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 332	$ 125

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Derivatives (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Fair Value of Derivatives
Current derivative assets	$ 557	$ 623
Current derivative liabilities	(1,335)	(738)
Total net derivative asset/(liability)	(2,250)	(404)
Fair Value
Fair Value of Derivatives
Current derivative assets	557	623
Long-term derivative assets	426	463
Current derivative liabilities	(1,335)	(738)
Long-term derivative liabilities	(1,898)	(752)
Total net derivative asset/(liability)	(2,250)	(404)
Level 1 | Fair Value
Fair Value of Derivatives
Current derivative assets	34	142
Long-term derivative assets	1	0
Current derivative liabilities	(52)	(136)
Long-term derivative liabilities	(1)	0
Total net derivative asset/(liability)	(18)	6
Level 2 | Fair Value
Fair Value of Derivatives
Current derivative assets	267	308
Long-term derivative assets	243	412
Current derivative liabilities	(1,000)	(391)
Long-term derivative liabilities	(1,690)	(608)
Total net derivative asset/(liability)	(2,180)	(279)
Level 3
Fair Value of Derivatives
Total net derivative asset/(liability)	(52)
Level 3 | Fair Value
Fair Value of Derivatives
Current derivative assets	256	173
Long-term derivative assets	182	51
Current derivative liabilities	(283)	(211)
Long-term derivative liabilities	(207)	(144)
Total net derivative asset/(liability)	(52)	(131)
Foreign exchange contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(2,175)	(152)
Foreign exchange contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	125	139
Long-term derivative assets	83	335
Current derivative liabilities	(804)	(128)
Long-term derivative liabilities	(1,579)	(498)
Total net derivative asset/(liability)	(2,175)	(152)
Foreign exchange contracts | Level 1 | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Foreign exchange contracts | Level 2 | Fair Value
Fair Value of Derivatives
Current derivative assets	125	139
Long-term derivative assets	83	335
Current derivative liabilities	(804)	(128)
Long-term derivative liabilities	(1,579)	(498)
Total net derivative asset/(liability)	(2,175)	(152)
Foreign exchange contracts | Level 3 | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Interest rate contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	53	(156)
Interest rate contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	67	65
Long-term derivative assets	146	53
Current derivative liabilities	(80)	(186)
Long-term derivative liabilities	(80)	(88)
Total net derivative asset/(liability)	53	(156)
Interest rate contracts | Level 1 | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Interest rate contracts | Level 2 | Fair Value
Fair Value of Derivatives
Current derivative assets	67	65
Long-term derivative assets	146	53
Current derivative liabilities	(80)	(186)
Long-term derivative liabilities	(80)	(88)
Total net derivative asset/(liability)	53	(156)
Interest rate contracts | Level 3 | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Commodity contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(131)	(96)
Commodity contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	362	418
Long-term derivative assets	197	75
Current derivative liabilities	(451)	(423)
Long-term derivative liabilities	(239)	(166)
Total net derivative asset/(liability)	(131)	(96)
Commodity contracts | Level 1 | Fair Value
Fair Value of Derivatives
Current derivative assets	34	142
Long-term derivative assets	1	0
Current derivative liabilities	(52)	(136)
Long-term derivative liabilities	(1)	0
Total net derivative asset/(liability)	(18)	6
Commodity contracts | Level 2 | Fair Value
Fair Value of Derivatives
Current derivative assets	72	103
Long-term derivative assets	14	24
Current derivative liabilities	(116)	(76)
Long-term derivative liabilities	(31)	(22)
Total net derivative asset/(liability)	(61)	29
Commodity contracts | Level 3 | Fair Value
Fair Value of Derivatives
Current derivative assets	256	173
Long-term derivative assets	182	51
Current derivative liabilities	(283)	(211)
Long-term derivative liabilities	(207)	(144)
Total net derivative asset/(liability)	(52)	(131)
Other contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	3	0
Other contracts | Fair Value
Fair Value of Derivatives
Current derivative assets	3	1
Long-term derivative assets	0
Current derivative liabilities	0	(1)
Long-term derivative liabilities	0
Total net derivative asset/(liability)	3	0
Other contracts | Level 1 | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0
Total net derivative asset/(liability)	0	0
Other contracts | Level 2 | Fair Value
Fair Value of Derivatives
Current derivative assets	3	1
Long-term derivative assets	0
Current derivative liabilities	0	(1)
Long-term derivative liabilities	0
Total net derivative asset/(liability)	3	0
Other contracts | Level 3 | Fair Value
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0
Total net derivative asset/(liability)	$ 0	$ 0

RISK MANAGEMENT AND FINANCIA_11

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Level 3 Inputs (Details) $ in Millions	Dec. 31, 2024 CAD ($) $ / MWh $ / MillionsofBTU-MMBTU $ / bbl	Dec. 31, 2023 CAD ($)
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (2,250)	$ (404)
Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(2,250)	(404)
Level 3
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(52)
Level 3 | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (52)	$ (131)
Commodity Options | Level 3 | Market approach valuation technique | Minimum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent)	0.03
Commodity Options | Level 3 | Market approach valuation technique | Maximum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent)	0.77
Commodity Options | Level 3 | Market approach valuation technique | Weighted Average Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent)	0.50
Natural gas | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Minimum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MillionsofBTU-MMBTU	3.73
Natural gas | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Maximum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MillionsofBTU-MMBTU	9.85
Natural gas | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Weighted Average Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MillionsofBTU-MMBTU	4.12
Natural gas | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (5)
Natural gas | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Minimum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MillionsofBTU-MMBTU	1.40
Natural gas | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Maximum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MillionsofBTU-MMBTU	22.57
Natural gas | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Weighted Average Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MillionsofBTU-MMBTU	4.12
Natural gas | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (80)
Natural gas | Commodity Options | Level 3 | Market approach valuation technique | Minimum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MillionsofBTU-MMBTU	2.44
Natural gas | Commodity Options | Level 3 | Market approach valuation technique | Maximum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MillionsofBTU-MMBTU	7.09
Natural gas | Commodity Options | Level 3 | Market approach valuation technique | Weighted Average Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MillionsofBTU-MMBTU	4.44
Natural gas | Commodity Options | Level 3 | Market approach valuation technique | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ 166
Crude | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Minimum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / bbl	73.54
Crude | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Maximum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / bbl	104.42
Crude | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Weighted Average Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / bbl	97.44
Crude | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (13)
Crude | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Minimum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / bbl	77.31
Crude | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Maximum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / bbl	118.28
Crude | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Weighted Average Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / bbl	99.76
Crude | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ 22
Power | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Minimum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MWh	31.17
Power | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Maximum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MWh	229.29
Power | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Weighted Average Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MWh	68.51
Power | Commodity Contracts - Financial | Level 3 | Market approach valuation technique | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (44)
Power | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Minimum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MWh	12.94
Power | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Maximum Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MWh	211.42
Power | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Weighted Average Price/Volatility
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Price volatility (in $/MMBTU, $/barrel, $ / MW/H, percent) | $ / MWh	70.30
Power | Commodity Contracts - Physical | Level 3 | Market approach valuation technique | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (98)

RISK MANAGEMENT AND FINANCIA_12

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Changes in Level 3 (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Changes in net fair value of derivative assets and liabilities classified as Level 3
Level 3 net derivative liability at beginning of year	$ (131)	$ (136)
Total gain/(loss), unrealized
Included in earnings	(92)	(48)
Included in OCI	19	67
Included in regulatory assets/liabilities	130	0
Settlements	22	(14)
Level 3 net derivative liability at end of year	$ (52)	$ (131)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Earnings
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, 2024	Dec. 31, 2023
Fair Value of Other Financial Instruments
Equity investments at carrying value	$ 187	$ 173
Long-term debt	98,900	78,100
Equity Funds And Debt Securities
Fair Value of Other Financial Instruments
Unrealized gain (loss) on investments	(16)	34
Level 1 | Equity funds
Fair Value of Other Financial Instruments
Fair value of investments	114	287
Level 2
Fair Value of Other Financial Instruments
Investment owned restricted cost	1,100	279
Level 2 | Debt Securities
Fair Value of Other Financial Instruments
Fair value of investments	1,100	284
Carrying value
Fair Value of Other Financial Instruments
Long-term debt	101,600	81,200
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
Net investment hedges
Fair Value of Other Financial Instruments
Unrealized foreign exchange gain (loss) on translation of United States dollar denominated debt	(1,185)	645
Realized loss associated with the settlement of foreign exchange forward contracts	$ 120	$ 236

RISK MANAGEMENT AND FINANCIA_14

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Restricted Long-Term Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Long-Lived Assets Held-for-sale [Line Items]
Debt securities, available-for-sale, amortized cost	$ 540	$ 486
Unrealized holding gains (losses)	$ 33	$ 51
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	$ 826	$ 745
Total long - term regulatory liabilities	6,112	3,521
Pipeline future abandonment costs
Long-Lived Assets Held-for-sale [Line Items]
Total long - term regulatory liabilities	826	745
Level 1
Long-Lived Assets Held-for-sale [Line Items]
Restricted long-term investments and cash (Note 23)	491	263
Level 2
Long-Lived Assets Held-for-sale [Line Items]
Restricted long-term investments and cash (Note 23)	507	454
Fair Value
Long-Lived Assets Held-for-sale [Line Items]
Restricted long-term investments and cash (Note 23)	$ 998	$ 717

INCOME TAXES - Schedule of Inco

INCOME TAXES - Schedule of Income Tax Rate Reconciliation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
INCOME TAX RATE RECONCILIATION
Earnings before income taxes	$ 7,299	$ 7,879	$ 4,542
Canadian federal statutory income tax rate	15%	15%	15%
Expected federal taxes at statutory rate	$ 1,095	$ 1,182	$ 681
Increase/(decrease) resulting from:
Provincial and state income taxes	183	411	108
Foreign and other statutory rate differentials	340	187	295
Effects of rate-regulated accounting	(192)	(106)	(122)
Write-off of regulatory deferrals	4	115	0
Part VI.1 tax, net of federal Part I deduction	73	66	76
US minimum tax	148	100	107
Non-taxable portion of gain on sale of investment	(147)	0	0
Valuation allowance	(2)	(12)	6
Accounting impairment of non-deductible goodwill	148	0	370
Noncontrolling interests	(30)	19	9
Investment and production tax credits	(23)	(47)	0
Other	71	(94)	74
Income tax expense	$ 1,668	$ 1,821	$ 1,604
Effective income tax rate (as a percent)	22.90%	23.10%	35.30%

INCOME TAXES - Schedule of Comp

INCOME TAXES - Schedule of Components of Pretax Earnings and Income Taxes (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Earnings before income taxes
Earnings before income taxes	$ 7,299	$ 7,879	$ 4,542
Current income taxes
Total current income taxes	949	401	647
Deferred income taxes
Total deferred income taxes	719	1,420	957
Income tax expense	1,668	1,821	1,604
Canada
Earnings before income taxes
Domestic	1,035	2,233	583
Current income taxes
Domestic	248	100	360
Deferred income taxes
Domestic	(299)	456	(358)
US
Earnings before income taxes
Foreign	5,231	4,620	2,865
Current income taxes
Foreign	578	191	201
Deferred income taxes
Foreign	1,013	974	1,309
Other
Earnings before income taxes
Foreign	1,033	1,026	1,094
Current income taxes
Foreign	123	110	86
Deferred income taxes
Foreign	$ 5	$ (10)	$ 6

INCOME TAXES - Schedule of Majo

INCOME TAXES - Schedule of Major Components of Deferred Income Tax Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Deferred income tax liabilities
Property, plant and equipment	$ (11,368)	$ (9,202)
Investments	(9,043)	(7,765)
Regulatory assets	(1,940)	(1,338)
Other	(251)	(52)
Total deferred income tax liabilities	(22,602)	(18,357)
Deferred income tax assets
Financial instruments	740	271
Loss carryforwards	1,272	1,745
Other	2,088	1,798
Total deferred income tax assets	4,100	3,814
Less valuation allowance	(298)	(147)
Total deferred income tax assets, net	3,802	3,667
Net deferred income tax liabilities, net	(18,800)	(14,690)
Total deferred income tax assets	796	341
Total deferred income tax liabilities	$ (19,596)	$ (15,031)

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Income Taxes
Foreign subsidiaries' undistributed earnings on which deferred income taxes has not been provided	$ 9,500	$ 6,600
Interest and penalties (recovery) expense related to unrecognized tax benefits	(8)	1
Accrued interest and penalties related to unrecognized tax benefits	6	14
Canada
Income Taxes
Benefit of unused tax loss carryforwards recognized	1,300	1,300
US
Income Taxes
Benefit of unused tax loss carryforwards recognized	$ 4,200	$ 6,400

INCOME TAXES - Schedule of Unre

INCOME TAXES - Schedule of Unrecognized Tax Benefits (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
UNRECOGNIZED TAX BENEFITS
Unrecognized tax benefits at beginning of year	$ 45	$ 55
Gross decreases for tax positions of prior year	(2)	(2)
Change in translation of foreign currency	4	(1)
Lapses of statute of limitations	(16)	(7)
Unrecognized tax benefits at end of year	$ 31	$ 45

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, 2024	Dec. 31, 2023	Dec. 31, 2022
Change in plan assets
Fair value of plan assets at beginning of year	$ 61
Fair value of plan assets at end of year	77	$ 61
Canada | Pension
Change in projected benefit obligation
Projected benefit obligation at beginning of year	4,092	3,630
Service cost	103	81	$ 131
Interest cost	186	184	127
Participant contributions	32	31
Actuarial (gain)/loss	0	359
Benefits paid	(210)	(193)
Transfer in	0	0
Foreign currency exchange rate changes	0	0
Other	0	0
Projected benefit obligation at end of year	4,203	4,092	3,630
Change in plan assets
Fair value of plan assets at beginning of year	4,528	4,234
Actual return on plan assets	627	427
Employer contributions	23	27
Participant contributions	32	31
Benefits paid	(210)	(193)
Transfer in	0	0
Foreign currency exchange rate changes	0	0
Other	0	2
Fair value of plan assets at end of year	5,000	4,528	4,234
Overfunded status at end of year	797	436
Presented as follows:
Deferred amounts and other assets	943	636
Other current liabilities	(10)	(8)
Other long-term liabilities	(136)	(192)
Amount recognized in balance sheet	797	436
Accumulated benefit obligation	3,900	3,800
Canada | Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	18	14
Canada | OPEB
Change in projected benefit obligation
Projected benefit obligation at beginning of year	228	211
Service cost	3	3	4
Interest cost	10	11	7
Participant contributions	0	0
Actuarial (gain)/loss	(21)	13
Benefits paid	(10)	(10)
Transfer in	0	0
Foreign currency exchange rate changes	0	0
Projected benefit obligation at end of year	210	228	211
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	10	10
Participant contributions	0	0
Benefits paid	(10)	(10)
Transfer in	0	0
Foreign currency exchange rate changes	0	0
Other	0	0
Fair value of plan assets at end of year	0	0	0
Overfunded status at end of year	(210)	(228)
Presented as follows:
Deferred amounts and other assets	0	0
Other current liabilities	(11)	(12)
Other long-term liabilities	(199)	(216)
Amount recognized in balance sheet	(210)	(228)
US
Change in plan assets
Employer contributions	35	33	30
US | Pension
Change in projected benefit obligation
Projected benefit obligation at beginning of year	1,036	1,029
Service cost	60	40	43
Interest cost	69	47	24
Participant contributions	0	0
Actuarial (gain)/loss	(98)	31
Benefits paid	(100)	(76)
Transfer in	569	0
Foreign currency exchange rate changes	119	(29)
Other	(7)	(6)
Projected benefit obligation at end of year	1,648	1,036	1,029
Change in plan assets
Fair value of plan assets at beginning of year	1,052	1,080
Actual return on plan assets	197	78
Employer contributions	5	5
Participant contributions	0	0
Benefits paid	(100)	(76)
Transfer in	900	0
Foreign currency exchange rate changes	146	(29)
Other	(6)	(6)
Fair value of plan assets at end of year	2,194	1,052	1,080
Overfunded status at end of year	546	16
Presented as follows:
Deferred amounts and other assets	653	116
Other current liabilities	(6)	(5)
Other long-term liabilities	(101)	(95)
Amount recognized in balance sheet	546	16
Accumulated benefit obligation	1,600	1,000
US | Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	80	62
US | OPEB
Change in projected benefit obligation
Projected benefit obligation at beginning of year	129	136
Service cost	3	1	1
Interest cost	7	6	3
Participant contributions	5	5
Actuarial (gain)/loss	(9)	4
Benefits paid	(20)	(20)
Transfer in	46	0
Foreign currency exchange rate changes	16	(3)
Projected benefit obligation at end of year	177	129	136
Change in plan assets
Fair value of plan assets at beginning of year	187	185
Actual return on plan assets	22	14
Employer contributions	7	7
Participant contributions	5	5
Benefits paid	(20)	(20)
Transfer in	55	0
Foreign currency exchange rate changes	20	(4)
Other	2	0
Fair value of plan assets at end of year	278	187	$ 185
Overfunded status at end of year	101	58
Presented as follows:
Deferred amounts and other assets	113	73
Other current liabilities	0	0
Other long-term liabilities	(12)	(15)
Amount recognized in balance sheet	$ 101	$ 58

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, 2024	Dec. 31, 2023
Canada
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	$ 404	$ 394
Fair value of plan assets	283	243
Canada | OPEB
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	210	228
Fair value of plan assets	0	0
Projected benefit obligation	428	416
Fair value of plan assets	283	243
US
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	107	99
Fair value of plan assets	0	0
US | OPEB
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	100	78
Fair value of plan assets	88	63
Projected benefit obligation	107	99
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, 2024	Dec. 31, 2023
Canada | Pension
Amount included in AOCI
Net actuarial (gain)/loss	$ (122)	$ 51
Prior service cost	0	0
Total amount recognized in AOCI	(122)	51
Canada | OPEB
Amount included in AOCI
Net actuarial (gain)/loss	(99)	(82)
Prior service cost	0	(1)
Total amount recognized in AOCI	(99)	(83)
US | Pension
Amount included in AOCI
Net actuarial (gain)/loss	(42)	74
Prior service cost	5	1
Total amount recognized in AOCI	(37)	75
US | OPEB
Amount included in AOCI
Net actuarial (gain)/loss	(103)	(96)
Prior service cost	(16)	(22)
Total amount recognized in AOCI	$ (119)	$ (118)

PENSION AND OTHER POSTRETIREM_6

PENSION AND OTHER POSTRETIREMENT BENEFITS - Net Benefit Costs Recognized (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pension | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost1	$ 103	$ 81	$ 131
Interest cost	186	184	127
Expected return on plan assets	(304)	(271)	(295)
Amortization/settlement of net actuarial (gain)/loss	4	0	8
Amortization/curtailment of prior service credit	0	0	0
Net periodic benefit (credit)/cost	(11)	(6)	(29)
Defined contribution benefit cost	12	12	10
Net pension (credit)/cost recognized in Earnings	1	6	(19)
Amount recognized in OCI:
Amortization/settlement of net actuarial (gain)/loss	0	0	(2)
Amortization/curtailment of prior service credit	0	0	0
Net actuarial (gain)/loss arising during the year	(173)	115	(288)
Total amount recognized in OCI	(173)	115	(290)
Total amount recognized in Comprehensive income	(172)	121	(309)
Pension | US
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost1	60	40	43
Interest cost	69	47	24
Expected return on plan assets	(131)	(77)	(85)
Amortization/settlement of net actuarial (gain)/loss	7	(4)	0
Amortization/curtailment of prior service credit	(4)	0	(2)
Net periodic benefit (credit)/cost	1	6	(20)
Defined contribution benefit cost	0	0	0
Net pension (credit)/cost recognized in Earnings	1	6	(20)
Amount recognized in OCI:
Amortization/settlement of net actuarial (gain)/loss	0	4	0
Amortization/curtailment of prior service credit	4	0	2
Net actuarial (gain)/loss arising during the year	(116)	30	(52)
Total amount recognized in OCI	(112)	34	(50)
Total amount recognized in Comprehensive income	(111)	40	(70)
OPEB | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost1	3	3	4
Interest cost	10	11	7
Expected return on plan assets	0	0	0
Amortization/settlement of net actuarial (gain)/loss	(5)	(6)	(1)
Amortization/curtailment of prior service credit	(1)	0	0
Net pension (credit)/cost recognized in Earnings	7	8	10
Amount recognized in OCI:
Amortization/settlement of net actuarial (gain)/loss	5	6	1
Amortization/curtailment of prior service credit	1	0	0
Net actuarial (gain)/loss arising during the year	(22)	13	(67)
Total amount recognized in OCI	(16)	19	(66)
Total amount recognized in Comprehensive income	(9)	27	(56)
OPEB | US
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost1	3	1	1
Interest cost	7	6	3
Expected return on plan assets	(15)	(11)	(12)
Amortization/settlement of net actuarial (gain)/loss	(5)	(6)	(6)
Amortization/curtailment of prior service credit	(6)	(8)	(7)
Net pension (credit)/cost recognized in Earnings	(16)	(18)	(21)
Amount recognized in OCI:
Amortization/settlement of net actuarial (gain)/loss	5	6	6
Amortization/curtailment of prior service credit	6	8	7
Net actuarial (gain)/loss arising during the year	(12)	0	(4)
Total amount recognized in OCI	(1)	14	9
Total amount recognized in Comprehensive income	$ (17)	$ (4)	$ (12)

PENSION AND OTHER POSTRETIREM_7

PENSION AND OTHER POSTRETIREMENT BENEFITS - Actuarial Assumptions (Details)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Canada | Pension
Projected benefit obligation
Discount rate	4.70%	4.60%	5.10%
Rate of salary increase	3%	3%	2.90%
Net periodic benefit cost
Discount rate	4.60%	5.30%	3.20%
Rate of return on plan assets	6.80%	6.50%	6.60%
Rate of salary increase	3%	2.90%	2.90%
Canada | OPEB
Projected benefit obligation
Discount rate	4.70%	4.60%	5.30%
Net periodic benefit cost
Discount rate	4.60%	5.30%	3.20%
US | Pension
Projected benefit obligation
Discount rate	5.50%	4.70%	4.90%
Rate of salary increase	2.60%	2.60%	2.80%
Cash balance interest credit rate	4%	4.50%	4.30%
Net periodic benefit cost
Discount rate	4.80%	4.90%	2.60%
Rate of return on plan assets	7.30%	7.40%	7.40%
Rate of salary increase	2.80%	2.80%	2.80%
Cash balance interest credit rate	4.40%	4.30%	4.30%
US | OPEB
Projected benefit obligation
Discount rate	5.30%	4.70%	4.90%
Net periodic benefit cost
Discount rate	5.50%	4.90%	2.40%
Rate of return on plan assets	6.70%	5.90%	6%

PENSION AND OTHER POSTRETIREM_8

PENSION AND OTHER POSTRETIREMENT BENEFITS - Assumed Health Care Cost Trend Rates (Details)	Dec. 31, 2024	Dec. 31, 2023
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	3.20%	4.70%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	3.70%	3.30%
US | Enbridge Employee Services, Inc. Health Reimbursement Account Plan
MEDICAL COST TRENDS (as percent)
Three- year increase in healthcare costs (percent)	5%

PENSION AND OTHER POSTRETIREM_9

PENSION AND OTHER POSTRETIREMENT BENEFITS - Plan Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Change in plan assets
Fair value of plan assets at beginning of year	$ 61
Fair value of plan assets at end of year	$ 77	$ 61
Canada | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	46.20%
Plan asset allocations	39.10%	41.40%
Canada | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	23%
Plan asset allocations	31.60%	29.60%
Canada | Alternatives
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	30.80%
Plan asset allocations	29.30%	29%
Canada | Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 4,528	$ 4,234
Fair value of plan assets at end of year	5,000	4,528
Canada | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	227
Fair value of plan assets at end of year	335	227
Canada | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	3,011
Fair value of plan assets at end of year	3,201	3,011
Canada | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	1,290	1,291
Unrealized and realized gains	104	(41)
Purchases and settlements, net	70	40
Fair value of plan assets at end of year	1,464	1,290
Canada | Pension | Alternatives
Change in plan assets
Fair value of plan assets at beginning of year	1,290
Fair value of plan assets at end of year	1,464	1,290
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	1,290
Fair value of plan assets at end of year	1,464	1,290
Canada | Pension | Cash and Cash Equivalents
Change in plan assets
Fair value of plan assets at beginning of year	227
Fair value of plan assets at end of year	201	227
Canada | Pension | Cash and Cash Equivalents | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	227
Fair value of plan assets at end of year	201	227
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	1,871
Fair value of plan assets at end of year	1,951	1,871
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	134	0
Canada | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	1,871
Fair value of plan assets at end of year	1,817	1,871
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	3
Fair value of plan assets at end of year	3	3
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	3
Fair value of plan assets at end of year	3	3
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	446
Fair value of plan assets at end of year	543	446
Canada | 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
Canada | Pension | Government | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	446
Fair value of plan assets at end of year	543	446
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	667
Fair value of plan assets at end of year	838	667
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	667
Fair value of plan assets at end of year	838	667
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	24
Fair value of plan assets at end of year		24
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
Canada | Pension | Foreign exchange contracts | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	24
Fair value of plan assets at end of year		24
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
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)	43.40%
Plan asset allocations	44.80%	39.50%
US | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	23.20%
Plan asset allocations	33%	19.40%
US | Alternatives
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	33.40%
Plan asset allocations	22.20%	41.10%
US | Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 1,052	$ 1,080
Fair value of plan assets at end of year	2,194	1,052
US | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	8
Fair value of plan assets at end of year	84	8
US | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	611
Fair value of plan assets at end of year	1,622	611
US | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	433	445
Unrealized and realized gains	63	(12)
Purchases and settlements, net	(8)	0
Fair value of plan assets at end of year	488	433
US | Pension | Alternatives
Change in plan assets
Fair value of plan assets at beginning of year	433
Fair value of plan assets at end of year	488	433
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	433
Fair value of plan assets at end of year	488	433
US | Pension | Cash and Cash Equivalents
Change in plan assets
Fair value of plan assets at beginning of year	8
Fair value of plan assets at end of year	57	8
US | Pension | Cash and Cash Equivalents | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	8
Fair value of plan assets at end of year	57	8
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	416
Fair value of plan assets at end of year	981	416
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	27	0
US | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	416
Fair value of plan assets at end of year	954	416
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	46
Fair value of plan assets at end of year	194	46
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	46
Fair value of plan assets at end of year	194	46
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	149
Fair value of plan assets at end of year	474	149
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	149
Fair value of plan assets at end of year	474	149
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
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
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
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
US | OPEB
Change in plan assets
Fair value of plan assets at beginning of year	187	185
Fair value of plan assets at end of year	278	187
US | OPEB | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	187
Fair value of plan assets at end of year	278	187
US | OPEB | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	45
Fair value of plan assets at end of year	75	45
US | OPEB | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	113
Fair value of plan assets at end of year	170	113
US | OPEB | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	29	28
Unrealized and realized gains	5	1
Purchases and settlements, net	(1)	0
Fair value of plan assets at end of year	33	29
US | OPEB | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	29
Fair value of plan assets at end of year	33	29
US | OPEB | Alternatives | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	29
Fair value of plan assets at end of year	33	29
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	29
Fair value of plan assets at end of year	33	29
US | OPEB | Cash and Cash Equivalents | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	3
Fair value of plan assets at end of year	4	3
US | OPEB | Cash and Cash Equivalents | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	3
Fair value of plan assets at end of year	4	3
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	36
Fair value of plan assets at end of year	52	36
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	36
Fair value of plan assets at end of year	52	36
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	93	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	93	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	45
Fair value of plan assets at end of year	77	45
US | OPEB | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	42
Fair value of plan assets at end of year	71	42
US | OPEB | Government | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	3
Fair value of plan assets at end of year	6	3
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	12
Fair value of plan assets at end of year	19	12
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	12
Fair value of plan assets at end of year	19	12
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, 2024 CAD ($)
Canada | Pension
Benefits Expected to be Paid by the Company
2025	$ 214
2026	220
2027	226
2028	232
2029	238
2030-2034	1,285
Contributions expected to be paid in next fiscal year	21
Canada | OPEB
Benefits Expected to be Paid by the Company
2025	11
2026	12
2027	12
2028	12
2029	12
2030-2034	64
Contributions expected to be paid in next fiscal year	11
US | Pension
Benefits Expected to be Paid by the Company
2025	117
2026	120
2027	123
2028	123
2029	120
2030-2034	625
Contributions expected to be paid in next fiscal year	6
US | OPEB
Benefits Expected to be Paid by the Company
2025	16
2026	16
2027	16
2028	16
2029	16
2030-2034	71
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, 2024	Dec. 31, 2023	Dec. 31, 2022
Pension and Other Postretirement Benefit Disclosures
Total contributions by the Company	$ 35	$ 33	$ 30
Minimum
Pension and Other Postretirement Benefit Disclosures
Percent of match (percent)	3%
Maximum
Pension and Other Postretirement Benefit Disclosures
Percent of match (percent)	7%

LEASES - Narrative (Details)

LEASES - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Operating lease, expense	$ 132	$ 131	$ 118
Operating lease, payments	$ 128	$ 129	$ 123
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease term	2 months
Lessor, operating lease, remaining lease term	3 months
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	41 years
Lessor, operating lease, remaining lease term	27 years

LEASES - Schedule of Supplement

LEASES - Schedule of Supplemental Statements of Financial Position (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Leases, Operating [Abstract]
Operating lease right-of-use assets, net	$ 785	$ 669
Operating lease liabilities - current	121	98
Operating lease liabilities - long-term	738	652
Total operating lease liabilities	$ 859	$ 750
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]	Trade payables and accrued liabilities	Trade payables and accrued liabilities
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	$ 294	$ 287
Finance lease liabilities - current	16	19
Finance lease liabilities - long-term	300	264
Total finance lease liabilities	$ 316	$ 283
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 (in years)	14 years	12 years
Finance leases (in years)	31 years	31 years
Weighted average discount rate
Operating leases (as percent)	4.80%	4.50%
Finance leases (as percent)	5.80%	5.70%
Affiliated Entity
Leases, Operating [Abstract]
Operating lease right-of-use assets, net	$ 42	$ 42
Operating lease liabilities - current	6	5
Operating lease liabilities - long-term	$ 37	$ 38

LEASES - Lease Commitments (Det

LEASES - Lease Commitments (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Operating leases
2025	$ 148
2026	134
2027	123
2028	97
2029	65
Thereafter	685
Total undiscounted lease payments	1,252
Less imputed interest	(393)
Total	859	$ 750
Finance leases
2025	31
2026	30
2027	23
2028	23
2029	22
Thereafter	531
Total undiscounted lease payments	660
Less imputed interest	(344)
Total finance lease liabilities	$ 316	$ 283

LEASES - Lessor Lease Income (D

LEASES - Lessor Lease Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating lease income	$ 229	$ 241	$ 266
Variable lease income	321	299	321
Total lease income	$ 550	$ 540	$ 587
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, 2024 CAD ($)
Leases [Abstract]
2025	$ 221
2026	202
2027	197
2028	198
2029	199
Thereafter	1,415
Future lease payments	$ 2,432

OTHER INCOME_(EXPENSE) (Details

OTHER INCOME/(EXPENSE) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Other Income and Expenses [Abstract]
Realized foreign currency gain/(loss)	$ 121	$ (129)	$ 92
Unrealized foreign currency gain/(loss)	(2,199)	821	(1,094)
Net defined pension and OPEB credit	188	135	239
Other	564	397	174
Total	$ (1,326)	$ 1,224	$ (589)

CHANGES IN OPERATING ASSETS A_3

CHANGES IN OPERATING ASSETS AND LIABILITIES (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
CHANGES IN OPERATING ASSETS AND LIABILITIES
Trade receivables and unbilled revenues	$ (1,638)	$ 1,125	$ (572)
Accounts receivable from affiliates	(23)	18	17
Inventory	177	763	(599)
Other current and non-current assets	(426)	1,301	(394)
Trade payables and accrued liabilities	1,383	(1,542)	585
Accounts payable to affiliates	(8)	(66)	16
Interest payable	157	199	58
Other current and long-term liabilities	245	513	877
Changes in operating assets and liabilities	$ (133)	$ 2,311	$ (12)

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
RELATED PARTY TRANSACTIONS
Revenues	$ 16,217	$ 14,882	$ 11,336	$ 11,038	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 53,473	$ 43,649	$ 53,309
Operating and administrative									9,427	8,600	8,219
Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Operating and administrative									637	625	503
Commodity costs									22	63	778
Gas distribution costs									147	140	136
Transportation and other services
RELATED PARTY TRANSACTIONS
Revenues									19,653	19,226	17,922
Transportation and other services | Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Revenues									181	169	185
Commodity sales
RELATED PARTY TRANSACTIONS
Revenues									27,018	18,981	29,150
Commodity sales | Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Revenues									0	0	51
Seaway Crude Pipeline System | Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Operating and administrative									650	632	495
Aux Sable Canada LP | Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Commodity costs									$ 0	$ 2	$ 571

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details) $ in Millions	Dec. 31, 2024 CAD ($)
Purchase of services, pipe and other materials, including transportation
Total	$ 14,019
Less than 1 year	4,260
2 years	2,047
3 years	1,755
4 years	1,535
5 years	1,200
Thereafter	3,222
Maintenance agreements
Total	452
Less than 1 year	57
2 years	56
3 years	57
4 years	36
5 years	36
Thereafter	210
Right-of-ways commitments
Total	981
Less than 1 year	52
2 years	48
3 years	53
4 years	49
5 years	49
Thereafter	730
Total
Total	15,452
Less than 1 year	4,369
2 years	2,151
3 years	1,865
4 years	1,620
5 years	1,285
Thereafter	$ 4,162

QUARTERLY FINANCIAL DATA (UNA_3

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - CAD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 16,217	$ 14,882	$ 11,336	$ 11,038	$ 11,298	$ 9,844	$ 10,432	$ 12,075	$ 53,473	$ 43,649	$ 53,309
Operating income	2,447	2,218	2,273	2,711	1,845	1,794	2,350	2,662	9,649	8,651	5,178
Earnings	618	1,447	2,001	1,565	1,568	623	2,001	1,866	5,631	6,058	2,938
Earnings attributable to controlling interests	595	1,391	1,943	1,512	1,818	621	1,935	1,817	5,441	6,191	3,003
Earnings attributable to common shareholders	$ 493	$ 1,293	$ 1,848	$ 1,419	$ 1,726	$ 532	$ 1,848	$ 1,733	$ 5,053	$ 5,839	$ 2,589
Earnings per common share
Basic (in CAD per share)	$ 0.23	$ 0.59	$ 0.86	$ 0.67	$ 0.81	$ 0.26	$ 0.91	$ 0.86	$ 2.34	$ 2.84	$ 1.28
Diluted (in CAD per share)	$ 0.23	$ 0.59	$ 0.86	$ 0.67	$ 0.81	$ 0.26	$ 0.91	$ 0.85	$ 2.34	$ 2.84	$ 1.28