TransCanada Pipelines 40-F 14 Feb 25 2024 FY Annual report (Canada) Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2024 shares
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
Current Fiscal Year End Date	--12-31
Entity Registrant Name	TC ENERGY CORPORATION
Entity File Number	1-31690
Entity Incorporation, State or Country Code	Z4
Entity Primary SIC Number	4922
Entity Address, Address Line One	TC Energy Tower, 450 - 1 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 5H1
City Area Code	403
Local Phone Number	920-2000
Title of 12(b) Security	Common Shares (including Rights under Shareholder Rights Plan) of TC Energy Corporation
Trading Symbol	TRP
Security Exchange Name	NYSE
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	1,039,095,489
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Central Index Key	0001232384
Amendment Flag	false
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY
TRANSCANADA PIPELINES LIMITED
Entity Information [Line Items]
Entity Registrant Name	TRANSCANADA PIPELINES LIMITED
Entity File Number	1-8887
Entity Tax Identification Number	52-2179728
Security Reporting Obligation	15(d)
Entity Common Stock, Shares Outstanding	992,720,977
Entity Central Index Key	0000099070
Amendment Flag	false
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY
Business contact
Entity Information [Line Items]
Entity Address, Address Line One	700 Louisiana Street
Entity Address, Address Line Two	Suite 700
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002-2700
Contact Personnel Name	TransCanada PipeLine USA Ltd
City Area Code	832
Local Phone Number	320-5201

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2024
Auditor Information [Abstract]
Auditor Name	KPMG LLP
Auditor Location	Calgary, AB, Canada
Auditor Firm ID	85

Consolidated statement of incom

Consolidated statement of income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenues	$ 13,771	$ 13,267	$ 12,309
Income (Loss) from Equity Investments (Note 11)	1,558	1,310	999
Impairment of equity investment (Note 7)	0	(2,100)	(3,048)
Operating and Other Expenses
Plant operating costs and other	4,413	4,073	4,228
Commodity purchases resold	217	80	22
Property taxes	820	781	727
Depreciation and amortization	2,535	2,446	2,262
Goodwill impairment charge (Note 14)	0	0	571
Total operating and other expenses	7,985	7,380	7,810
Net Gain (Loss) on Sale of Assets (Note 30)	620	0	0
Financial Charges
Interest expense (Note 20)	3,019	2,966	2,300
Allowance for funds used during construction	(784)	(575)	(369)
Foreign exchange (gains) losses on loans receivable	147	(320)	185
Interest income and other	(324)	(272)	(140)
Total financial charges	2,058	1,799	1,976
Income (Loss) from Continuing Operations before Income Taxes	5,906	3,298	474
Income Tax Expense (Recovery) from Continuing Operations (Note 19)
Current	495	864	363
Deferred	427	(22)	(41)
Income Tax Expense	922	842	322
Net Income (Loss) from Continuing Operations	4,984	2,456	152
Net Income (Loss) from Discontinued Operations, Net of Tax	395	612	633
Net Income (Loss)	5,379	3,068	785
Net income (loss) attributable to non-controlling interests (Note 23)	681	146	37
Net income (loss) attributable to controlling interests from continuing operations	4,303	2,310	115
Net Income (Loss) Attributable to Controlling Interests	4,698	2,922	748
Preferred share dividends	104	93	107
Net income (loss) attributable to common shares from continuing operations	4,199	2,217	8
Net income (loss) attributable to common shares from continuing operations	$ 4,594	$ 2,829	$ 641
Net Income (Loss) per Common Share - Basic and Diluted (Note 24)
Continuing operations, Basic (in dollars per share)	$ 4.05	$ 2.15	$ 0.01
Continuing operations, Diluted (in dollars per share)	4.05	2.15	0.01
Discontinued operations, Basic (in dollars per share)	0.38	0.60	0.63
Discontinued operations, Diluted (in dollars per share)	0.38	0.60	0.63
Basic (in dollars per share)	4.43	2.75	0.64
Diluted (in dollars per share)	4.43	2.75	0.64
Dividends Declared per Common Share (in dollars per share)	$ 3.7025	$ 3.72	$ 3.60
Weighted Average Number of Common Shares (millions) (Note 24)
Basic (in shares)	1,038	1,030	995
Diluted (in shares)	1,038	1,030	996
Canadian Natural Gas Pipelines
Revenues	$ 5,600	$ 5,173	$ 4,764
U.S. Natural Gas Pipelines
Revenues	6,339	6,229	5,933
Mexico Natural Gas Pipelines
Revenues	870	846	688
Power and Energy Solutions
Revenues	954	1,019	924
Corporate
Revenues	$ 8	$ 0	$ 0

Consolidated statement of compr

Consolidated statement of comprehensive income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 5,379	$ 3,068	$ 785
Other Comprehensive Income (Loss), Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations	1,602	(1,141)	1,494
Reclassification of foreign currency translation (gains) on net investment on disposal of foreign operations	(25)	0	0
Change in fair value of net investment hedges	(18)	17	(36)
Change in fair value of cash flow hedges	35	0	(39)
Reclassification to net income of (gains) losses on cash flow hedges	(16)	74	42
Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans	83	(11)	63
Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans	(6)	0	6
Other comprehensive income (loss) on equity investments	173	(211)	867
Other comprehensive income (loss) (Note 26)	1,828	(1,272)	2,397
Comprehensive Income (Loss)	7,207	1,796	3,182
Comprehensive income (loss) attributable to non-controlling interests	1,584	(220)	45
Comprehensive Income (Loss) Attributable to Controlling Interests	5,623	2,016	3,137
Preferred share dividends	104	93	107
Comprehensive Income (Loss) Attributable to Common Shares	$ 5,519	$ 1,923	$ 3,030

Consolidated statement of cash

Consolidated statement of cash flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash Generated from Operations
Net income (loss)	$ 5,379	$ 3,068	$ 785
Depreciation and amortization	2,788	2,778	2,584
Goodwill impairment charge (Note 14)	21	(4)	453
Deferred income taxes (Note 19)	493	11	174
(Income) loss from equity investments (Note 11)	(1,608)	(1,377)	(1,054)
Impairment of equity investment (Note 7)	0	2,100	3,048
Distributions received from operating activities of equity investments (Note 11)	1,675	1,254	1,025
Employee post-retirement benefits funding, net of expense (Note 27)	11	(17)	(29)
Net (gain) loss on sale of assets (Note 30)	(620)	0	0
Equity allowance for funds used during construction	(512)	(367)	(248)
Unrealized (gains) losses on financial instruments (Note 28)	340	(342)	135
Expected credit loss provision (Note 28)	(22)	(83)	163
Foreign exchange (gains) losses on loans receivable	(216)	44	28
Other	(232)	(4)	(50)
(Increase) decrease in operating working capital (Note 29)	199	207	(639)
Net cash provided by operations	7,696	7,268	6,375
Investing Activities
Capital expenditures (Note 5)	(6,308)	(8,007)	(6,678)
Capital projects in development (Note 5)	(50)	(142)	(49)
Contributions to equity investments (Notes 5, 7 and 11)	(4,683)	(4,149)	(3,433)
Acquisitions, net of cash acquired (Note 30)	0	(307)	0
Loans to affiliate (issued) repaid, net (Notes 7 and 12)	0	250	(11)
Keystone XL contractual recoveries	7	10	571
Proceeds from sales of assets, net of transaction costs (Note 30)	791	33	0
Other distributions from equity investments (Note 11)	3,686	23	2,632
Deferred amounts and other	(352)	2	(41)
Net cash (used in) provided by investing activities	(6,909)	(12,287)	(7,009)
Financing Activities
Notes payable issued (repaid), net	341	(6,299)	766
Long-term debt issued, net of issue costs	8,089	15,884	2,508
Long-term debt repaid	(9,273)	(3,772)	(1,338)
Disposition of equity interest, net of transaction costs (Note 30)	419	5,328	0
Junior subordinated notes issued, net of issue costs	1,465	0	1,008
Cash transferred to South Bow, net of debt settlements	(244)	0	0
Dividends on common shares	(3,953)	(2,787)	(3,192)
Dividends on preferred shares	(99)	(92)	(106)
Contributions from redeemable non-controlling interest	21	0	0
Distributions to non-controlling interests and other	(755)	(173)	(87)
Common shares issued, net of issue costs	88	4	1,905
Preferred shares redeemed (Note 25)	0	0	(1,000)
Gains (losses) on settlement of financial instruments	27	0	23
Net cash (used in) provided by financing activities	(3,874)	8,093	487
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	210	(16)	94
Increase (Decrease) in Cash and Cash Equivalents	(2,877)	3,058	(53)
Cash and Cash Equivalents, Beginning of year	3,678	620	673
Cash and Cash Equivalents, End of year	$ 801	$ 3,678	$ 620

Consolidated balance sheet

Consolidated balance sheet $ in Millions, $ in Millions	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)
Current Assets
Cash and cash equivalents	$ 801	$ 3,678
Accounts receivable	2,611	2,427
Inventories	747	771
Other current assets (Note 8)	1,339	1,419
Current assets of discontinued operations (Note 4)	235	3,077
Total current assets	5,733	11,372
Plant, Property and Equipment (Note 9)	77,501	69,451
Net Investment in Leases (Note 10)	2,477	2,263
Equity Investments (Note 11)	10,636	9,240
Restricted Investments	2,998	2,532
Regulatory Assets (Note 13)	2,682	2,330
Goodwill (Note 14)	13,670	12,532
Other Long-Term Assets (Note 15)	2,410	2,881
Long-Term Assets of Discontinued Operations (Note 4)	136	12,433
Total assets	118,243	125,034
Current Liabilities
Notes payable (Note 16)	387	0
Accounts payable and other (Note 17)	5,297	4,305
Dividends payable	874	979
Accrued interest	828	913
Current portion of long-term debt (Note 20)	2,955	2,938
Current liabilities of discontinued operations (Note 4)	170	2,682
Total current liabilities	10,511	11,817
Regulatory Liabilities (Note 13)	5,303	4,703
Other Long-Term Liabilities (Note 18)	1,051	991
Deferred Income Tax Liabilities (Note 19)	6,884	6,972
Long-Term Debt (Note 20)	44,976	49,976
Junior Subordinated Notes (Note 21)	11,048	10,287
Long-Term Liabilities of Discontinued Operations (Note 4)	110	1,280
Total liabilities	79,883	86,026
EQUITY
Common shares, no par value (Note 24)	30,101	30,002
Preferred shares (Note 25)	2,499	2,499
Retained earnings (Accumulated deficit)	(5,241)	(2,997)
Accumulated other comprehensive income (loss) (Note 26)	233	49
Controlling Interests	27,592	29,553
Non-Controlling Interests (Note 23)	10,768	9,455
Total Equity	38,360	39,008
Total Liabilities and Equity	$ 118,243	$ 125,034

Consolidated balance sheet (Par

Consolidated balance sheet (Parenthetical) - shares shares in Millions	Dec. 31, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Common shares issued (in shares)	1,039	1,037
Common shares outstanding (in shares)	1,039	1,037

Consolidated statement of equit

Consolidated statement of equity - CAD ($) $ in Millions	Total	Equity Attributable to Controlling Interests	Common shares	Preferred Shares (Note 25)	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)	AOCI Attributable to Parent	Equity Attributable to Non-Controlling Interests
Balance at beginning of year at Dec. 31, 2021			$ 26,716	$ 3,487	$ 729	$ 3,773	$ (1,434)	$ 125
Shares issued:
Dividend reinvestment and share purchase plan			342
Exercise of stock options			183
Under public offering, net of issue costs			1,754
Issuance of stock options, net of exercises					(7)
Net income (loss) attributable to controlling interests	$ 748					748
Common share dividends						(3,595)
Preferred share dividends						(95)
Redemption of shares				(988)		(12)
Other comprehensive income (loss) attributable to controlling interests	2,397						2,389
Net income (loss) attributable to non-controlling interests (Note 23)	(37)							37
Other comprehensive income (loss) attributable to non-controlling interests								8
Distributions declared to non-controlling interests								(44)
Balance at end of year at Dec. 31, 2022	34,116	$ 33,990	28,995	2,499	722	819	955	126
Shares issued:
Dividend reinvestment and share purchase plan			1,003
Exercise of stock options			4
Issuance of stock options, net of exercises					9
Disposition of equity interest, net of transaction costs (Note 30)					(3,537)			9,451
Reclassification of additional paid-in capital deficit to accumulated deficit					2,806	(2,806)
Net income (loss) attributable to controlling interests	2,922					2,922
Common share dividends						(3,839)
Preferred share dividends						(93)
Other comprehensive income (loss) attributable to controlling interests	(1,272)						(379)
Impact of non-controlling interest (Note 30)							(527)
Non-controlling interests on acquisition of Texas Wind Farms (Note 30)								222
Net income (loss) attributable to non-controlling interests (Note 23)	(146)							146
Other comprehensive income (loss) attributable to non-controlling interests								(366)
Distributions declared to non-controlling interests								(124)
Balance at end of year at Dec. 31, 2023	39,008	29,553	30,002	2,499		(2,997)	49	9,455
Shares issued:
Exercise of stock options			99
Issuance of stock options, net of exercises					(5)
Disposition of equity interest, net of transaction costs (Note 30)					(41)			461
Reclassification of additional paid-in capital deficit to accumulated deficit					46	(46)
Net income (loss) attributable to controlling interests	4,698					4,698
Common share dividends						(3,842)
Preferred share dividends						(104)
Spinoff of Liquids Pipelines business (Note 4)						(2,950)	(741)
Other comprehensive income (loss) attributable to controlling interests	1,828						946
Impact of non-controlling interest (Note 30)							(21)
Net income (loss) attributable to non-controlling interests (Note 23)	(681)							681
Other comprehensive income (loss) attributable to non-controlling interests								903
Contributions from non-controlling interests								21
Distributions declared to non-controlling interests								(753)
Balance at end of year at Dec. 31, 2024	$ 38,360	$ 27,592	$ 30,101	$ 2,499	$ 0	$ (5,241)	$ 233	$ 10,768

DESCRIPTION OF TC ENERGY'S BUSI

DESCRIPTION OF TC ENERGY'S BUSINESS	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
DESCRIPTION OF TC ENERGY'S BUSINESS	DESCRIPTION OF TC ENERGY'S BUSINESS TC Energy Corporation (TC Energy or the Company) is a leading North American energy infrastructure company which operates in four business segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines and Power and Energy Solutions. These segments offer different products and services, including certain natural gas and electricity marketing and storage services. The Company also has a Corporate segment, consisting of corporate and administrative functions that provide governance, financing and other support to the Company's business segments. Canadian Natural Gas Pipelines The Canadian Natural Gas Pipelines segment primarily consists of the Company's investments in 41,121 km (25,552 miles) of regulated natural gas pipelines currently in operation. U.S. Natural Gas Pipelines The U.S. Natural Gas Pipelines segment primarily consists of the Company's investments in 49,681 km (30,870 miles) of regulated natural gas pipelines, 532 Bcf of regulated natural gas storage facilities and other assets currently in operation. Mexico Natural Gas Pipelines The Mexico Natural Gas Pipelines segment primarily consists of the Company's investments in 2,885 km (1,791 miles) of regulated natural gas pipelines currently in operation. Power and Energy Solutions The Power and Energy Solutions segment primarily consists of the Company's investments in approximately 4,650 MW of power generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These assets are located in Alberta, Ontario, Québec, New Brunswick and Texas. In addition, TC Energy has physical and virtual power purchase agreements (PPAs) in Canada and the U.S. to buy and/or sell power from wind and solar facilities. These PPAs have the potential to be leases, derivatives or revenue arrangements depending on the contractual terms of the agreement. Spinoff of Liquids Pipelines Business On July 27, 2023, TC Energy announced plans to separate into two independent, investment-grade, publicly listed companies through the spinoff of its Liquids Pipelines business. TC Energy shareholders voted to approve the plan in June 2024 and, on October 1, 2024, TC Energy completed the spinoff of its Liquids Pipelines business into the new public company, South Bow Corporation (South Bow) (the Spinoff Transaction). TC Energy shareholders as of September 25, 2024 received one new TC Energy common share and 0.2 of a South Bow common share in exchange for each TC Energy common share held. TC Energy common shares resumed regular way trading on the TSX and NYSE on October 2, 2024. South Bow's common shares commenced regular way trading on the TSX on October 2, 2024 and on the NYSE on October 8, 2024, under the ticker symbol SOBO. Refer to Note 4, Discontinued operations, for additional information.

ACCOUNTING POLICIES

ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
ACCOUNTING POLICIES	ACCOUNTING POLICIES The Company's consolidated financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles. Amounts are stated in Canadian dollars unless otherwise indicated. Basis of Presentation These consolidated financial statements include the accounts of TC Energy and its subsidiaries. The Company consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. TC Energy uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. The Spinoff Transaction represented a strategic shift that had a major effect on the Company's operations and consolidated financial results. Accordingly, the historical results of the Liquids Pipelines business are presented as discontinued operations and have been excluded from continuing operations and segment disclosures for all periods presented. The Notes to the consolidated financial statements reflect continuing operations only, unless otherwise indicated. Prior to the spinoff, the operations of the Liquids Pipelines business were materially reported as the Company's Liquids Pipelines segment. Refer to Note 4, Discontinued operations, and Note 5, Segmented information, for additional information. Certain prior year amounts have been reclassified to conform to current year presentation. Use of Estimates and Judgments In preparing these consolidated financial statements, TC Energy is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Certain estimates and judgments have a material impact where the assumptions underlying these accounting estimates relate to matters that are highly uncertain at the time they are made or are subjective. These estimates and judgments include, but are not limited to, the assessment of goodwill impairment indicators and fair value of reporting units that contain goodwill (Note 14). Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial statements, but do not involve significant subjectivity or uncertainty. These estimates and judgments include, but are not limited to: • provisions for indemnities related to the South Bow Separation Agreement (Note 4) • recoverability and depreciation rates of plant, property and equipment (Note 9) • allocation of consideration to lease and non-lease components in a contract that contains a lease (Note 10) • assumptions used to measure the carrying amount of and expected credit losses on net investment in leases and certain contract assets (Notes 10 and 28) • fair value of equity investments (Note 11) • carrying value of regulatory assets and liabilities (Note 13) • recognition of asset retirement obligations (Note 18) • provisions for income taxes, including valuation allowances and releases as well as tax positions that may be reviewed as part of an audit by tax authorities (Note 19) • assumptions used to measure retirement and other post-retirement benefit obligations (Note 27) • fair value of financial instruments (Note 28) • fair value of Fluvanna Wind Farm and Blue Cloud Wind Farm (Texas Wind Farms) assets (Note 30) • commitments and provisions for contingencies and guarantees (Note 31). TC Energy continues to assess climate-related impacts on the consolidated financial statements. There are ongoing developments in the ESG frameworks and regulatory initiatives that could further impact accounting estimates and judgments including, but not limited to, assessment of asset useful lives, goodwill valuation, impairment of plant, property and equipment, accrued environmental costs and asset retirement obligations. The impact of these changes is continuously assessed to ensure any changes in assumptions that would impact estimates listed above are adjusted on a timely basis. Actual results could differ from these estimates. Regulation Certain Canadian, U.S. and Mexico natural gas pipeline and storage assets are regulated with respect to construction, operations and the determination of tolls. In Canada, regulated natural gas pipelines are subject to the authority of the Canada Energy Regulator (CER), the Alberta Energy Regulator or the B.C. Oil and Gas Commission. In the U.S., regulated interstate natural gas pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TC Energy's rate-regulated businesses which may differ from that otherwise recognized in non-rate-regulated businesses to reflect the economic impact of the regulators' decisions regarding revenues and tolls. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An operation qualifies for the use of RRA when it meets three criteria: • a regulator must establish or approve the rates for the regulated services or activities • the regulated rates must be designed to recover the cost of providing the services or products • it is reasonable to assume that rates set at levels to recover the cost can be charged to and collected from customers because of the demand for services or products and the level of direct or indirect competition. TC Energy's businesses that apply RRA currently include natural gas pipelines in Canada, U.S. and Mexico and regulated U.S. natural gas storage. Revenue Recognition The total consideration for services and products to which the Company expects to be entitled can include fixed and variable amounts. The Company has variable revenue that is subject to factors outside the Company's influence, such as market prices, actions of third parties and weather conditions. The Company considers this variable revenue to be "constrained" as it cannot be reliably estimated and, therefore, recognizes variable revenue when the service is provided. Revenues from contracts with customers are recognized net of any commodity taxes collected from customers which are subsequently remitted to governmental authorities. The Company's contracts with customers include natural gas pipelines capacity arrangements and transportation contracts, power generation contracts, natural gas storage and other contracts. Revenues from non-lease components associated with a lease arrangement are recognized systematically over the term of the contract. The majority of income earned from marketing activities, as it relates to the purchase and sale of natural gas and electricity, is recorded on a net basis in the month of delivery. Canadian Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Canadian natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. Revenues from the Company's Canadian natural gas pipelines under federal jurisdiction are subject to regulatory decisions by the CER. The tolls charged on these pipelines are based on revenue requirements designed to recover the costs of providing natural gas capacity for transportation services, which includes a return of and on capital, as approved by the CER. The Company's Canadian natural gas pipelines are generally not subject to earnings volatility related to variances in revenues and costs. These variances, except as related to incentive arrangements, are generally subject to deferral treatment and are recovered or refunded in future tolls. Revenues recognized prior to a CER decision on rates for that period reflect the CER's last approved return on equity (ROE) assumptions. Adjustments to revenues are recorded when the CER decision is received. Canadian natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Other Through the year, the Company was contracted to provide pipeline construction services to a partially-owned entity for a development fee. The development fee was considered variable consideration due to refund provisions in the contract. The Company recognized its estimate of the most likely amount of the variable consideration to which it was entitled. The development fee was recognized over time as the services were provided based on the input method using an estimate of activity level. U.S. Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's U.S. natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Company's U.S. interstate natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. U.S. natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Natural Gas Storage and Other Revenues from the Company's regulated U.S. natural gas storage services are generated mainly from firm committed capacity storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage including specifications with regard to the amount of natural gas that can be injected or withdrawn on a daily basis. Revenues are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. Natural gas storage services revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it stores for customers. The Company owns mineral rights associated with certain natural gas storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest which is recognized when natural gas and associated liquids are produced. Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from certain of the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Other The Company generates revenues from operating and maintenance services provided on leased pipelines. Revenues earned from these services are recognized ratably over the term of the contract. Power and Energy Solutions Power Revenues from the Company's Power and Energy Solutions business are primarily derived from long-term contractual commitments to provide power capacity to meet the demands of the market and from the sale of electricity to both centralized markets and to customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and capacity payments are recognized as the services are provided and as electricity and steam is delivered. Power generation revenues are invoiced and received on a monthly basis. Natural Gas Storage and Other Non-regulated natural gas storage contracts include park, loan and term storage arrangements. Revenues are recognized as the services are provided. Term storage revenues are invoiced and received on a monthly basis. Revenues from ancillary services are recognized as the service is provided. The Company does not take ownership of the natural gas that it stores for customers. Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. Inventories Inventories primarily consist of materials and supplies including spare parts and fuel, proprietary natural gas inventory in storage and emissions allowances and credits not held for compliance. The Company purchases certain emissions allowances and credits as part of bundled arrangements that also include the purchase of electricity for a fixed price. The cost allocated to emissions allowances and credits under such arrangements is based on observable market prices. Inventories are carried at the lower of cost and net realizable value. Assets Held for Sale The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, net of selling costs and any losses are recognized in net income. Gains related to the expected sale of these assets are not recognized until the transaction closes. Once an asset is classified as held for sale, depreciation expense is no longer recorded. Plant, Property and Equipment Natural Gas Pipelines Plant, property and equipment for natural gas pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from 0.75 per cent to 6.67 per cent and metering and other plant equipment are depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in Plant, property and equipment with a corresponding credit recognized in Allowance for funds used during construction in the Consolidated statement of income. The equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines. Natural gas pipelines' linepack and natural gas storage base gas are valued at cost and are maintained to ensure adequate pressure exists to transport natural gas through pipelines and deliver natural gas held in storage. Linepack and base gas are not depreciated. When rate-regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation with no amount recorded to net income. Costs incurred to remove plant, property and equipment from service, net of any salvage proceeds, are also recorded in accumulated depreciation. Other The Company participates as a working interest partner in the development of certain Marcellus and Utica acreage. The working interest allows the Company to invest in drilling activities in addition to receiving a royalty interest in well production. The Company uses the successful efforts method of accounting for natural gas and crude oil resulting from its portion of drilling activities. Capitalized well costs are depleted based on the units of production method. Power and Energy Solutions Plant, property and equipment for Power and Energy Solutions assets are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. Natural gas storage base gas, which is valued at original cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver gas held in storage. Base gas is not depreciated. Corporate Corporate plant, property and equipment is recorded at cost and depreciated on a straight-line basis over its estimated useful life at average annual rates ranging from four per cent to 20 per cent. Capital Projects in Development The Company capitalizes project costs once advancement of the project to construction stage is probable or costs are otherwise likely to be recoverable. The Company capitalizes interest costs for non-regulated projects in development and AFUDC for regulated projects in development. Capital projects in development are included in Other long-term assets on the Consolidated balance sheet. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to plant, property and equipment under construction. Leases The Company determines if a contract contains a lease at inception of a contract by using judgment in assessing the following aspects: 1) the contract specifies an identified asset which is physically distinct or, if not physically distinct, represents substantially all of the capacity of the asset; 2) the contract provides the customer with the right to obtain substantially all of the economic benefits from the use of the asset and 3) the customer has the right to direct how and for what purpose the identified asset is used throughout the period of the contract. If the contract is determined to contain a lease, further judgment is required to identify separate lease components of the arrangement by assessing whether the lessee can benefit from the right of use either on its own or together with other resources that are readily available to the lessee, as well as if the right of use is neither highly dependent on, nor highly interrelated, with the other rights to use the underlying assets in the contract. The Company considers non-lease components as distinct elements of a contract that are not related to the use of the leased asset. A good or service that is provided to a customer is distinct if: 1) the customer can benefit from the good or service either on its own or together with other resources that are readily available to the customer and 2) the entity’s promise to transfer the good or service to the customer is separately identifiable from other promises in the contract. The Company applies the practical expedient to not separate lease and non-lease components for all lessee contracts and facilities for which the Company is the lessor in an operating lease. Lessee Accounting Policy Operating leases are recognized as right-of-use (ROU) assets and included in Plant, property and equipment while corresponding liabilities are included in Accounts payable and other and Other long-term liabilities on the Consolidated balance sheet. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at the commencement date of the lease agreement. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. As the Company's lease contracts do not provide an implicit interest rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Operating lease expense is recognized on a straight-line basis over the lease term and included in Plant operating costs and other in the Consolidated statement of income. The Company applies the practical expedient to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption. Lessor Accounting Policy The Company provides transportation and other services on certain assets to customers according to long-term service agreements through sales-type and operating leases. In a sales-type lease, the Company measures the total consideration within the contract at lease commencement. When a lease arrangement contains more than one lease and/or non-lease component, a portion of the contract consideration is allocated to each component based on the stand-alone selling price for each distinct service. The Company applies judgment to determine reasonable estimates of the expected future cost of satisfying the performance obligations of each service. The payments associated with lease components are apportioned between a reduction in the lease receivable and sales-type lease income. At lease commencement, the Company recognizes a net investment in lease represented by the present value of both the future lease payments and the estimated residual value of the leased asset. The plant, property and equipment of the leased asset is derecognized, with related gains/losses, if any, recognized in the Consolidated statement of income. Sales-type lease income is determined using the rate implicit in the lease and is recorded in Revenues. The Company is the lessor within certain other contracts, including PPAs, that are accounted for as operating leases. In an operating lease, the leased asset remains capitalized in Plant, property and equipment on the Consolidated balance sheet and is depreciated over its useful life, while lease payments are recognized as revenue over the term of the lease on a straight-line basis. Variable lease payments are recognized as income in the period in which they occur. Impairment of Long-Lived Assets The Company reviews long-lived assets such as plant, property and equipment and capital projects in development for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows for an asset within plant, property and equipment, or the estimated selling price of any long-lived asset is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the asset. Impairment of Equity Method Investments The Company reviews equity method investments for impairment when an event or change in circumstances has a significant adverse effect on the investment's fair value. Where the Company concludes an investment's fair value is below its carrying value, the Company then determines whether the impairment is other-than-temporary, and if so, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the investment, not exceeding the carrying value of the investment. Acquisitions and Goodwill The Company accounts for business combinations using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair values at the date of acquisition. The excess of the fair value of the consideration transferred over the estimated fair value of the net assets acquired is classified as goodwill. Goodwill is not amortized and is tested for impairment on an annual basis, or more frequently if events or changes in circumstances indicate that it might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company can initially assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. The factors the Company considers include, but are not limited to, macroeconomic conditions, industry and market considerations, current valuation multiples and discount rates, cost factors, historical and forecasted financial results and events specific to that reporting unit. If the Company concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the Company will then perform a quantitative goodwill impairment test. The Company can elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Company compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. The fair value of a reporting unit is determined by using a discounted cash flow analysis which requires the use of assumptions that may include, but are not limited to, revenue and capital expenditure projections, valuation multiples and discount rates. The Company has elected to allocate goodwill impairment charges first to goodwill that is non-deductible for income tax purposes, with any remaining charge allocated to tax-deductible goodwill. When a portion of a reporting unit that constitutes a business is disposed, goodwill associated with that business is included in the carrying amount of the business in determining the gain or loss on disposal. The amount of goodwill disposed is determined based on the relative fair values of the business to be disposed and the portion of the reporting unit that will be retained. A goodwill impairment test will be completed for both the goodwill disposed and the portion of the goodwill that will be retained. Non-Controlling Interests Non-controlling interests (NCI) represent third-party ownership interests in certain consolidated subsidiaries of the Company. Partial dispositions which result in a change in the Company's ownership interest, but do not result in a change in control, of a subsidiary that constitutes a business are accounted for as equity transactions. No gain or loss is recognized in earnings. At the time of partial disposition, NCI is recorded as the third party's ownership interest in the Company's carrying value of the net assets of the subsidiary. Any difference between the amount by which the NCI is adjusted and the fair value of the consideration paid or received is recognized in Additional paid-in capital and/or Retained earnings (Accumulated deficit). Loans and Receivables Loans receivable from affiliates and accounts receivable are measured at amortized cost. Impairment of Financial Assets The Company reviews financial assets, inclusive of net investment in leases and certain contract assets, carried at amortized cost for impairment using the lifetime expected loss of the financial asset at initial recognition and throughout the life of the financial asset. An expected credit loss (ECL) is calculated using a model and methodology based on assumptions and judgment considering historical data, current counterparty information as well as reasonable and supportable forecasts of future economic conditions. The ECL is recognized in Plant operating costs and other in the Consolidated statement of income, and is presented on the Consolidated balance sheet as a reduction to the carrying value of the related financial asset. Restricted Investments The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are classified as available for sale and are recorded at fair value on the Consolidated balance sheet. As a result of the CER’s Land Matters Consultation Initiative (LMCI), TC Energy is required to collect funds to cover estimated future pipeline abandonment costs for larger CER-regulated Canadian pipelines. Funds collected are placed in trusts that hold and invest the funds and are accounted for as restricted investments (LMCI restricted investments). LMCI restricted investments may only be used to fund the abandonment of the CER-regulated pipeline facilities, therefore, a corresponding regulatory liability is recorded on the Consolidated balance sheet. The Company also has other restricted investments that have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. Income Taxes The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in net income in the period in which they occur, except for changes in balances related to regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the regulator. Deferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet. The Company’s exposure to uncertain tax positions is evaluated and a provision is made where it is more likely than not that this exposure will materialize. Canadian income taxes are not provided for on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Any interest and/or penalty incurred related to income tax is reflected in Income tax expense. Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Plant operating costs and other in the Consolidated statement of income. In determining the fair value of ARO, the following assumptions are used: • the expected retirement date • the scope and cost of abandonment and reclamation activities that are required • appropriate inflation and discount rates. The Company's AROs are substantially related to its power generation facilities. The scope and timing of asset retirements related to the Company's natural gas pipelines and storage facilities are indeterminable because the Company intends to operate them as long as there is supply and demand. As a result, the Company has not recorded an amount for ARO related to these assets. Environmental Liabilities and

ACCOUNTING CHANGES

ACCOUNTING CHANGES	12 Months Ended
	Dec. 31, 2024
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES Changes in Accounting Policies for 2024 Segment Reporting In November 2023, the Financial Accounting Standards Board (FASB) issued new guidance to improve disclosures about a public entity's reportable segments and address requests from investors for additional, more detailed information about a reportable segment's expenses. The guidance was effective for annual periods beginning January 1, 2024 and interim periods beginning January 1, 2025. The Company adopted the guidance effective January 1, 2024. Refer to Note 5, Segmented information. Leases In March 2023, the FASB issued new guidance that clarified the accounting for leasehold improvements associated with common control leases. This new guidance was effective January 1, 2024 and adoption did not have a material impact on the Company's consolidated financial statements. Future Accounting Changes Income Taxes In December 2023, the FASB issued new guidance to enhance the transparency and decision usefulness of income tax disclosures through improvements to the rate reconciliation and income taxes paid information. The guidance also includes certain other amendments to improve the effectiveness of income tax disclosures. This new guidance is effective for annual periods beginning January 1, 2025. The guidance is applied prospectively with retrospective application permitted. Early adoption is permitted for annual financial statements not yet issued. The Company intends to adopt the guidance prospectively and does not intend to early adopt the guidance. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements, but does not expect the guidance to have a material impact on the Company's financial position or results of operations. Disaggregation of Income Statement Expenses

DISCONTINUED OPERATIONS

DISCONTINUED OPERATIONS	12 Months Ended
	Dec. 31, 2024
Discontinued Operations and Disposal Groups [Abstract]
DISCONTINUED OPERATIONS	DISCONTINUED OPERATIONS Spinoff of Liquids Pipelines Business Agreements Pursuant to the October 1, 2024 Spinoff Transaction described in Note 1, Description of TC Energy's business, TC Energy and South Bow have executed a series of agreements to outline the parameters and guidelines that govern their ongoing relationship. A Transition Services Agreement has been established to specify certain services that TC Energy will provide to South Bow for a period of up to two years. These services primarily include access to, and support of, systems that South Bow will continue to use until it has fully implemented new systems to support its business processes and warehouse management services. A Tax Matters Agreement was executed to govern TC Energy and South Bow's tax rights and obligations after the Spinoff Transaction. The agreement imposes certain restrictions on both TC Energy and South Bow in order to preserve the tax-free status of the spinoff. In the event the Spinoff Transaction is not tax-free, the agreement allocates tax liabilities by generally assigning responsibility to either TC Energy or South Bow to the extent that the failure to qualify is attributable to actions, events or transactions, or a breach of the representations or covenants made by that entity. A Separation Agreement was established to specify the separation of assets and liabilities between TC Energy and South Bow. The agreement states, among other things, that TC Energy will indemnify South Bow for 86 per cent of total net liabilities and costs arising from the Milepost 14 incident that occurred on the Keystone Pipeline System in December 2022 and the existing variable toll disputes on the Keystone Pipeline System (excluding any future impacts with respect to the variable toll after October 1, 2024), subject to a maximum liability to South Bow of $30 million, in aggregate, for those two matters. At December 31, 2023, the Company accrued a life-to-date environmental liability for the Milepost 14 incident of $794 million, before expected insurance recoveries and not including potential fines and penalties which were indeterminable. Prior to the Spinoff Transaction, for the nine months ended September 30, 2024, amounts paid for the environmental remediation liability were $92 million (twelve months ended December 31, 2023 – $676 million). For the year ended December 31, 2024, the Company received $99 million (2023 – $575 million) from its insurance policies related to the costs for environmental remediation. In addition, the Company also received insurance proceeds of $36 million that were collected from the Company’s wholly-owned captive insurance subsidiary. As part of the Separation Agreement, all future insurance recoveries will remain with TC Energy. For the year ended December 31, 2024, the Company recorded a pre-tax expense of $37 million for its current estimate of potential incremental costs related to the Milepost 14 incident. This amount represents TC Energy’s 86 per cent share pursuant to the indemnity provisions in the Separation Agreement. Amounts accrued for these matters are recorded as current assets and liabilities from discontinued operations. Due to the inherent uncertainties of the final amounts to be settled under these indemnities, any amounts that may ultimately be payable in respect of these net liabilities to South Bow could differ materially from those reported at December 31, 2024. Separation Costs Liquids Pipelines business separation costs primarily include internal costs related to separation activities, legal, income tax, audit and other consulting fees, insurance provisions and net financial charges related to debt issued and held in escrow. For the years ended December 31, 2024 and 2023, Liquids Pipelines business separation costs of $197 million ($167 million after tax) and $40 million ($34 million after tax), respectively, were included in Net income (loss) from discontinued operations, net of tax in the Consolidated statement of income. Pensions As part of the Spinoff Transaction, certain TC Energy employees became employees of South Bow. Prior to the Spinoff Transaction, these employees in Canada and the U.S. participated in DB Plans, DC Plans and savings plans, as applicable. Effective October 1, 2024, the benefit obligations under the DB Plans in respect of the employees moving from TC Energy to South Bow were transferred to South Bow. An asset transfer application related to the Canadian DB Plan will be prepared in early 2025 outlining the proposed transfer of assets from TC Energy to South Bow. The Canadian DB Plan's assets to be transferred to South Bow are subject to regulatory approval and will be transferred when approval is received. As at December 31, 2024, these assets remain in the TC Energy DB Plan trust and have been reflected as Long-term assets of discontinued operations and a corresponding obligation to South Bow has been reflected as Long-term liabilities of discontinued operations on the Consolidated balance sheet. The assets related to the U.S. DB Plan were fully transferred to South Bow as at December 31, 2024. South Bow Debt On August 28, 2024, South Bow Canadian Infrastructure Holdings Ltd. and 6297782 LLC, two wholly-owned subsidiaries of the Company at the time, completed an offering of approximately $7.9 billion Canadian-dollar equivalent of senior unsecured notes and junior subordinated notes. Approximately $6.2 billion Canadian-dollar equivalent of the net proceeds was placed in escrow pending the completion of the Spinoff Transaction on October 1, 2024 and US$1.3 billion of senior unsecured notes were used to repay a TransCanada PipeLines Limited (TCPL) term loan. Upon completion of the Spinoff Transaction, the escrowed funds were released to South Bow and used to repay indebtedness owed by South Bow and its subsidiaries to TC Energy and its subsidiaries. Presentation of Discontinued Operations Upon completion of the Spinoff Transaction, the Liquids Pipelines business was accounted for as discontinued operations. The Company's presentation of discontinued operations includes revenues and expenses directly attributable to the Liquids Pipelines business. As such, the results of discontinued operations excludes shared costs related to TC Energy’s corporate services and governance functions that had provided support, and whose costs had been historically allocated, to the Liquids Pipelines segment. Depreciation expense related to Corporate shared assets has also been excluded from the results of discontinued operations. The Company has elected to allocate a portion of interest expense incurred at the corporate level to discontinued operations. Prior year amounts have been reclassified to present the Liquids Pipelines business as discontinued operations. Income from Discontinued Operations year ended December 31 (millions of Canadian $) 2024 ¹ 2023 2022 Revenues 2,217 2,667 2,668 Income (Loss) from Equity Investments 50 67 55 Operating and Other Expenses Plant operating costs and other 806 814 704 Commodity purchases resold 387 437 512 Property taxes 84 116 121 Depreciation and amortization 253 332 322 Asset impairment charge and other 21 (4) (118) 1,551 1,695 1,541 Segmented Earnings (Losses) from Discontinued Operations 716 1,039 1,182 Financial Charges Interest expense 218 297 288 Interest income and other (21) 30 (6) 197 327 282 Income (Loss) from Discontinued Operations before Income Taxes 519 712 900 Income tax expense (recovery) 124 100 267 Net Income (Loss) from Discontinued Operations, Net of Tax 395 612 633 1 Represents nine months of Liquids Pipelines earnings in 2024 compared to a full year of Liquids Pipelines earnings in 2023 and 2022. Assets and Liabilities of Discontinued Operations at December 31 (millions of Canadian $) 2024 2023 ASSETS Current Assets Accounts receivable — 1,782 Inventories — 211 Other current assets 235 1,084 235 3,077 Plant, Property and Equipment — 11,118 Equity Investments — 1,074 Other Long-Term Assets 136 241 371 15,510 LIABILITIES Current Liabilities Accounts payable and other 170 2,682 170 2,682 Other Long-Term Liabilities 110 127 Deferred Income Tax Liabilities — 1,153 280 3,962 The Spinoff Transaction resulted in derecognition of the net assets of the Liquids Pipelines segment in the amount of Cash Flows from Discontinued Operations year ended December 31 (millions of Canadian $) 2024 2023 2022 Net cash provided by operations 670 1,026 709 Net cash (used in) provided by investing activities (89) 87 502

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION The Company’s chief operating decision maker is the President and Chief Executive Officer. The chief operating decision maker uses segmented earnings (losses) to assess the performance of the business segments, assist with capital investment decisions and benchmark to TC Energy’s competitors. Information regarding the Company's business segments is as follows: year ended December 31, 2024 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 5,600 6,339 870 954 8 13,771 Intersegment revenues 2 — 99 — 49 (148) — 5,600 6,438 870 1,003 (140) 13,771 Income (loss) from equity investments 34 341 283 900 — 1,558 Operating costs 2 (2,246) (2,381) (132) (700) 9 3 (5,450) Depreciation and amortization (1,382) (955) (92) (101) (5) 3 (2,535) Other segment items 4 10 610 — — — 620 Segmented Earnings (Losses) 2,016 4,053 929 1,102 (136) 7,964 Interest expense (3,019) Allowance for funds used during construction 784 Foreign exchange gains (losses), net (147) Interest income and other 324 Income (Loss) from Continuing Operations before Income Taxes 5,906 Income tax (expense) recovery from continuing operations (922) Net Income (Loss) from Continuing Operations 4,984 Net Income (Loss) from Discontinued Operations, Net of Tax 395 Net Income (Loss) 5,379 Net (income) loss attributable to non-controlling interests (681) Net Income (Loss) Attributable to Controlling Interests 4,698 Preferred share dividends (104) Net Income (Loss) Attributable to Common Shares 4,594 Capital Spending 5 Capital expenditures 1,273 2,568 2,228 62 50 6,181 Capital projects in development — 5 — 45 — 50 Contributions to equity investments 6 827 2 — 717 — 1,546 2,100 2,575 2,228 824 50 7,777 Discontinued operations 127 7,904 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Includes shared costs and depreciation previously allocated to the Liquids Pipelines segment. Refer to Note 4, Discontinued operations, for additional information. 4 Other segment items include a Net gain (loss) on sale of assets. 5 Included in Investing activities in the Consolidated statement of cash flows. 6 Contributions to equity investments in the Canadian Natural Gas Pipelines segment of $3.1 billion are offset by the equivalent amount in Other distributions from equity investments, although they are reported on a gross basis in the Company’s Consolidated statement of cash flows. Refer to Note 7, Coastal GasLink, for additional information. year ended December 31, 2023 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 5,173 6,229 846 1,019 — 13,267 Intersegment revenues 2 — 101 — 22 (123) — 5,173 6,330 846 1,041 (123) 13,267 Income (loss) from equity investments 220 324 78 688 — 1,310 Impairment of equity investment (2,100) — — — — (2,100) Operating costs 2 (2,058) (2,189) (39) (633) (15) 3 (4,934) Depreciation and amortization (1,325) (934) (89) (92) (6) 3 (2,446) Segmented Earnings (Losses) (90) 3,531 796 1,004 (144) 5,097 Interest expense (2,966) Allowance for funds used during construction 575 Foreign exchange gains (losses), net 320 Interest income and other 272 Income (Loss) from Continuing Operations before Income Taxes 3,298 Income tax (expense) recovery from continuing operations (842) Net Income (Loss) from Continuing Operations 2,456 Net income (loss) from Discontinued Operations, Net of Tax 612 Net Income (Loss) 3,068 Net Income (loss) attributable to non-controlling interests (146) Net Income (Loss) Attributable to Controlling Interests 2,922 Preferred share dividends (93) Net Income (Loss) Attributable to Common Shares 2,829 Capital Spending 4 Capital expenditures 2,953 2,536 2,292 144 33 7,958 Capital projects in development — — — 142 — 142 Contributions to equity investments 3,231 124 — 794 — 4,149 6,184 2,660 2,292 1,080 33 12,249 Discontinued operations 49 12,298 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Includes shared costs and depreciation previously allocated to the Liquids Pipelines segment. Refer to Note 4, Discontinued operations, for additional information. 4 Included in Investing activities in the Consolidated statement of cash flows. year ended December 31, 2022 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 4,764 5,933 688 924 — 12,309 Intersegment revenues 2 — 132 — 12 (144) — 4,764 6,065 688 936 (144) 12,309 Income (loss) from equity investments 18 292 122 539 28 3 999 Impairment of equity investment (3,048) — — — — (3,048) Operating costs 2 (1,976) (2,282) (221) (570) 72 4 (4,977) Depreciation and amortization (1,198) (887) (98) (72) (7) 4 (2,262) Other segment items 5 — (571) — — — (571) Segmented Earnings (Losses) (1,440) 2,617 491 833 (51) 2,450 Interest expense (2,300) Allowance for funds used during construction 369 Foreign exchange gains (losses), net 3 (185) Interest income and other 140 Income (Loss) from Continuing Operations before Income Taxes 474 Income tax (expense) recovery from continuing operations (322) Net Income (Loss) from Continuing Operations 152 Net Income (Loss) from Discontinued Operations, Net of Tax 633 Net Income (Loss) 785 Net (income) loss attributable to non-controlling interests (37) Net Income (Loss) Attributable to Controlling Interests 748 Preferred share dividends (107) Net Income (Loss) Attributable to Common Shares 641 Capital Spending 6 Capital expenditures 3,274 2,137 1,027 93 41 6,572 Capital projects in development — — — 49 — 49 Contributions to equity investments 7 1,445 — — 752 — 2,197 4,719 2,137 1,027 894 41 8,818 Discontinued operations 143 8,961 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income (loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains and losses on the peso-denominated loans from affiliates which are fully offset in Foreign exchange gains (losses), net by the corresponding foreign exchange losses and gains on the affiliate receivable balance until March 15, 2022, when it was fully repaid upon maturity. Refer to Note 12, Loans receivable from affiliates, for additional information. 4 Includes shared costs and depreciation previously allocated to the Liquids Pipelines segment. Refer to Note 4, Discontinued operations, for additional information. 5 Other segment items includes a goodwill impairment charge. Refer to Note 14, Goodwill, for additional information. 6 Included in Investing activities in the Consolidated statement of cash flows. 7 Contributions to equity investments in the Corporate segment of $1.2 billion are offset by the equivalent amount in Other distributions from equity investments, although they are reported on a gross basis in the Company’s Consolidated statement of cash flows. Refer to Note 12, Loans receivable from affiliates, for additional information. at December 31 2024 2023 (millions of Canadian $) Total Assets by Segment Canadian Natural Gas Pipelines 31,167 29,782 U.S. Natural Gas Pipelines 56,304 50,499 Mexico Natural Gas Pipelines 15,995 12,003 Power and Energy Solutions 10,217 9,525 Corporate 4,189 7,715 117,872 109,524 Discontinued Operations 371 15,510 118,243 125,034 Geographic Information year ended December 31 2024 2023 2022 (millions of Canadian $) Revenues Canada – domestic 5,579 5,337 4,920 Canada – export 953 821 765 United States 6,369 6,263 5,936 Mexico 870 846 688 13,771 13,267 12,309 at December 31 2024 2023 (millions of Canadian $) Plant, Property and Equipment Canada 26,354 26,434 United States 40,580 35,640 Mexico 10,567 7,377 77,501 69,451

REVENUES

REVENUES	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
REVENUES	REVENUES Disaggregation of Revenues year ended December 31, 2024 Canadian U.S. Mexico Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 5,586 5,382 438 — 11,406 Power generation — — — 266 266 Natural gas storage and other 1,2 14 869 124 383 1,390 5,600 6,251 562 649 13,062 Other revenues 3 — 88 — 305 393 Sales-type lease income 4 — — 308 — 308 Corporate revenues 5 — — — — 8 5,600 6,339 870 954 13,771 1 Includes $14 million of fee revenues from an affiliate related to the development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy. 2 Includes $98 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service Transportadora de Gas Natural de La Huasteca (TGNH) pipelines. Refer to Note 10, Leases, for additional information. 3 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information. 4 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. 5 Includes $7 million of revenues generated from the Transition Services Agreement with South Bow. Refer to Note 4, Discontinued operations, for additional information. year ended December 31, 2023 Canadian U.S. Mexico Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 5,141 5,107 442 — 10,690 Power generation — — — 427 427 Natural gas storage and other 1,2 32 874 125 363 1,394 5,173 5,981 567 790 12,511 Other revenues 3 — 248 — 229 477 Sales-type lease income 4 — — 279 — 279 5,173 6,229 846 1,019 13,267 1 Includes $31 million of fee revenues from an affiliate related to the development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy. 2 Includes $97 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. 3 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information. 4 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. year ended December 31, 2022 Canadian U.S. Mexico Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,696 4,621 507 — 9,824 Power generation — — — 490 490 Natural gas storage and other 1,2 68 1,298 54 391 1,811 4,764 5,919 561 881 12,125 Other revenues 3,4 — 14 — 43 57 Sales-type lease income 5 — — 127 — 127 4,764 5,933 688 924 12,309 1 Includes $68 million of fee revenues from an affiliate related to the development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy. 2 Includes $37 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. 3 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information. 4 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from H.R. 1, the Tax Cuts and Jobs Act (U.S. Tax Reform). Refer to Note 13, Rate-regulated businesses. 5 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. Contract Balances at December 31 2024 2023 Affected line item on the (millions of Canadian $) Receivables from contracts with customers 1,452 1,388 Accounts receivable Contract assets (Note 8) 165 151 Other current assets Long-term contract assets (Note 15) 608 457 Other long-term assets Contract liabilities 1 (Note 17) 30 47 Accounts payable and other Long-term contract liabilities 1 — 2 Other long-term liabilities 1 During the year ended December 31, 2024, $41 million (2023 – $47 million) of revenues were recognized that were included in contract liabilities and long-term contract liabilities at the beginning of the year. Contract assets and long-term contract assets primarily relate to the Company’s right to revenues for services completed but not invoiced at the reporting date on long-term committed capacity natural gas pipelines contracts. The change in contract assets is primarily related to the transfer to Accounts receivable when these rights become unconditional and the customer is invoiced, as well as the recognition of additional revenues that remain to be invoiced. Contract liabilities and long-term contract liabilities primarily represent unearned revenue for contracted services. Under the terms of the consolidated Transportation Service Agreement (TSA), the contract liability relating to current and future in-service pipelines of the Company's Mexico-based subsidiary, Transportadora de Gas Natural de la Huasteca (TGNH), is netted against certain contract asset balances. The resulting net contract liability is settled against Net investment in leases on the Consolidated balance sheet when the pipeline enters into service. Future Revenues from Remaining Performance Obligations As at December 31, 2024, future revenues from long-term pipeline capacity arrangements and transportation as well as natural gas storage and other contracts extending through 2055 are approximately $29.1 billion, of which approximately $6.4 billion is expected to be recognized in 2025. A significant portion of the Company's revenues are not included in the future revenue disclosure above, as the Company has elected the following disclosure exemptions: • revenues related to flow-through operating costs, or other similar variable consideration, that are recognized at the amount for which the Company has the right to invoice the customer • variable consideration relating to interruptible transportation service revenues and power generation revenues where there is uncertainty in estimating the amount of future revenue • revenues for periods extending beyond the current rate settlement term for the Company’s U.S. natural gas pipelines' regulated transportation and storage contracts where the maximum tariff rate is to be collected from shippers •

COASTAL GASLINK

COASTAL GASLINK	12 Months Ended
	Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
COASTAL GASLINK	COASTAL GASLINK On November 18, 2024, Coastal GasLink Pipeline Limited Partnership (Coastal GasLink LP) executed a commercial agreement with LNG Canada (LNGC) and each of the five LNGC participants (LNGC Participants) that declared commercial in-service for the pipeline, allowing for the collection of tolls from customers retroactive to October 1, 2024. The agreement also includes a one-time payment of $199 million from LNGC Participants to TC Energy in recognition of the completion of certain work and the final settlement of costs. The payment is to be made by LNGC Participants upon the earlier of three months after the declared in-service of the LNGC facility, or December 15, 2025. The payment, which accrues in full to TC Energy in accordance with the contractual terms between the Coastal GasLink LP partners, has been accounted for as an in-substance equity distribution from Coastal GasLink LP and reflected in Accounts receivable and Equity investments on the Company's Consolidated balance sheet at December 31, 2024. Subordinated Loan Agreement TC Energy has a subordinated loan agreement with Coastal GasLink LP under which the Company advances non-revolving interest-bearing loans subject to floating market-based rates to Coastal GasLink LP to fund capital costs to complete the Coastal GasLink pipeline. At December 31, 2023, this loan had a committed capacity of $3,375 million. Coastal GasLink LP partners, including TC Energy, were contractually obligated to contribute equity to Coastal GasLink LP to ultimately fund the settlement of amounts outstanding under the subordinated loan agreement. Because of the expectation that the Company would predominantly fund the settlement of the amounts outstanding, amounts drawn under the subordinated loan agreement have been accounted for as in-substance equity contributions and are presented as Contributions to equity investments in the Company’s Consolidated statement of cash flows. Repayments of amounts owed by Coastal GasLink LP to the Company are accounted for as in-substance equity distributions and are presented in Other distributions from equity investments in the Company's Consolidated statement of cash flows. During the year ended December 31, 2024, draws of $627 million (2023 - $2,520 million) were made by Coastal GasLink LP under the subordinated loan agreement. On December 17, 2024, following the declared commercial in-service of the pipeline, Coastal GasLink LP repaid the $3,147 million balance owing to TC Energy under the subordinated loan agreement. The Company's share of equity contributions required to fund Coastal GasLink LP's repayment of the outstanding loan balance amounted to $3,137 million. This repayment reduced the Company's funding commitment under the subordinated loan agreement to $228 million at December 31, 2024. At December 31, 2024, $228 million (December 31, 2023 - $855 million) in unused committed capacity remains available for use by Coastal GasLink LP. At December 31, 2024, the balance of loans outstanding under the subordinated loan agreement was nil (December 31, 2023 - $2,520 million). Subordinated Demand Revolving Credit Facility Agreement The Company has a subordinated demand revolving credit facility agreement with Coastal GasLink LP to provide additional short-term liquidity and funding flexibility to projects under construction. Facilities available through this agreement bear interest at floating market-based rates and have a combined capacity of $120 million (December 31, 2023 - $100 million) with no outstanding balances at December 31, 2024 and 2023. Impairment of Equity Investment in Coastal GasLink LP In February 2023, Coastal GasLink LP announced an increase in the revised capital cost of the Coastal GasLink pipeline. As noted above, the expectation was that equity contributions to fund the increased capital cost would be predominantly funded by TC Energy. For the year ended December 31, 2022 until the quarter ended September 30, 2023, the expectation that additional equity contributions under the subordinated loan agreement would be predominantly funded by TC Energy was an indication of significant adverse impact on the estimated fair value of the Company’s investment in Coastal GasLink LP. The Company completed valuation assessments in each of these periods and concluded that the fair value of its investment in Coastal GasLink LP was below its carrying value in each period assessed, reflecting other-than-temporary impairments. As a result, the Company recorded cumulative pre-tax impairment charges of $5,148 million, or $4,586 million after tax, between December 31, 2022 and September 30, 2023. No further indication of other-than-temporary impairments of the Company's investment in Coastal GasLink LP have since been identified and no further impairment charges have been recorded. At December 31, 2024, the carrying value of the Company's investment in Coastal GasLink LP was $1,006 million (2023 – $294 million). (millions of Canadian $) Ownership Interest at December 31, 2024 Income (Loss) from Equity Investments Equity year ended December 31 at December 31 2024 2023 2022 2024 2023 Canadian Natural Gas Pipelines TQM 1 50 % 17 17 17 160 166 Coastal GasLink 1,2 35 % 17 203 1 1,006 294 U.S. Natural Gas Pipelines Northern Border 50 % 130 101 92 647 599 Millennium 47.5 % 95 109 103 (21) 476 Iroquois 50 % 100 98 77 221 227 Other Various 16 16 20 135 120 Mexico Natural Gas Pipelines Sur de Texas 60 % 283 78 150 1,403 1,078 Power and Energy Solutions Bruce Power 1 48.3 % 900 690 537 7,043 6,242 Other Various — (2) 2 42 38 1,558 1,310 999 10,636 9,240 1 Classified as a VIE. Refer to Note 32, Variable interest entities, for additional information. 2 Refer to Note 7, Coastal GasLink, for additional information. Coastal GasLink Incentive Payment The Coastal GasLink project reached mechanical completion in November 2023 and was ready to deliver commissioning gas to the LNGC facility by the end of 2023. These milestones entitled Coastal GasLink LP to receive a $200 million incentive payment from LNGC, which was recorded as Accounts receivable on the Consolidated balance sheet and Income (loss) from equity investments in the Consolidated statement of income as at and for the year ended December 31, 2023. The incentive payment was settled through a cash distribution in February 2024. Distributions and Contributions Distributions received from equity investments and contributions made to equity investments for the years ended December 31, 2024, 2023 and 2022 were as follows: year ended December 31 2024 2023 2022 (millions of Canadian $) Distributions Distributions received from operating activities of equity investments 1,607 1,158 955 Coastal GasLink LP subordinated loan repayment 1,2 3,147 — — Sur de Texas debt repayments 2,3 — — 2,404 Other 2 539 23 228 5,293 1,181 3,587 Contributions 2 Contributions to Coastal GasLink LP 1 3,964 3,231 1,414 Sur de Texas debt financing 3 — — 1,199 Contributions made to other equity investments 719 918 783 4,683 4,149 3,396 1 In December 2024, TC Energy made an equity contribution of $3,137 million to Coastal GasLink LP, which used the funds to repay the balance owing to TC Energy under the subordinated loan agreement. The contribution and repayment were included in Investing activities in the Consolidated statement of cash flows. Refer to Note 7, Coastal GasLink, for additional information. 2 Included in Investing activities in the Consolidated statement of cash flows. 3 Represents TC Energy's proportionate share of the Sur de Texas debt financing requirements and subsequent repayments. Refer to Note 12, Loans receivable from affiliates, for additional information. Summarized Financial Information of Equity Investments year ended December 31 2024 2023 2022 (millions of Canadian $) Income Revenues 6,962 6,197 5,681 Operating and other expenses (3,783) (3,343) (3,290) Net income 3,026 2,457 2,031 Net income attributable to TC Energy 1,558 1,310 999 at December 31 2024 2023 (millions of Canadian $) Balance Sheet Current assets 3,959 3,279 Non-current assets 44,835 41,270 Current liabilities (2,111) (2,403) Non-current liabilities (21,729) (21,894)

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2024
Other Assets [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS at December 31 2024 2023 (millions of Canadian $) Fair value of derivative contracts (Note 28) 347 589 Current portion of net investment in leases (Note 10) 333 306 Contract assets (Note 6) 165 151 Cash provided as collateral 128 28 Regulatory assets (Note 13) 123 76 Prepaid expenses 86 87 Emissions credits 75 94 Other 82 88 1,339 1,419

PLANT, PROPERTY AND EQUIPMENT

PLANT, PROPERTY AND EQUIPMENT	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
PLANT, PROPERTY AND EQUIPMENT	PLANT, PROPERTY AND EQUIPMENT at December 31 2024 2023 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 20,497 7,413 13,084 20,232 6,855 13,377 Compression 7,146 2,497 4,649 6,603 2,349 4,254 Metering and other 1,668 883 785 1,589 830 759 29,311 10,793 18,518 28,424 10,034 18,390 Under construction 503 — 503 787 — 787 29,814 10,793 19,021 29,211 10,034 19,177 Canadian Mainline Pipeline 10,907 8,165 2,742 10,729 7,996 2,733 Compression 4,540 3,448 1,092 4,437 3,354 1,083 Metering and other 749 331 418 729 308 421 16,196 11,944 4,252 15,895 11,658 4,237 Under construction 163 — 163 147 — 147 16,359 11,944 4,415 16,042 11,658 4,384 Other Canadian Natural Gas Pipelines 1 Other 2,927 1,742 1,185 2,846 1,682 1,164 Under construction 31 — 31 23 — 23 2,958 1,742 1,216 2,869 1,682 1,187 49,131 24,479 24,652 48,122 23,374 24,748 U.S. Natural Gas Pipelines Columbia Gas Pipeline 14,826 1,472 13,354 12,952 1,247 11,705 Compression 6,153 677 5,476 5,310 559 4,751 Metering and other 4,570 455 4,115 4,074 372 3,702 25,549 2,604 22,945 22,336 2,178 20,158 Under construction 891 — 891 771 — 771 26,440 2,604 23,836 23,107 2,178 20,929 ANR Pipeline 2,477 745 1,732 2,117 657 1,460 Compression 4,446 938 3,508 3,928 773 3,155 Metering and other 1,832 521 1,311 1,625 458 1,167 8,755 2,204 6,551 7,670 1,888 5,782 Under construction 853 — 853 404 — 404 9,608 2,204 7,404 8,074 1,888 6,186 at December 31 2024 2023 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Other U.S. Natural Gas Pipelines Columbia Gulf 4,127 304 3,823 3,600 256 3,344 GTN 3,405 1,467 1,938 2,992 1,295 1,697 Great Lakes 2,602 1,537 1,065 2,359 1,401 958 Other 2 1,695 628 1,067 2,071 800 1,271 11,829 3,936 7,893 11,022 3,752 7,270 Under construction 694 — 694 584 — 584 12,523 3,936 8,587 11,606 3,752 7,854 48,571 8,744 39,827 42,787 7,818 34,969 Mexico Natural Gas Pipelines 3 Pipeline 2,590 523 2,067 2,290 422 1,868 Compression 476 107 369 447 82 365 Metering and other 398 99 299 395 85 310 3,464 729 2,735 3,132 589 2,543 Under construction 7,807 — 7,807 4,823 — 4,823 11,271 729 10,542 7,955 589 7,366 Power and Energy Solutions Natural Gas Power Generation 1,273 671 602 1,239 637 602 Natural Gas Storage and Other 873 281 592 845 256 589 Renewable Power Generation 779 54 725 581 19 562 2,925 1,006 1,919 2,665 912 1,753 Under construction 56 — 56 153 — 153 2,981 1,006 1,975 2,818 912 1,906 Corporate 944 439 505 909 447 462 112,898 35,397 77,501 102,591 33,140 69,451 1 Includes Foothills, Ventures LP and Great Lakes Canada. 2 Includes North Baja, Tuscarora, Louisiana Intrastate, Crossroads, U.S. Energy Marketing and mineral rights business. On August 15, 2024, the Company completed the sale of Portland Natural Gas Transmission System (PNGTS). Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 3 During the year ended December 31, 2024, the Company derecognized nil (2023 – $407 million) of Plant, property and equipment and recorded a corresponding asset for Net investment in leases for the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
LEASES	LEASES As a Lessee The Company has operating leases for corporate offices, other various premises, equipment and land. Some leases have an option to renew for periods of one Operating lease cost was as follows: year ended December 31 (millions of Canadian $) 2024 2023 Operating lease cost 1 117 105 Sublease income (6) (4) Net operating lease cost 111 101 1 Includes short-term leases and variable lease costs. Other information related to operating leases is noted in the following tables: year ended December 31 (millions of Canadian $) 2024 2023 Cash paid for amounts included in the measurement of operating lease liabilities 74 72 ROU assets obtained in exchange for new operating lease liabilities 96 83 at December 31 2024 2023 Weighted average remaining lease term 13 years 13 years Weighted average discount rate 3.3 % 3.3 % Maturities of operating lease liabilities are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 73 71 One to two years 73 68 Two to three years 66 66 Three to four years 64 59 Four to five years 63 58 More than five years 275 224 Total operating lease payments 614 546 Imputed interest (103) (89) Operating lease liabilities 511 457 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2024 2023 Accounts payable and other (Note 17) 60 57 Other long-term liabilities (Note 18) 451 400 511 457 As at December 31, 2024, the carrying value of the ROU assets recorded under operating leases was $480 million (2023 – $435 million) and is included in Plant, property and equipment on the Consolidated balance sheet. As a Lessor Operating Leases The Grandview and Bécancour power plants in the Power and Energy Solutions segment are accounted for as operating leases. The Company has long-term PPAs for the sale of power from these assets which expire between 2026 and 2035. Some operating leases contain variable lease payments that are based on operating hours and the reimbursement of variable costs, and options to purchase the underlying asset at fair value or based on a formula considering the remaining fixed payments. Lessees have rights under some leases to terminate under certain circumstances. The fixed portion of the operating lease income recorded by the Company for the year ended December 31, 2024 was $114 million (2023 – $112 million; 2022 – $110 million). Future lease payments to be received under operating leases are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 107 111 One to two years 76 94 Two to three years 9 70 Three to four years 10 — Four to five years 10 — More than five years 55 — 267 275 At December 31, 2024, the cost and accumulated depreciation for facilities accounted for as operating leases was $697 million and $351 million, respectively (2023 – $646 million and $333 million, respectively). Sales-Type Leases The Tamazunchale, Villa de Reyes and Tula pipelines are part of a U.S. dollar-denominated take-or-pay TSA that extends through 2055 between TGNH and the Comisión Federal de Electricidad (CFE). The consolidated TSA contains a lease with multiple lease and non-lease components. The lease components within the TSA represent the capacity available to the CFE provided by the in-service pipelines within TGNH at December 31, 2024. The non-lease components represent the Company’s services with respect to operation and maintenance of the TGNH pipelines in service. The Company allocated a portion of the contract consideration to non-lease components for the provision of operating and maintenance services based on the stand-alone selling price using an expected cost plus margin approach. The remaining consideration was allocated to the lease components using the residual approach due to uncertainty surrounding the stand-alone selling price. During 2024, the Company did not enter into any new sales-type lease arrangements (2023 – $407 million). Future lease payments to be received under the existing sales-type leases are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 333 305 One to two years 333 305 Two to three years 333 305 Three to four years 333 305 Four to five years 333 305 More than five years 8,499 8,102 10,164 9,627 The following table lists the components of the aggregate net investment in leases reflected on the Company's Consolidated balance sheet: at December 31 (millions of Canadian $) 2024 2023 Net Investment in Leases Minimum lease payments 10,164 9,627 Unearned lease income (7,323) (7,006) Lease receivable 2,841 2,621 Expected credit loss provision 1 (59) (76) Present value of unguaranteed residual value 28 24 2,810 2,569 Current portion included in Other current assets (Note 8) (333) (306) 2,477 2,263 1 Includes $6 million (2023 – nil) of foreign currency translation losses. Future lease payments will increase as assets associated with sales-type leases come into service. For the year ended December 31, 2024, the Company recorded $308 million (2023 – $279 million; 2022 - $127 million) of sales-type lease income. For the year ended December 31, 2024, the Company recorded a $23 million ECL recovery (2023 – a recovery of $73 million; 2022 – an expense of $149 million) relating to net investment in leases in Plant operating costs and other. Refer to Note 28, Risk management and financial instruments, for additional information.
LEASES	LEASES As a Lessee The Company has operating leases for corporate offices, other various premises, equipment and land. Some leases have an option to renew for periods of one Operating lease cost was as follows: year ended December 31 (millions of Canadian $) 2024 2023 Operating lease cost 1 117 105 Sublease income (6) (4) Net operating lease cost 111 101 1 Includes short-term leases and variable lease costs. Other information related to operating leases is noted in the following tables: year ended December 31 (millions of Canadian $) 2024 2023 Cash paid for amounts included in the measurement of operating lease liabilities 74 72 ROU assets obtained in exchange for new operating lease liabilities 96 83 at December 31 2024 2023 Weighted average remaining lease term 13 years 13 years Weighted average discount rate 3.3 % 3.3 % Maturities of operating lease liabilities are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 73 71 One to two years 73 68 Two to three years 66 66 Three to four years 64 59 Four to five years 63 58 More than five years 275 224 Total operating lease payments 614 546 Imputed interest (103) (89) Operating lease liabilities 511 457 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2024 2023 Accounts payable and other (Note 17) 60 57 Other long-term liabilities (Note 18) 451 400 511 457 As at December 31, 2024, the carrying value of the ROU assets recorded under operating leases was $480 million (2023 – $435 million) and is included in Plant, property and equipment on the Consolidated balance sheet. As a Lessor Operating Leases The Grandview and Bécancour power plants in the Power and Energy Solutions segment are accounted for as operating leases. The Company has long-term PPAs for the sale of power from these assets which expire between 2026 and 2035. Some operating leases contain variable lease payments that are based on operating hours and the reimbursement of variable costs, and options to purchase the underlying asset at fair value or based on a formula considering the remaining fixed payments. Lessees have rights under some leases to terminate under certain circumstances. The fixed portion of the operating lease income recorded by the Company for the year ended December 31, 2024 was $114 million (2023 – $112 million; 2022 – $110 million). Future lease payments to be received under operating leases are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 107 111 One to two years 76 94 Two to three years 9 70 Three to four years 10 — Four to five years 10 — More than five years 55 — 267 275 At December 31, 2024, the cost and accumulated depreciation for facilities accounted for as operating leases was $697 million and $351 million, respectively (2023 – $646 million and $333 million, respectively). Sales-Type Leases The Tamazunchale, Villa de Reyes and Tula pipelines are part of a U.S. dollar-denominated take-or-pay TSA that extends through 2055 between TGNH and the Comisión Federal de Electricidad (CFE). The consolidated TSA contains a lease with multiple lease and non-lease components. The lease components within the TSA represent the capacity available to the CFE provided by the in-service pipelines within TGNH at December 31, 2024. The non-lease components represent the Company’s services with respect to operation and maintenance of the TGNH pipelines in service. The Company allocated a portion of the contract consideration to non-lease components for the provision of operating and maintenance services based on the stand-alone selling price using an expected cost plus margin approach. The remaining consideration was allocated to the lease components using the residual approach due to uncertainty surrounding the stand-alone selling price. During 2024, the Company did not enter into any new sales-type lease arrangements (2023 – $407 million). Future lease payments to be received under the existing sales-type leases are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 333 305 One to two years 333 305 Two to three years 333 305 Three to four years 333 305 Four to five years 333 305 More than five years 8,499 8,102 10,164 9,627 The following table lists the components of the aggregate net investment in leases reflected on the Company's Consolidated balance sheet: at December 31 (millions of Canadian $) 2024 2023 Net Investment in Leases Minimum lease payments 10,164 9,627 Unearned lease income (7,323) (7,006) Lease receivable 2,841 2,621 Expected credit loss provision 1 (59) (76) Present value of unguaranteed residual value 28 24 2,810 2,569 Current portion included in Other current assets (Note 8) (333) (306) 2,477 2,263 1 Includes $6 million (2023 – nil) of foreign currency translation losses. Future lease payments will increase as assets associated with sales-type leases come into service. For the year ended December 31, 2024, the Company recorded $308 million (2023 – $279 million; 2022 - $127 million) of sales-type lease income. For the year ended December 31, 2024, the Company recorded a $23 million ECL recovery (2023 – a recovery of $73 million; 2022 – an expense of $149 million) relating to net investment in leases in Plant operating costs and other. Refer to Note 28, Risk management and financial instruments, for additional information.
LEASES	LEASES As a Lessee The Company has operating leases for corporate offices, other various premises, equipment and land. Some leases have an option to renew for periods of one Operating lease cost was as follows: year ended December 31 (millions of Canadian $) 2024 2023 Operating lease cost 1 117 105 Sublease income (6) (4) Net operating lease cost 111 101 1 Includes short-term leases and variable lease costs. Other information related to operating leases is noted in the following tables: year ended December 31 (millions of Canadian $) 2024 2023 Cash paid for amounts included in the measurement of operating lease liabilities 74 72 ROU assets obtained in exchange for new operating lease liabilities 96 83 at December 31 2024 2023 Weighted average remaining lease term 13 years 13 years Weighted average discount rate 3.3 % 3.3 % Maturities of operating lease liabilities are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 73 71 One to two years 73 68 Two to three years 66 66 Three to four years 64 59 Four to five years 63 58 More than five years 275 224 Total operating lease payments 614 546 Imputed interest (103) (89) Operating lease liabilities 511 457 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2024 2023 Accounts payable and other (Note 17) 60 57 Other long-term liabilities (Note 18) 451 400 511 457 As at December 31, 2024, the carrying value of the ROU assets recorded under operating leases was $480 million (2023 – $435 million) and is included in Plant, property and equipment on the Consolidated balance sheet. As a Lessor Operating Leases The Grandview and Bécancour power plants in the Power and Energy Solutions segment are accounted for as operating leases. The Company has long-term PPAs for the sale of power from these assets which expire between 2026 and 2035. Some operating leases contain variable lease payments that are based on operating hours and the reimbursement of variable costs, and options to purchase the underlying asset at fair value or based on a formula considering the remaining fixed payments. Lessees have rights under some leases to terminate under certain circumstances. The fixed portion of the operating lease income recorded by the Company for the year ended December 31, 2024 was $114 million (2023 – $112 million; 2022 – $110 million). Future lease payments to be received under operating leases are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 107 111 One to two years 76 94 Two to three years 9 70 Three to four years 10 — Four to five years 10 — More than five years 55 — 267 275 At December 31, 2024, the cost and accumulated depreciation for facilities accounted for as operating leases was $697 million and $351 million, respectively (2023 – $646 million and $333 million, respectively). Sales-Type Leases The Tamazunchale, Villa de Reyes and Tula pipelines are part of a U.S. dollar-denominated take-or-pay TSA that extends through 2055 between TGNH and the Comisión Federal de Electricidad (CFE). The consolidated TSA contains a lease with multiple lease and non-lease components. The lease components within the TSA represent the capacity available to the CFE provided by the in-service pipelines within TGNH at December 31, 2024. The non-lease components represent the Company’s services with respect to operation and maintenance of the TGNH pipelines in service. The Company allocated a portion of the contract consideration to non-lease components for the provision of operating and maintenance services based on the stand-alone selling price using an expected cost plus margin approach. The remaining consideration was allocated to the lease components using the residual approach due to uncertainty surrounding the stand-alone selling price. During 2024, the Company did not enter into any new sales-type lease arrangements (2023 – $407 million). Future lease payments to be received under the existing sales-type leases are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 333 305 One to two years 333 305 Two to three years 333 305 Three to four years 333 305 Four to five years 333 305 More than five years 8,499 8,102 10,164 9,627 The following table lists the components of the aggregate net investment in leases reflected on the Company's Consolidated balance sheet: at December 31 (millions of Canadian $) 2024 2023 Net Investment in Leases Minimum lease payments 10,164 9,627 Unearned lease income (7,323) (7,006) Lease receivable 2,841 2,621 Expected credit loss provision 1 (59) (76) Present value of unguaranteed residual value 28 24 2,810 2,569 Current portion included in Other current assets (Note 8) (333) (306) 2,477 2,263 1 Includes $6 million (2023 – nil) of foreign currency translation losses. Future lease payments will increase as assets associated with sales-type leases come into service. For the year ended December 31, 2024, the Company recorded $308 million (2023 – $279 million; 2022 - $127 million) of sales-type lease income. For the year ended December 31, 2024, the Company recorded a $23 million ECL recovery (2023 – a recovery of $73 million; 2022 – an expense of $149 million) relating to net investment in leases in Plant operating costs and other. Refer to Note 28, Risk management and financial instruments, for additional information.

EQUITY INVESTMENTS

EQUITY INVESTMENTS	12 Months Ended
	Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	COASTAL GASLINK On November 18, 2024, Coastal GasLink Pipeline Limited Partnership (Coastal GasLink LP) executed a commercial agreement with LNG Canada (LNGC) and each of the five LNGC participants (LNGC Participants) that declared commercial in-service for the pipeline, allowing for the collection of tolls from customers retroactive to October 1, 2024. The agreement also includes a one-time payment of $199 million from LNGC Participants to TC Energy in recognition of the completion of certain work and the final settlement of costs. The payment is to be made by LNGC Participants upon the earlier of three months after the declared in-service of the LNGC facility, or December 15, 2025. The payment, which accrues in full to TC Energy in accordance with the contractual terms between the Coastal GasLink LP partners, has been accounted for as an in-substance equity distribution from Coastal GasLink LP and reflected in Accounts receivable and Equity investments on the Company's Consolidated balance sheet at December 31, 2024. Subordinated Loan Agreement TC Energy has a subordinated loan agreement with Coastal GasLink LP under which the Company advances non-revolving interest-bearing loans subject to floating market-based rates to Coastal GasLink LP to fund capital costs to complete the Coastal GasLink pipeline. At December 31, 2023, this loan had a committed capacity of $3,375 million. Coastal GasLink LP partners, including TC Energy, were contractually obligated to contribute equity to Coastal GasLink LP to ultimately fund the settlement of amounts outstanding under the subordinated loan agreement. Because of the expectation that the Company would predominantly fund the settlement of the amounts outstanding, amounts drawn under the subordinated loan agreement have been accounted for as in-substance equity contributions and are presented as Contributions to equity investments in the Company’s Consolidated statement of cash flows. Repayments of amounts owed by Coastal GasLink LP to the Company are accounted for as in-substance equity distributions and are presented in Other distributions from equity investments in the Company's Consolidated statement of cash flows. During the year ended December 31, 2024, draws of $627 million (2023 - $2,520 million) were made by Coastal GasLink LP under the subordinated loan agreement. On December 17, 2024, following the declared commercial in-service of the pipeline, Coastal GasLink LP repaid the $3,147 million balance owing to TC Energy under the subordinated loan agreement. The Company's share of equity contributions required to fund Coastal GasLink LP's repayment of the outstanding loan balance amounted to $3,137 million. This repayment reduced the Company's funding commitment under the subordinated loan agreement to $228 million at December 31, 2024. At December 31, 2024, $228 million (December 31, 2023 - $855 million) in unused committed capacity remains available for use by Coastal GasLink LP. At December 31, 2024, the balance of loans outstanding under the subordinated loan agreement was nil (December 31, 2023 - $2,520 million). Subordinated Demand Revolving Credit Facility Agreement The Company has a subordinated demand revolving credit facility agreement with Coastal GasLink LP to provide additional short-term liquidity and funding flexibility to projects under construction. Facilities available through this agreement bear interest at floating market-based rates and have a combined capacity of $120 million (December 31, 2023 - $100 million) with no outstanding balances at December 31, 2024 and 2023. Impairment of Equity Investment in Coastal GasLink LP In February 2023, Coastal GasLink LP announced an increase in the revised capital cost of the Coastal GasLink pipeline. As noted above, the expectation was that equity contributions to fund the increased capital cost would be predominantly funded by TC Energy. For the year ended December 31, 2022 until the quarter ended September 30, 2023, the expectation that additional equity contributions under the subordinated loan agreement would be predominantly funded by TC Energy was an indication of significant adverse impact on the estimated fair value of the Company’s investment in Coastal GasLink LP. The Company completed valuation assessments in each of these periods and concluded that the fair value of its investment in Coastal GasLink LP was below its carrying value in each period assessed, reflecting other-than-temporary impairments. As a result, the Company recorded cumulative pre-tax impairment charges of $5,148 million, or $4,586 million after tax, between December 31, 2022 and September 30, 2023. No further indication of other-than-temporary impairments of the Company's investment in Coastal GasLink LP have since been identified and no further impairment charges have been recorded. At December 31, 2024, the carrying value of the Company's investment in Coastal GasLink LP was $1,006 million (2023 – $294 million). (millions of Canadian $) Ownership Interest at December 31, 2024 Income (Loss) from Equity Investments Equity year ended December 31 at December 31 2024 2023 2022 2024 2023 Canadian Natural Gas Pipelines TQM 1 50 % 17 17 17 160 166 Coastal GasLink 1,2 35 % 17 203 1 1,006 294 U.S. Natural Gas Pipelines Northern Border 50 % 130 101 92 647 599 Millennium 47.5 % 95 109 103 (21) 476 Iroquois 50 % 100 98 77 221 227 Other Various 16 16 20 135 120 Mexico Natural Gas Pipelines Sur de Texas 60 % 283 78 150 1,403 1,078 Power and Energy Solutions Bruce Power 1 48.3 % 900 690 537 7,043 6,242 Other Various — (2) 2 42 38 1,558 1,310 999 10,636 9,240 1 Classified as a VIE. Refer to Note 32, Variable interest entities, for additional information. 2 Refer to Note 7, Coastal GasLink, for additional information. Coastal GasLink Incentive Payment The Coastal GasLink project reached mechanical completion in November 2023 and was ready to deliver commissioning gas to the LNGC facility by the end of 2023. These milestones entitled Coastal GasLink LP to receive a $200 million incentive payment from LNGC, which was recorded as Accounts receivable on the Consolidated balance sheet and Income (loss) from equity investments in the Consolidated statement of income as at and for the year ended December 31, 2023. The incentive payment was settled through a cash distribution in February 2024. Distributions and Contributions Distributions received from equity investments and contributions made to equity investments for the years ended December 31, 2024, 2023 and 2022 were as follows: year ended December 31 2024 2023 2022 (millions of Canadian $) Distributions Distributions received from operating activities of equity investments 1,607 1,158 955 Coastal GasLink LP subordinated loan repayment 1,2 3,147 — — Sur de Texas debt repayments 2,3 — — 2,404 Other 2 539 23 228 5,293 1,181 3,587 Contributions 2 Contributions to Coastal GasLink LP 1 3,964 3,231 1,414 Sur de Texas debt financing 3 — — 1,199 Contributions made to other equity investments 719 918 783 4,683 4,149 3,396 1 In December 2024, TC Energy made an equity contribution of $3,137 million to Coastal GasLink LP, which used the funds to repay the balance owing to TC Energy under the subordinated loan agreement. The contribution and repayment were included in Investing activities in the Consolidated statement of cash flows. Refer to Note 7, Coastal GasLink, for additional information. 2 Included in Investing activities in the Consolidated statement of cash flows. 3 Represents TC Energy's proportionate share of the Sur de Texas debt financing requirements and subsequent repayments. Refer to Note 12, Loans receivable from affiliates, for additional information. Summarized Financial Information of Equity Investments year ended December 31 2024 2023 2022 (millions of Canadian $) Income Revenues 6,962 6,197 5,681 Operating and other expenses (3,783) (3,343) (3,290) Net income 3,026 2,457 2,031 Net income attributable to TC Energy 1,558 1,310 999 at December 31 2024 2023 (millions of Canadian $) Balance Sheet Current assets 3,959 3,279 Non-current assets 44,835 41,270 Current liabilities (2,111) (2,403) Non-current liabilities (21,729) (21,894)

LOANS RECEIVABLE FROM AFFILIATE

LOANS RECEIVABLE FROM AFFILIATES	12 Months Ended
	Dec. 31, 2024
Receivables [Abstract]
LOANS RECEIVABLE FROM AFFILIATES	LOANS RECEIVABLE FROM AFFILIATES Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. Coastal GasLink Pipeline Limited Partnership TC Energy holds a 35 per cent equity interest in Coastal GasLink LP and has been contracted to develop, construct and operate the Coastal GasLink pipeline. The Company has a subordinated loan agreement and a subordinated demand revolving credit facility with Coastal GasLink LP. Refer to Note 7, Coastal GasLink, for additional information. Sur de Texas TC Energy holds a 60 per cent equity interest in a joint venture with IEnova to own the Sur de Texas pipeline, for which TC Energy is the operator. In 2017, TC Energy entered into a MXN$21.3 billion unsecured revolving credit facility with the joint venture, which bore interest at a floating rate and was fully repaid upon maturity on March 15, 2022 in the amount of $1.2 billion. The Company's Consolidated statement of income reflects the related interest income and foreign exchange impact on this loan receivable until its repayment on March 15, 2022, which were fully offset upon consolidation with corresponding amounts included in TC Energy’s proportionate share of Sur de Texas equity earnings as follows: year ended December 31 Affected line item in the Consolidated statement of income (millions of Canadian $) 2024 2023 2022 Interest income 1 — — 19 Interest income and other Interest expense 2 — — (19) Income (loss) from equity investments Foreign exchange losses 1 — — (28) Foreign exchange (gains) losses, net Foreign exchange gains 1 — — 28 Income (loss) from equity investments 1 Included in the Corporate segment. 2 Included in the Mexico Natural Gas Pipelines segment. On March 15, 2022, as part of refinancing activities with the Sur de Texas joint venture, the peso-denominated inter-affiliate loan discussed above was replaced with a new U.S. dollar-denominated inter-affiliate loan from TC Energy of an equivalent $1.2 billion (US$938 million) with a floating interest rate. On July 29, 2022, the Sur de Texas joint venture entered into an unsecured term loan agreement with third parties, the proceeds of which were used to fully repay the U.S. dollar-denominated inter-affiliate loan with TC Energy.

RATE-REGULATED BUSINESSES

RATE-REGULATED BUSINESSES	12 Months Ended
	Dec. 31, 2024
Regulated Operations [Abstract]
RATE-REGULATED BUSINESSES	RATE-REGULATED BUSINESSES TC Energy's businesses that apply RRA currently include almost all of the Canadian, U.S. and Mexico natural gas pipelines and certain U.S. natural gas storage operations. Rate-regulated businesses account for and report assets and liabilities consistent with the resulting economic impact of the regulators' established rates, provided the rates are designed to recover the costs of providing the regulated service and the competitive environment makes it probable that such rates can be charged and collected. Certain revenues and expenses subject to utility regulation or rate determination that would otherwise be reflected in the statement of income are deferred on the balance sheet and are expected to be recovered from or refunded to customers in future service rates. Canadian Regulated Operations The majority of TC Energy's Canadian natural gas pipelines are regulated by the CER under the Canadian Energy Regulator Act. The CER regulates the construction and operation of facilities and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems under federal jurisdiction. The Impact Assessment Agency of Canada continues to assess designated projects. TC Energy's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and on capital as approved by the CER. Rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenue requirement for the upcoming year or multiple years. To the extent actual costs and revenues are more or less than forecasted costs and revenues, the regulator generally allows the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur. The Company's most significant regulated Canadian natural gas pipelines, based on total operated pipe length, are described below. NGTL System Prior to December 31, 2024, the NGTL System operated under the 2020-2024 Revenue Requirement Settlement (the 2020-2024 Settlement). The 2020-2024 Settlement included an approved ROE of 10.1 per cent on 40 per cent deemed common equity, provided the NGTL System the opportunity to increase depreciation rates if tolls fell below specified levels and provided an incentive mechanism for certain operating costs where variances from projected amounts are shared with its customers. In September 2024, the CER approved a new five-year negotiated revenue requirement settlement (the 2025–2029 NGTL Settlement) which commenced on January 1, 2025. The settlement enables an investment framework that supports the approval by the Company's Board of Directors (Board) to allocate approximately $3.3 billion of capital towards progression of a new multi-year growth plan for expansion facilities on the NGTL System. It is comprised of multiple distinct projects with targeted in-service dates between 2027 and 2030 that are subject to final Company and regulatory approvals. The 2025-2029 NGTL Settlement maintains an ROE of 10.1 per cent on 40 per cent deemed common equity while increasing NGTL System depreciation rates, with an incentive that allows the NGTL System the opportunity to further increase depreciation rates if tolls fall below specified levels or if growth projects are undertaken. The 2025-2029 NGTL Settlement introduces a new incentive mechanism to reduce both physical emissions and emission compliance costs, which builds on the incentive mechanism for certain operating costs where variances from projected amounts and emissions savings are shared with customers. A provision for review exists in the current settlement if tolls exceed a pre-determined level or if final Company approvals of the multi-year growth plan are not obtained. Canadian Mainline The Canadian Mainline currently operates under the terms of the 2015-2030 Tolls Application approved in 2014 (the 2014 Decision). In April 2020, the CER approved the six-year unanimous negotiated settlement (the 2021-2026 Mainline Settlement) effective January 1, 2021. Similar to the previous settlement, the 2021-2026 Mainline Settlement maintains a base equity return of 10.1 per cent on 40 per cent deemed common equity and includes an incentive to either achieve cost efficiencies and/or increase revenues on the pipeline with a beneficial sharing mechanism to both customers and TC Energy. Toll stabilization is achieved using deferral accounts, including the toll-stabilization account and the short-term adjustment accounts (STAA), which capture the surplus or shortfall between system revenues and cost of service each year under the 2021-2026 Mainline Settlement. A portion of the STAA commenced amortization in 2023 and the remainder commenced amortization in 2024, according to the terms outlined in the 2021-2026 Mainline Settlement as predetermined thresholds per the settlement agreement were met. Similar to the STAA, the long-term adjustment account (LTAA) and bridging account were used to capture the surplus or shortfall between the Company's revenues and cost of service during the previous settlement and are amortized over the life of 2021-2026 Settlement and the 2014 Decision respectively. U.S. Regulated Operations TC Energy's U.S. regulated natural gas pipelines operate under the provisions of the Natural Gas Act of 1938 (NGA), the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005, and are subject to the jurisdiction of FERC. The NGA grants FERC authority over the construction, acquisition and operation of pipelines and related facilities, including the regulation of tariffs which incorporates maximum and minimum rates for services and allows U.S. regulated natural gas pipelines to discount or negotiate rates on a non-discriminatory basis. The Company's most significant regulated U.S. natural gas pipelines, based on effective ownership and total operated pipe length, are described below. Columbia Gas Columbia Gas' natural gas transportation and storage services are provided under a tariff at rates subject to FERC approval. Columbia Gas operates under a settlement approved by FERC in February 2022 (the 2022 Columbia Gas Settlement). As part of the settlement, there is a moratorium on any further rate changes until April 1, 2025, and Columbia Gas must file for new rates with an effective date no later than April 1, 2026. Additionally, Columbia Gas maintains a FERC-approved modernization program allowing for the cost recovery and return on additional investment up to US$1.2 billion over a four-year period through 2024 to modernize the Columbia Gas system, thereby improving system integrity and enhancing service reliability and flexibility. In September 2024, Columbia Gas filed a general NGA Section 4 rate case with FERC requesting an increase to Columbia Gas’ maximum transportation rates effective April 1, 2025, subject to refund based on the outcome of the proceeding. ANR Pipeline ANR Pipeline operates under rates established through a 2022 FERC-approved rate settlement (the 2022 ANR Settlement). The 2022 ANR Settlement reflects the agreement of ANR Pipeline, its customers and FERC staff to resolve all outstanding issues pertaining to the original rate case filing in January 2022 and was effective August 2022. The 2022 ANR Settlement received FERC approval on April 11, 2023. As part of the settlement, there is a moratorium on any further rate changes until November 1, 2025. ANR must file for new rates with an effective date no later than August 1, 2028. The settlement also included an additional rate step up effective August 2024 related to certain modernization projects. In 2023, previously accrued rate refund liabilities, including interest, were refunded to customers. Columbia Gulf Columbia Gulf operates under a settlement approved by FERC in August 2023, effective March 1, 2024 (the 2023 Columbia Gulf Settlement). The 2023 Columbia Gulf Settlement includes a moratorium on further rate changes through February 28, 2027, and Columbia Gulf must file for new rates no later than March 1, 2029. Great Lakes Great Lakes operates under a rate settlement approved by FERC on April 26, 2022 (the 2022 Great Lakes Settlement), which maintains Great Lakes’ existing maximum transportation rates through October 31, 2025. The 2022 Great Lakes Settlement contains a moratorium until October 31, 2025. Great Lakes will be required to file for new rates no later than April 30, 2025, with such new rates effective no later than November 1, 2025. Tuscarora Tuscarora operates under rates established as part of the FERC-approved rate settlement on September 6, 2023 (the 2023 Tuscarora Settlement). The 2023 Tuscarora Settlement provided for phased rate reductions as of February 1, 2023, and additionally as of February 1, 2025. The 2023 Tuscarora Settlement contains a moratorium that expires December 1, 2028. Tuscarora is required to file new rates by December 1, 2028. Gas Transmission Northwest On September 29, 2023, Gas Transmission Northwest (GTN) filed a general NGA Section 4 Rate Case with FERC, requesting an increase to GTN's maximum rates to become effective April 1, 2024, and subject to refund. On August 9, 2024, GTN filed a settlement with FERC resolving all issues in the general NGA Section 4 Rate Case. On October 21, 2024, the settlement was approved by FERC. Mexico Regulated Operations TC Energy's Mexico natural gas pipelines are regulated by CRE and operate in accordance with CRE-approved tariffs. The rates in effect on TC Energy's Mexico natural gas pipelines provide for cost recovery, including a return of and on invested capital. Regulatory Assets and Liabilities at December 31 Remaining Recovery/ Settlement Period (years) 2024 2023 (millions of Canadian $) Regulatory Assets Deferred income taxes 1 n/a 2,593 2,204 Operating and debt-service regulatory assets 2 1 56 29 Pensions and other post-retirement benefits 1,3 n/a — 54 Foreign exchange on long-term debt 1,4 1-5 39 11 Other n/a 117 108 2,805 2,406 Less: Current portion included in Other current assets (Note 8) 123 76 2,682 2,330 Regulatory Liabilities Pipeline abandonment trust balances 5 n/a 2,686 2,252 Deferred income taxes – U.S. Tax Reform 6 n/a 1,197 1,137 Canadian Mainline short-term adjustment and toll-stabilization accounts 7,8 n/a 553 437 Cost of removal 9 n/a 376 351 Canadian Mainline bridging amortization account 7 6 322 376 Deferred income taxes 1 n/a 188 198 Pensions and other post-retirement benefits 3 n/a 122 6 Canadian Mainline long-term adjustment account 7,10 2 74 111 Operating and debt-service regulatory liabilities 2 1 50 23 ANR post-employment and retirement benefits other than pension 11 n/a 45 42 Other n/a 43 54 5,656 4,987 Less: Current portion included in Accounts payable and other (Note 17) 353 284 5,303 4,703 1 These regulatory assets and liabilities are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets or liabilities are not included in rate base and do not yield a return on investment during the recovery period. 2 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances to be included in determination of rates in the following year. 3 These balances represent the regulatory offset to pension plan and other post-retirement benefit obligations to the extent the amounts are expected to be collected from or refunded to customers in future rates. 4 Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. 5 This balance represents the amounts collected in tolls from customers and included in the LMCI restricted investments to fund future abandonment of the Company's CER-regulated pipeline facilities. 6 The U.S. corporate income tax rate was reduced from 35 per cent to 21 per cent in 2017 as a result of H.R.1, the Tax Cuts and Jobs Act (U.S. Tax Reform). This U.S. regulated operations balance, where applicable, represents established regulatory liabilities driven by 2018 FERC prescribed changes related to U.S. Tax Reform being amortized over varying terms that approximate the expected reversal of the underlying deferred tax liabilities that gave rise to the regulatory liabilities. 7 These regulatory accounts are used to capture revenue and cost variances plus toll-stabilization adjustments during the 2015-2030 settlement term. 8 Under the terms of the 2021-2026 Mainline Settlement, a portion of the STAA account commenced amortization in 2023 and the remainder commenced amortization in 2024, as predetermined thresholds were met, over the terms outlined per the settlement agreement. 9 This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated operations for future costs to be incurred. 10 Under the terms of the 2021-2026 Mainline Settlement, $223 million is amortized over the six-year settlement term. 11

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL The Company's Goodwill balance on the Consolidated balance sheet is comprised of the following amounts: at December 31 2024 2023 (millions) Canadian U.S. dollars Canadian dollars U.S. dollars Columbia Pipeline Group, Inc. 10,588 7,351 9,708 7,351 ANR 2,803 1,946 2,570 1,946 Great Lakes 176 122 161 122 North Baja 70 48 63 48 Tuscarora 33 23 30 23 13,670 9,490 12,532 9,490 Changes in Goodwill were as follows: (millions of Canadian $) U.S. Natural Balance at January 1, 2023 12,843 Foreign exchange rate changes (311) Balance at December 31, 2023 1 12,532 Foreign exchange rate changes 1,138 Balance at December 31, 2024 1 13,670 1 Represents gross amounts of goodwill as at December 31, 2024 of $15,405 million (2023 – $14,267 million), net of accumulated impairment of $1,735 million (2023 – $1,735 million). As part of the annual goodwill impairment assessment at December 31, 2024, the Company evaluated qualitative factors impacting the fair value of the underlying reporting units. It was determined that it was more likely than not that the fair value of all reporting units exceeded their carrying amounts, including goodwill. Columbia On October 4, 2023, as part of the asset divestiture program announced in 2022, the Company successfully completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf. In conjunction with the process leading up to the sale, the Company performed a quantitative goodwill impairment test at June 30, 2023. The estimated fair value measurements used in the Company's goodwill impairment analysis are classified as Level III of the fair value hierarchy. In the determination of the fair value utilized in the quantitative goodwill impairment test for the Columbia reporting unit, the Company performed a discounted cash flow model analysis using projections of future cash flows and applied a risk-adjusted discount rate and value multiple which involved significant estimates and judgments. It was determined that the fair value of the Columbia reporting unit, inclusive of the Columbia Gas and Columbia Gulf business units, exceeded its carrying value, including goodwill. Although goodwill was not impaired, the estimated fair value in excess of the carrying value was less than 10 per cent. There is a risk that reductions in future cash flow forecasts and adverse changes in other key assumptions could result in a future impairment of a portion of the goodwill balance relating to Columbia. Great Lakes In March 2022, an impairment loss of $571 million ($531 million after tax) was recognized for the excess carrying value over the estimated fair value of our Great Lakes reporting unit. There is a risk that reductions in future cash flow forecasts and adverse changes in other key assumptions could result in future impairment of the remaining goodwill balance.

OTHER LONG-TERM ASSETS

OTHER LONG-TERM ASSETS	12 Months Ended
	Dec. 31, 2024
Intangible Assets, Net (Excluding Goodwill) [Abstract]
OTHER LONG-TERM ASSETS	OTHER LONG-TERM ASSETS at December 31 2024 2023 (millions of Canadian $) Employee post-retirement benefits (Note 27) 758 518 Long-term contract assets (Note 6) 608 457 Deferred income tax assets (Note 19) 428 1,319 Capital projects in development 164 234 Fair value of derivative contracts (Note 28) 122 155 Other 330 198 2,410 2,881

NOTES PAYABLE

NOTES PAYABLE	12 Months Ended
	Dec. 31, 2024
Short-Term Debt [Abstract]
NOTES PAYABLE	NOTES PAYABLE at December 31 2024 2023 (millions of Canadian $, unless otherwise noted) Outstanding Weighted Average Interest Rate per Annum Outstanding Weighted Average Interest Rate per Annum Canada 1 308 4.7 % — — U.S. (2024 – US$55; 2023 – nil) 79 4.7 % — — 387 — 1 At December 31, 2024, Notes payable consisted of Canadian dollar-denominated notes of nil (2023 – nil) and U.S. dollar-denominated notes of US$214 million (2023 – nil). At December 31, 2024, Notes payable reflects short-term borrowings in Canada by TCPL and in the U.S. by TransCanada PipeLine USA Ltd. (TCPL USA). At December 31, 2024, total committed revolving and demand credit facilities were $12.2 billion (2023 – $12.9 billion). When drawn, interest on these lines of credit is charged at negotiated floating rates of Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following: at December 31 (billions of Canadian $, unless otherwise noted) 2024 2023 Borrowers Description Matures Total Facilities Unused Capacity 1 Total Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities 2 : TCPL Supports commercial paper program and for general corporate purposes December 2029 3.0 3.0 3.0 TCPL / TCPL USA Supports commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL December 2025 US 1.0 US 0.7 US 2.5 TCPL / TCPL USA Supports commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL December 2027 US 2.5 US 2.5 US 2.5 Columbia Pipelines Holding Company LLC 3 Supports commercial paper program and general corporate purposes of the borrower December 2027 US 1.5 US 1.5 US 1.0 Demand senior unsecured revolving credit facilities 2 : TCPL / TCPL USA Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL Demand 2.0 4 1.1 2.0 4 1 Unused capacity is net of commercial paper outstanding and facility draws. 2 Provisions of various trust indentures and credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and preferred shares. These trust indentures and credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2024, the Company was in compliance with all financial covenants. 3 Columbia Pipelines Holding Company LLC (CPHC LLC) is a partially-owned subsidiary of TC Energy with 40 per cent non-controlling interest. 4 Or the U.S. dollar equivalent. For the year ended December 31, 2024, the cost to maintain the above facilities was $18 million (2023 – $16 million; 2022 – $14 million).

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2024
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER at December 31 2024 2023 (millions of Canadian $) Trade payables 3,699 3,092 Fair value of derivative contracts (Note 28) 507 415 Regulatory liabilities (Note 13) 353 284 Income tax liabilities 143 76 Operating lease liabilities (Note 10) 60 57 Contract liabilities (Note 6) 30 47 Other 505 334 5,297 4,305

OTHER LONG-TERM LIABILITIES

OTHER LONG-TERM LIABILITIES	12 Months Ended
	Dec. 31, 2024
Deferred Costs, Noncurrent [Abstract]
OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES at December 31 2024 2023 (millions of Canadian $) Operating lease obligations (Note 10) 451 400 Fair value of derivative contracts (Note 28) 209 106 Asset retirement obligations 108 64 Employee post-retirement benefits (Note 27) 94 97 Other 189 324 1,051 991

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Geographic Components of Income before Income Taxes year ended December 31 2024 2023 2022 (millions of Canadian $) Canada 1,219 (344) (2,133) Foreign 4,687 3,642 2,607 Income before Income Taxes 5,906 3,298 474 Provision for Income Taxes year ended December 31 2024 2023 2022 (millions of Canadian $) Current Canada 102 61 41 Foreign 393 803 322 495 864 363 Deferred Canada 135 8 (459) Foreign 292 (30) 418 427 (22) (41) Income Tax Expense 922 842 322 Reconciliation of Income Tax Expense year ended December 31 2024 2023 2022 (millions of Canadian $) Income before income taxes 5,906 3,298 474 Federal and provincial statutory tax rate 23.0 % 23.0 % 23.0 % Expected income tax expense 1,358 759 109 Mexico foreign exchange exposure (246) 132 9 Income tax differential related to regulated operations (227) (260) (174) Income from non-controlling interests and equity investments (224) (56) (54) Foreign income tax rate differentials 167 (84) (216) Non-taxable capital (gains) and losses 18 182 173 Impact of Mexico inflationary adjustments 7 1 24 Valuation allowance (release) 4 182 198 Settlement of Mexico prior years' income tax assessments — — 196 Non-deductible goodwill impairment — — 91 Other 65 (14) (34) Income Tax Expense 922 842 322 Deferred Income Tax Assets and Liabilities at December 31 2024 2023 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,987 1,664 Disallowed interest carryforward 115 — Regulatory and other deferred amounts 612 583 Unrealized foreign exchange losses on long-term debt 467 206 Other 143 160 3,324 2,613 Less: Valuation allowance 931 690 2,393 1,923 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment 6,488 5,599 Equity investments 1,280 1,043 Taxes on future revenue requirement 612 496 Financial instruments 168 168 Other 301 270 8,849 7,576 Net Deferred Income Tax Liabilities 6,456 5,653 The above deferred tax amounts have been classified on the Consolidated balance sheet as follows: at December 31 2024 2023 (millions of Canadian $) Deferred Income Tax Assets Other long-term assets (Note 15) 428 1,319 Deferred Income Tax Liabilities Deferred income tax liabilities 6,884 6,972 Net Deferred Income Tax Liabilities 6,456 5,653 TC Energy recorded an income tax valuation allowance of $931 million and $690 million against the deferred income tax asset balances at December 31, 2024 and 2023, respectively. The increase in the valuation allowance is primarily a result of the foreign exchange movement on unrecognized capital losses. At December 31, 2023, the Company recorded a total of $358 million in valuation allowance as a result of the Coastal GasLink equity investment impairment that resulted in a portion of the impairment having unrealized non-taxable capital losses. These losses have not been recognized as of December 31, 2024. At each reporting date, the Company considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. At December 31, 2024, the Company determined there was sufficient positive evidence to conclude that it is more likely than not that the net deferred tax assets will be realized. At December 31, 2024, the Company has recognized the benefit of non-capital loss carryforwards of $6,740 million (2023 – $6,593 million) for federal and provincial purposes in Canada, which expire from 2030 to 2044. The Company has not yet recognized the benefit of capital loss carryforwards of $599 million (2023 – $478 million) for federal and provincial purposes in Canada which have no expiry date. The Company has Ontario corporate minimum tax (CMT) credits of $161 million (2023 – $140 million), which expire from 2026 to 2044. As of December 31, 2024, the Company has not recognized the benefit of CMT credits of $22 million (2023 – $22 million). As of December 31, 2024, the Company has recognized the benefit of disallowed Canadian interest expense of $480 million (2023 - nil) which may be carried forward indefinitely. At December 31, 2024, the Company has recognized the benefit of net operating loss carryforwards of US$518 million (2023 – US$47 million) in Mexico, which expire from 2024 to 2034. Unremitted Earnings of Foreign Investments Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2024 by approximately $1,728 million (2023 – $1,443 million) if there had been a provision for these taxes. Income Tax Payments Income tax payments of $387 million, net of refunds, were made in 2024 (2023 – payments, net of refunds, of $791 million; 2022 – payments, net of refunds, of $394 million). Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2024 2023 2022 (millions of Canadian $) Unrecognized tax benefit at beginning of year 85 91 80 Gross increases – tax positions in prior years 3 9 6 Gross decreases – tax positions in prior years (2) (1) — Gross increases – tax positions in current year 5 16 7 Gross decrease – tax positions in current year (2) — — Settlement (13) — — Lapse of statutes of limitations (4) (30) (2) Unrecognized Tax Benefit at End of Year 72 85 91 TC Energy's practice is to recognize interest and penalties related to income tax uncertainties in Income tax expense. Income tax expense for the year ended December 31, 2024 reflects $1 million interest recovery (2023 – $3 million expense; 2022 – $6 million expense). At December 31, 2024, the Company accrued $19 million in interest expense (2023 – $20 million; 2022 – $18 million). The Company incurred no penalties associated with income tax uncertainties related to income tax expense for the years ended December 31, 2024, 2023 and 2022 and no penalties were accrued as at December 31, 2024, 2023 and 2022. Subject to the results of audit examinations by taxing authorities and other legislative amendments, TC Energy does not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on its financial statements. TC Energy and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2016. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2016. Substantially all material Mexico income tax matters have been concluded for years through 2018. Mexico Tax Audit In 2019, the Mexican tax authority, the Tax Administration Services (SAT), completed an audit of the 2013 tax return of one of the Company’s subsidiaries in Mexico. The audit resulted in a tax assessment that denied the deduction for all interest expense and an assessment of additional tax, penalties and financial charges totaling less than US$1 million. The Company disagreed with this assessment and commenced litigation to challenge it. In January 2022, TC Energy received the tax court’s ruling on the 2013 tax return, which upheld the SAT assessment. From September 2021 to February 2022, the SAT issued assessments for tax years 2014 through 2017 which denied the deduction of all interest expense as well as assessed incremental withholding tax on the interest. These assessments totaled approximately US$490 million in income and withholding taxes, interest, penalties and other financial charges. During 2022, TC Energy settled with the SAT on all of the above matters for the tax years 2013 through 2021 and recorded $196 million (US$153 million) of income tax expense, inclusive of withholding taxes, interest, penalties and other financial charges for the year ended December 31, 2022.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT at December 31 2024 2023 Maturity Dates Outstanding Interest Rate 1 Outstanding Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Medium Term Notes Canadian 2025 to 2052 13,141 4.7 % 15,466 4.6 % Senior Unsecured Notes U.S. (2024 – US$11,792; 2023 – US$16,167) 2025 to 2049 16,985 5.5 % 21,349 5.0 % 30,126 36,815 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian — — 100 9.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2024 and 2023 – US$33) 2026 47 7.5 % 43 7.5 % 551 647 COLUMBIA PIPELINES OPERATING COMPANY LLC Senior Unsecured Notes U.S. (2024 – US$6,500; 2023 – US$6,100) 2025 to 2063 9,362 6.0 % 8,055 6.1 % COLUMBIA PIPELINES HOLDING COMPANY LLC Senior Unsecured Notes U.S. (2024 – US$1,900; 2023 – US$1,000) 2026 to 2034 2,737 5.9 % 1,320 6.2 % ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2024 – US$1,047; 2023 – US$1,172) 2025 to 2037 1,509 3.7 % 1,548 4.1 % TC PIPELINES, LP Senior Unsecured Notes U.S. (2024 and 2023 – US$850) 2025 to 2027 1,224 4.2 % 1,122 4.2 % GAS TRANSMISSION NORTHWEST LLC Senior Unsecured Notes U.S. (2024 and 2023 – US$375) 2030 to 2035 540 4.4 % 495 4.4 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM 2 Senior Unsecured Notes U.S. (2024 – nil; 2023 – US$250) — — 330 2.8 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2024 – US$104; 2023 – US$125) 2028 to 2030 150 7.6 % 165 7.6 % at December 31 2024 2023 Maturity Dates Outstanding Interest Rate 1 Outstanding Interest Rate 1 (millions of Canadian $, unless otherwise noted) TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. Senior Unsecured Term Loan U.S. (2024 – US$1,370; 2023 – US$1,800) 2028 1,973 7.2 % 2,377 7.7 % Senior Unsecured Revolving Credit Facility U.S. (2024 – nil; 2023 – US$185) 2028 — — 244 7.7 % 1,973 2,621 48,172 53,118 Current portion of long-term debt (2,955) (2,938) Unamortized debt discount and issue costs (252) (312) Fair value adjustments 3 11 108 44,976 49,976 1 Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. The effective interest rate is calculated by discounting the expected future interest payments, adjusted for loan fees, premiums and discounts. Weighted average and effective interest rates are stated as at the respective outstanding dates. 2 On August 15, 2024, US$250 million of senior notes outstanding held at PNGTS were assumed by the purchaser as part of the sale of PNGTS. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 3 The fair value adjustments include $109 million (2023 – $119 million) related to the acquisition of Columbia Pipeline Group, Inc. These adjustments also include a decrease of $139 million (2023 – $11 million) related to hedged interest rate risk and an increase of $41 million (2023 - nil) related to discontinued hedge interest rate risk. Refer to Note 28, Risk management and financial instruments, for additional information. Principal Repayments At December 31, 2024, principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2025 2026 2027 2028 2029 Principal repayments on long-term debt 2,955 2,810 3,158 6,083 1,333 Long-Term Debt Issued The Company issued long-term debt over the three years ended December 31, 2024 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED August 2024 Term Loan 1 August 2024 US 1,242 Floating May 2023 Senior Unsecured Term Loan 2 May 2026 US 1,024 Floating March 2023 Senior Unsecured Notes 3 March 2026 US 850 6.20 % March 2023 Senior Unsecured Notes 3 March 2026 US 400 Floating March 2023 Medium Term Notes July 2030 1,250 5.28 % March 2023 Medium Term Notes 3 March 2026 600 5.42 % March 2023 Medium Term Notes 3 March 2026 400 Floating May 2022 Medium Term Notes May 2032 800 5.33 % May 2022 Medium Term Notes May 2026 400 4.35 % May 2022 Medium Term Notes May 2052 300 5.92 % COLUMBIA PIPELINES OPERATING COMPANY LLC September 2024 Senior Unsecured Notes October 2054 US 400 5.70 % August 2023 Senior Unsecured Notes November 2033 US 1,500 6.04 % August 2023 Senior Unsecured Notes November 2053 US 1,250 6.54 % August 2023 Senior Unsecured Notes August 2030 US 750 5.93 % August 2023 Senior Unsecured Notes August 2043 US 600 6.50 % August 2023 Senior Unsecured Notes August 2063 US 500 6.71 % COLUMBIA PIPELINES HOLDING COMPANY LLC September 2024 Senior Unsecured Notes October 2031 US 400 5.10 % January 2024 Senior Unsecured Notes January 2034 US 500 5.68 % August 2023 Senior Unsecured Notes August 2028 US 700 6.04 % August 2023 Senior Unsecured Notes August 2026 US 300 6.06 % GAS TRANSMISSION NORTHWEST LLC June 2023 Senior Unsecured Notes June 2030 US 50 4.92 % TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. January 2023 Senior Unsecured Term Loan January 2028 US 1,800 Floating January 2023 Senior Unsecured Revolving Credit Facility January 2028 US 500 Floating ANR PIPELINE COMPANY May 2022 Senior Unsecured Notes May 2032 US 300 3.43 % May 2022 Senior Unsecured Notes May 2034 US 200 3.58 % May 2022 Senior Unsecured Notes May 2037 US 200 3.73 % May 2022 Senior Unsecured Notes May 2029 US 100 3.26 % 1 In August 2024, TCPL entered into a term loan to facilitate the Spinoff Transaction and, in August 2024, the term loan was fully repaid and retired upon delivery of senior unsecured notes issued by 6297782 LLC. Refer to Note 4, Discontinued operations, for additional information. 2 Fully repaid and retired in September 2023. 3 In October 2024, callable notes were repaid and retired at par. Long-Term Debt Retired/Repaid The Company retired/repaid long-term debt over the three years ended December 31, 2024 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED October 2024 Senior Unsecured Notes US 1,250 1.00 % October 2024 Senior Unsecured Notes 1 US 850 6.20 % October 2024 Senior Unsecured Notes 2 US 739 2.50 % October 2024 Senior Unsecured Notes 2 US 441 4.88 % October 2024 Senior Unsecured Notes 1 US 400 Floating October 2024 Senior Unsecured Notes 2 US 313 4.75 % October 2024 Senior Unsecured Notes 2 US 201 5.00 % October 2024 Senior Unsecured Notes 2 US 180 5.10 % October 2024 Medium Term Notes 1 600 5.42 % October 2024 Medium Term Notes 2 575 4.18 % October 2024 Medium Term Notes 1 400 Floating August 2024 Term Loan 3 US 1,242 Floating June 2024 Medium Term Notes 750 Floating October 2023 Senior Unsecured Notes US 625 3.75 % September 2023 Senior Unsecured Term Loan US 1,024 Floating July 2023 Medium Term Notes 750 3.69 % December 2022 Medium Term Notes 25 9.95 % August 2022 Senior Unsecured Notes US 1,000 2.50 % NOVA GAS TRANSMISSION LTD. March 2024 Debentures 100 9.90 % April 2023 Debentures US 200 7.88 % ANR PIPELINE COMPANY February 2024 Senior Unsecured Notes US 125 7.38 % TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. Various 2024 Senior Unsecured Term Loan US 430 Floating Various 2024 Senior Unsecured Revolving Credit Facility US 185 Floating Various 2023 Senior Unsecured Revolving Credit Facility US 315 Floating TUSCARORA GAS TRANSMISSION COMPANY November 2023 Unsecured Term Loan US 32 Floating 1 In October 2024, callable notes were retired at par. 2 In October 2024, TCPL purchased and cancelled notes at a 7.73 per cent weighted average discount, as a settlement of cash tender offers. 3 In August 2024, TCPL entered into a term loan to facilitate the Spinoff Transaction and, in August 2024, the term loan was fully repaid and retired upon delivery of senior unsecured notes issued by 6297782 LLC. Refer to Note 4, Discontinued operations, for additional information. In October 2024, TCPL commenced and completed its cash tender offers to purchase and cancel certain senior unsecured notes and medium term notes at a 7.73 per cent weighted average discount. In addition, the Company repaid and retired outstanding callable notes at par. These extinguishments of debt resulted in a pre-tax net gain of $228 million, primarily due to the fair value discount and recognition of unamortized debt issue costs related to these notes. The net gain on debt extinguishment was recorded in Interest expense in the Consolidated statement of income. Interest Expense year ended December 31 2024 2023 2022 (millions of Canadian $) Interest on long-term debt 2,800 2,562 1,883 Interest on junior subordinated notes 638 617 543 Interest on short-term debt 60 165 153 Capitalized interest (191) (187) (27) Amortization and other financial charges 1 158 106 36 Gain on debt extinguishment (228) — — 3,237 3,263 2,588 Interest allocated to discontinued operations (Note 4) (218) (297) (288) 3,019 2,966 2,300 1 Amortization and other financial charges include amortization of transaction costs and debt discounts calculated using the effective interest method and losses on derivatives used to manage the Company's exposure to changes in interest rates. The Company made interest payments of $3,398 million in 2024 (2023 – $2,931 million; 2022 – $2,478 million) on long-term debt, junior subordinated notes and short-term debt, net of interest capitalized.

JUNIOR SUBORDINATED NOTES

JUNIOR SUBORDINATED NOTES	12 Months Ended
	Dec. 31, 2024
Junior Subordinated Notes [Abstract]
JUNIOR SUBORDINATED NOTES	JUNIOR SUBORDINATED NOTES at December 31 2024 2023 Maturity Outstanding Effective Interest Rate 1 Outstanding Effective Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED US$1,000 issued 2007 at 6.35% 2 2067 1,440 6.2 % 1,320 6.5 % US$750 issued 2015 at 5.88% 3,4 2075 1,080 7.5 % 990 7.8 % US$1,200 issued 2016 at 6.13% 3,4 2076 1,729 8.0 % 1,585 8.3 % US$1,500 issued 2017 at 5.55% 3,4 2077 2,161 7.2 % 1,981 7.5 % $1,500 issued 2017 at 4.90% 3,4 2077 1,500 6.8 % 1,500 7.0 % US$1,100 issued 2019 at 5.75% 3,4 2079 1,584 7.7 % 1,453 8.0 % $500 issued 2021 at 4.45% 3,5 2081 500 5.7 % 500 5.7 % US$800 issued 2022 at 5.85% 3,5 2082 1,152 7.3 % 1,056 7.1 % 11,146 10,385 Unamortized debt discount and issue costs (98) (98) 11,048 10,287 1 The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for issue costs and discounts. 2 Junior subordinated notes of US$1.0 billion were issued in 2007 at a fixed rate of 6.35 per cent and converted in 2017 to bear interest at a floating rate. 3 The Junior subordinated notes were issued to TransCanada Trust (the Trust), a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TC Energy's financial statements since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. 4 The coupon rate is initially a fixed interest rate for the first 10 years and converts to a floating rate thereafter. 5 The coupon rate is initially a fixed interest rate for the first 10 years and resets every five years thereafter. The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. In March 2022, TransCanada Trust (the Trust) issued US$800 million of Trust Notes – Series 2022-A to investors with a fixed interest rate of 5.60 per cent per annum for the first 10 years and resetting on the 10th anniversary and every five years thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$800 million of junior subordinated notes of TCPL at an initial fixed rate of 5.85 per cent per annum, including a 0.25 per cent administration charge. The rate on the junior subordinated notes of TCPL will reset every five years commencing March 2032 until March 2052 to the then Five-Year Treasury Rate, as defined in the document governing the subordinated notes, plus 4.236 per cent per annum; from March 2052 until March 2082, the interest rate will reset every five years to the then Five-Year Treasury Rate plus 4.986 per cent per annum. The junior subordinated notes are callable at TCPL's option at any time from December 7, 2031 to March 7, 2032 and on each interest payment and reset date thereafter at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. Pursuant to the terms of the notes issued between the Trust and TCPL (the Trust Notes) and related agreements, in certain circumstances: 1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and 2) TC Energy and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with any other outstanding first preferred shares of TCPL.

FOREIGN EXCHANGE (GAINS) LOSSES

FOREIGN EXCHANGE (GAINS) LOSSES, NET	12 Months Ended
	Dec. 31, 2024
Foreign Currency [Abstract]
FOREIGN EXCHANGE (GAINS) LOSSES, NET	FOREIGN EXCHANGE (GAINS) LOSSES, NET year ended December 31 2024 2023 2022 (millions of Canadian $) Derivative instruments held for trading (Note 28) 418 (401) 151 Other (271) 81 34 147 (320) 185

NON-CONTROLLING INTERESTS

NON-CONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2024
Noncontrolling Interest [Abstract]
NON-CONTROLLING INTERESTS	NON-CONTROLLING INTERESTS The Company's Net income (loss) attributable to non-controlling interests included in the Consolidated statement of income and Non-controlling interests included on the Consolidated balance sheet were as follows: (millions of Canadian $) Non-Controlling Interests Ownership at December 31, 2024 Income (Loss) Attributable to Non-Controlling Interests year ended December 31 at December 31 2024 2023 2022 2024 2023 Columbia Gas and Columbia Gulf 40 % 1 571 143 — 9,844 9,167 Portland Natural Gas Transmission System nil 1 30 41 37 — 106 Texas Wind Farms 100 % 1,2 (29) (38) — 168 182 TGNH 13.01 % 1 109 — — 756 — 681 146 37 10,768 9,455 1 Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 2 Tax equity investors own 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes and cash flows are allocated. TC Energy owns 100 per cent of the Class B Membership Interests.

COMMON SHARES

COMMON SHARES	12 Months Ended
	Dec. 31, 2024
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
COMMON SHARES	COMMON SHARES Number of Shares Amount (thousands) (millions of Canadian $) Outstanding at January 1, 2022 980,816 26,716 Issued under public offering 1 28,400 1,754 Dividend reinvestment and share purchase plan 5,916 342 Exercise of options 2,830 183 Outstanding at December 31, 2022 1,017,962 28,995 Dividend reinvestment and share purchase plan 19,464 1,003 Exercise of options 62 4 Outstanding at December 31, 2023 1,037,488 30,002 Exercise of options 1,607 99 Outstanding at December 31, 2024 1,039,095 30,101 1 Net of underwriting commissions and deferred income taxes. Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares without par value. Common Shares After Spinoff Transaction On October 1, 2024, as part of the Spinoff Transaction, TC Energy shareholders received one new TC Energy common share and 0.2 of a South Bow common share in exchange for each TC Energy common share held. Refer to Note 1, Description of TC Energy's business, for additional information. Common Shares Issued Under Public Offering On August 10, 2022, TC Energy issued 28,400,000 common shares at a price of $63.50 each for total gross proceeds of approximately $1.8 billion. Dividend Reinvestment and Share Purchase Plan Under the Company's Dividend Reinvestment and Share Purchase Plan (DRP), eligible holders of common and preferred shares of TC Energy can reinvest their dividends and make optional cash payments to obtain additional TC Energy common shares. From August 31, 2022 to July 31, 2023, common shares were issued from treasury at a discount of two per cent to market prices over a specified period. For the periods between January 1, 2021 and August 31, 2022, and after July 31, 2023, common shares purchased with reinvested cash dividends under TC Energy's DRP are acquired on the open market at 100 per cent of the weighted average purchase price. Basic and Diluted Net Income (Loss) per Common Share Net income (loss) from continuing operations per common share is calculated by dividing Net income (loss) from continuing operations attributable to common shares by the weighted average number of common shares outstanding. Net income (loss) from discontinued operations is calculated by dividing Net income (loss) from discontinued operations by the weighted average number of common shares outstanding. The weighted average number of shares for the diluted earnings per share calculation includes options exercisable under TC Energy's Stock Option Plan and, from August 31, 2022 to July 31, 2023, common shares issuable from treasury under the DRP. Weighted Average Common Shares Outstanding at December 31 (millions) 2024 2023 2022 Basic 1,038 1,030 995 Diluted 1,038 1,030 996 Stock Options Number of Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (thousands) (years) Options outstanding at January 1, 2024 7,436 $62.36 Options exercised (363) $56.85 Options forfeited/expired (598) $63.70 Options Outstanding at September 30, 2024 6,475 $62.54 3.5 Options Exercisable at September 30, 2024 4,975 $63.54 3.0 Options cancelled on October 1, 2024 (6,475) $62.54 Options issued on October 1, 2024 5,889 $59.72 Options exercised (1,244) $54.49 Options forfeited/expired (171) $72.17 Options Outstanding at December 31, 2024 4,474 $60.69 3.6 Options Exercisable at December 31, 2024 3,169 $62.50 3.1 On October 1, 2024, as part of the Spinoff Transaction, all outstanding TC Energy stock options were cancelled and an equivalent number of new TC Energy stock options were issued to applicable remaining TC Energy employees and former TC Energy employees (other than those transferred to South Bow pursuant to the Spinoff Transaction) who still held TC Energy stock options. The exercise prices of the new TC Energy stock options were adjusted for the change in value of the TC Energy common shares following the Spinoff Transaction. No other stock options were granted in 2024. At December 31, 2024, an additional 3,621,343 common shares were reserved for future issuance from treasury under TC Energy's Stock Option Plan. The contractual life of options granted is seven years. Options may be exercised at a price determined at the time the option is awarded and vest equally on the anniversary date in each of the three years following the award. Forfeiture of stock options results from their expiration and, if not previously vested, upon resignation or termination of the option holder's employment. Commencing in 2024, the Company no longer issues stock options to employees or officers. The Company used a binomial model for determining the fair value of options granted and applied the following weighted average assumptions: year ended December 31 2024 1 2023 2022 Weighted average fair value — $7.88 $8.24 Expected life (years) 2 — 5.1 5.4 Interest rate — 2.9 % 1.6 % Volatility 3 — 24 % 22 % Dividend yield — 6.3 % 5.5 % 1 Commencing in 2024, the Company no longer issues stock options to employees or officers. 2 Expected life is based on historical exercise activity. 3 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $6 million in 2024 (2023 – $9 million; 2022 – $10 million). At December 31, 2024, unrecognized compensation costs related to non-vested stock options were less than $1 million. The cost is expected to be fully recognized over a weighted average period of 0.7 years. The following table summarizes additional stock option information: year ended December 31 2024 2023 2022 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 17 — 33 Total fair value of options that have vested 99 76 89 Total options vested 1.5 million 1.5 million 1.6 million As at December 31, 2024, the aggregate intrinsic values of the total options exercisable and the total options outstanding were $20 million and $34 million, respectively. Shareholder Rights Plan TC Energy's Shareholder Rights Plan is designed to provide the Board of Directors with sufficient time to explore and develop alternatives for maximizing shareholder value in the event of a takeover offer for the Company and to encourage the fair treatment of shareholders in connection with any such offer. Attached to each common share is one right that, under certain circumstances, entitles certain holders to purchase an additional common share of the Company.

PREFERRED SHARES

PREFERRED SHARES	12 Months Ended
	Dec. 31, 2024
Preferred Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
PREFERRED SHARES	PREFERRED SHARES at December 31, 2024 Number of Shares Outstanding Current Yield Annual Dividend Per Share 1,2 Redemption Price Per Share Redemption and Conversion Option Date Right to Convert Into Carrying Value December 31 3 2024 2023 2022 (thousands) (millions of Canadian $) Cumulative First Preferred Shares Series 1 18,424 4.94 % 4 $1.23475 $25.00 December 31, 2029 Series 2 456 360 360 Series 2 3,576 Floating 5 Floating $25.00 December 31, 2029 Series 1 83 179 179 Series 3 9,997 1.69 % $0.4235 $25.00 June 30, 2025 Series 4 246 246 246 Series 4 4,003 Floating 5 Floating $25.00 June 30, 2025 Series 3 97 97 97 Series 5 12,071 1.95 % $0.48725 $25.00 January 30, 2026 Series 6 294 294 294 Series 6 1,929 Floating 5 Floating $25.00 January 30, 2026 Series 5 48 48 48 Series 7 24,000 5.99 % 4 $1.49625 $25.00 April 30, 2029 Series 8 589 589 589 Series 9 16,703 5.08 % 4 $1.27 $25.00 October 30, 2029 Series 10 410 442 442 Series 10 1,297 Floating 5 Floating $25.00 October 30, 2029 Series 9 32 — — Series 11 10,000 3.35 % $0.83775 $25.00 November 28, 2025 Series 12 244 244 244 2,499 2,499 2,499 1 Each of the even-numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90-day Government of Canada Treasury bill rate (T-bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10), or 2.96 per cent (Series 12). These rates reset quarterly with the then current T-Bill rate. 2 The odd-numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then Five-Year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), or 2.96 per cent (Series 11). 3 Net of underwriting commissions and deferred income taxes. 4 The fixed rate dividend for Series 1, Series 7 and Series 9 preferred shares increased from 3.48 per cent to 4.94 per cent on December 31, 2024, 3.90 per cent to 5.99 per cent on April 30, 2024 and from 3.76 per cent to 5.08 per cent on October 30, 2024, respectively, and is due to reset on every fifth anniversary thereafter. No Series 7 preferred shares were converted on the April 30, 2024 conversion date. 5 The floating quarterly dividend rate for the Series 2 preferred shares is 5.40 per cent for the period starting December 31, 2024 to, but excluding, March 31, 2025. The floating quarterly dividend rate for the Series 4 preferred shares is 4.76 per cent for the period starting December 31, 2024 to, but excluding, March 31, 2025. The floating quarterly dividend rate for the Series 6 preferred shares is 5.52 per cent for the period starting October 30, 2024 to, but excluding, January 30, 2025 The floating quarterly dividend rate for the Series 10 preferred shares is 6.33 per cent for the period starting October 30, 2024 to, but excluding, January 30, 2025. These rates will reset each quarter going forward. The holders of preferred shares are entitled to receive a fixed cumulative quarterly preferential dividend as and when declared by the Board with the exception of Series 2, Series 4, Series 6 and Series 10 preferred shares. The holders of Series 2, Series 4, Series 6 and Series 10 preferred shares are entitled to receive quarterly floating rate cumulative preferential dividends as and when declared by the Board. The holders will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter as indicated in the table above. TC Energy may, at its option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. In addition, Series 2, Series 4, Series 6 and Series 10 preferred shares are redeemable by TC Energy at any time other than on a designated date for $25.50 per share plus all accrued and unpaid dividends on such redemption date. On December 31, 2024, 42,200 Series 1 preferred shares were converted, on a one-for-one basis, into Series 2 preferred shares and 3,889,020 Series 2 preferred shares were converted, on a one-for-one basis, into Series 1 preferred shares. On October 30, 2024, 1,297,203 Series 9 preferred shares were converted, on a one-for-one basis, into Series 10 preferred shares. On May 31, 2022, TC Energy redeemed all 40,000,000 issued and outstanding Series 15 preferred shares at a redemption price of $25.00 per share and paid the final quarterly dividend of $0.30625 per Series 15 preferred share, for the period up to but excluding May 31, 2022. The Company used the proceeds from the March 2022 issuance of US$800 million of junior subordinated notes through the Trust to finance this preferred share redemption.

OTHER COMPREHENSIVE INCOME(LOSS

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS)	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS)	OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) Components of other comprehensive income (loss), including the portion attributable to non-controlling interests and related tax effects, were as follows: year ended December 31, 2024 Before Tax Amount Income Tax (Expense) Recovery Net of Tax Amount (millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations 1,582 20 1,602 Reclassification of foreign currency translation (gains) on net investment on disposal of foreign operations 1 (25) — (25) Change in fair value of net investment hedges (23) 5 (18) Change in fair value of cash flow hedges 46 (11) 35 Reclassification to net income of (gains) losses on cash flow hedges (20) 4 (16) Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans 107 (24) 83 Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans (6) — (6) Other comprehensive income (loss) on equity investments 230 (57) 173 Other Comprehensive Income (Loss) 1,891 (63) 1,828 1 Represents the controlling and non-controlling currency translation adjustment gains related to PNGTS. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. year ended December 31, 2023 Before Tax Amount Income Tax (Expense) Recovery Net of Tax Amount (millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations (1,148) 7 (1,141) Change in fair value of net investment hedges 23 (6) 17 Reclassification to net income of (gains) losses on cash flow hedges 97 (23) 74 Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans (15) 4 (11) Other comprehensive income (loss) on equity investments (283) 72 (211) Other Comprehensive Income (Loss) (1,326) 54 (1,272) year ended December 31, 2022 Before Tax Amount Income Tax (Expense) Recovery Net of Tax Amount (millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations 1,410 84 1,494 Change in fair value of net investment hedges (48) 12 (36) Change in fair value of cash flow hedges (58) 19 (39) Reclassification to net income of (gains) losses on cash flow hedges 63 (21) 42 Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans 81 (18) 63 Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans 9 (3) 6 Other comprehensive income (loss) on equity investments 1,156 (289) 867 Other Comprehensive Income (Loss) 2,613 (216) 2,397 The changes in AOCI by component, net of tax, are as follows: (millions of Canadian $) Currency Translation Adjustments Cash Flow Hedges Pension and Other Post-Retirement Benefit Plan Adjustments Equity Investments Total AOCI balance at January 1, 2022 (1,009) (112) (113) (200) (1,434) Other comprehensive income (loss) before reclassifications 1 1,450 (39) 63 870 2,344 Amounts reclassified from AOCI — 42 6 (3) 45 Net current period other comprehensive income (loss) 1,450 3 69 867 2,389 AOCI balance at December 31, 2022 441 (109) (44) 667 955 Other comprehensive income (loss) before reclassifications 1 (231) — (11) (195) (437) Amounts reclassified from AOCI — 74 — (16) 58 Net current period other comprehensive income (loss) (231) 74 (11) (211) (379) Impact of non-controlling interest 2 (527) — — — (527) AOCI balance at December 31, 2023 (317) (35) (55) 456 49 Other comprehensive income (loss) before reclassifications 1 692 35 83 188 998 Amounts reclassified from AOCI 3,4 (15) (16) (6) (15) (52) Net current period other comprehensive income (loss) 677 19 77 173 946 Impact of non-controlling interest 5 (21) — — — (21) Impact of spinoff of Liquids Pipelines business 6 (741) — — — (741) AOCI balance at December 31, 2024 (402) (16) 22 629 233 1 Other comprehensive income(loss) before reclassifications of currency translation adjustments are net of non-controlling interest gains of $903 million (2023 – losses of $366 million; 2022 – gains of $8 million). 2 Represents the AOCI attributable to the 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf upon its sale on October 4, 2023. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 3 Gains related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $5 million ($4 million, net of tax) at December 31, 2024. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time; however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. 4 Includes the controlling interest of the AOCI attributable to PNGTS recognized in Net gain (loss) on sale of assets upon the sale of PNGTS on August 15, 2024. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 5 Represents the AOCI attributable to CFE's 13.01 per cent non-controlling equity interest in TGNH. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 6 Represents the AOCI attributable to the Spinoff Transaction. Refer to Note 4, Discontinued operations, for additional information. Details about reclassifications out of AOCI into the Consolidated statement of income were as follows: year ended December 31 Amounts reclassified from AOCI 1 Affected line item in the Consolidated statement of income 2024 2023 2022 (millions of Canadian $) Cash flow hedges Commodities 32 (85) (47) Revenues (Power and Energy Solutions) Interest rate (12) (12) (16) Interest expense 20 (97) (63) Total before tax (4) 23 21 Income tax (expense) recovery 16 (74) (42) Net of tax Pension and other post-retirement benefit plan adjustments Amortization of actuarial gains (losses) 6 — (11) Plant operating costs and other 2 Settlement gain (loss) — — 2 Plant operating costs and other 2 6 — (9) Total before tax — — 3 Income tax (expense) recovery 6 — (6) Net of tax Equity investments Equity income (loss) 19 22 4 Income (loss) from equity investments (4) (6) (1) Income tax (expense) recovery 15 16 3 Net of tax Currency translation adjustments Foreign currency translation gains on disposal of foreign operations 15 — — Net gain (loss) on sale of assets — — — Income tax (expense) recovery 15 — — Net of tax 1 Amounts in parentheses indicate expenses to the Consolidated statement of income. 2 These AOCI components are included in the computation of net benefit cost. Refer to Note 27, Employee post-retirement benefits, for additional information.

EMPLOYEE POST-RETIREMENT BENEFI

EMPLOYEE POST-RETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2024
Retirement Benefits [Abstract]
EMPLOYEE POST-RETIREMENT BENEFITS	EMPLOYEE POST-RETIREMENT BENEFITS The Company sponsors DB Plans for certain employees. Pension benefits provided under the DB Plans are generally based on years of service and highest average earnings over three five The Company's U.S. DB Plan is closed to non-union new entrants and all non-union hires participate in the DC Plan. Net actuarial gains or losses are amortized out of AOCI over the EARSL of Plan participants, which was approximately nine years at December 31, 2024 (2023 – nine years; 2022 – nine years). The Company also provides its employees with DC Plans and savings plans in Canada, DC Plans in Mexico, DC Plans consisting of a 401(k) Plan in the U.S. and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Net actuarial gains or losses for the plans are amortized out of AOCI over the EARSL of employees, which was approximately 12 years at December 31, 2024 (2023 – 12 years and 2022 – 12 years). In 2024, the Company expensed $71 million (2023 – $64 million and 2022 – $64 million) for the savings and DC Plans. As part of the Spinoff Transaction, certain TC Energy employees became employees of South Bow. Prior to the Spinoff Transaction, these employees in Canada and the U.S. participated in DB Plans, DC Plans and savings plans, as applicable. Effective October 1, 2024, the benefit obligations under the DB Plans in respect of the employees moving from TC Energy to South Bow were transferred to South Bow. An asset transfer application related to the Canadian DB Plan will be prepared in early 2025 outlining the proposed transfer of assets from TC Energy to South Bow. The Canadian DB Plan's assets to be transferred to South Bow are subject to regulatory approval and will be transferred when approval is received. As at December 31, 2024, these assets remain in the TC Energy DB Plan trust and have been reflected as Long-term assets of discontinued operations and a corresponding obligation to South Bow has been reflected as Long-term liabilities of discontinued operations on the Consolidated balance sheet. The assets related to the U.S. DB Plan were fully transferred to South Bow as at December 31, 2024. Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2024 2023 2022 (millions of Canadian $) DB Plans — 28 78 Other post-retirement benefit plans 8 9 8 Savings and DC Plans 71 64 64 79 101 150 Current Canadian pension legislation allows for partial funding of solvency requirements over a number of years through letters of credit in lieu of cash contributions, up to certain limits. Total letters of credit provided to the Canadian DB plan at December 31, 2024 was $111 million (2023 – $244 million; 2022 – $322 million). The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2024 and the next required valuation is at January 1, 2025. The Company's funded status was comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2024 2023 2024 2023 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,356 3,081 285 310 Service cost 108 93 1 3 Interest cost 160 158 14 16 Employee contributions 11 7 2 2 Benefits paid (194) (185) (24) (44) Actuarial (gain) loss (39) 219 (5) 2 South Bow - transition of benefit obligation 2 (118) — (1) — Foreign exchange rate changes 58 (17) 16 (4) Benefit obligation – end of year 3,342 3,356 288 285 Change in Plan Assets Plan assets at fair value – beginning of year 3,697 3,481 358 354 Actual return on plan assets 485 385 17 24 Employer contributions 3,4 — 28 (41) 9 Employee contributions 11 7 2 2 Benefits paid (194) (185) (25) (23) South Bow - transition of plan assets 2 (119) — — — Foreign exchange rate changes 68 (19) 28 (8) Plan assets at fair value – end of year 3,948 3,697 339 358 Funded Status – Plan Surplus 606 341 51 73 1 The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation. 2 Reflects the impact of the Spinoff Transaction of the Liquids Pipelines business on October 1, 2024. 3 The Company reduced letters of credit by $133 million in the Canadian DB Plan (2023 – $78 million) for funding purposes. 4 OPEB surplus of $49 million was transferred to pay future active employee medical expenses. Additional pension benefit plan assets were as follows: at December 31 Pension (millions of Canadian $) 2024 2023 TC Energy plan assets at fair value 3,948 3,697 South Bow plan assets held in trust 1 110 — Plan assets at fair value – end of year 4,058 3,697 1 Related to the transfer of pension assets to South Bow. The final transfer will be adjusted for investment returns and benefit payments from October 1, 2024 to the transfer date. The $110 million is reflected in Long-term assets of discontinued operations. The actuarial gain realized on the defined benefit plan obligation is primarily attributable to an increase in the weighted average discount rate from 4.75 per cent in 2023 to 4.90 per cent in 2024. The actuarial gain realized on the OPEB Plan obligation is primarily due to an increase in the weighted average discount rate from 5.10 per cent in 2023 to 5.45 per cent in 2024. The amounts recognized on the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans were as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2024 2023 2024 2023 Other long-term assets (Note 15) 606 341 152 177 Accounts payable and other — — (7) (7) Other long-term liabilities (Note 18) — — (94) (97) 606 341 51 73 Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that were not fully funded: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2024 2023 2024 2023 Projected benefit obligation 1 — — (101) (104) Plan assets at fair value — — — — Funded Status – Plan Deficit — — (101) (104) 1 The projected benefit obligation for the pension benefit plans differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels. The funded status based on the accumulated benefit obligation for all DB Plans was as follows: at December 31 2024 2023 (millions of Canadian $) Accumulated benefit obligation (3,097) (3,090) Plan assets at fair value 1 4,058 3,697 Funded Status – Plan Surplus 961 607 1 Includes an estimated $110 million for future transfer to South Bow. The final transfer will be adjusted for investment returns and benefit payments from October 1, 2024, the date of the Spinoff Transaction to the transfer date. The Company's DB Plans with respect to accumulated benefit obligations and the fair value of plan assets were fully funded as at December 31, 2024 and December 31, 2023. The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: at December 31 Percentage of Target Allocations 2024 2023 2024 Fixed income securities 37 % 41 % 25% to 50% Equity securities 49 % 44 % 25% to 55% Other investments 14 % 15 % 10% to 35% 100 % 100 % Fixed income and equity securities include the Company's and its related parties debt and common shares as follows: at December 31 Percentage of (millions of Canadian $) 2024 2023 2024 2023 Fixed income securities 44 7 1.1 % 0.2 % Equity securities 3 2 0.1 % 0.1 % Pension plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset classes to maximize returns at an acceptable level of risk. Asset mix strategies consider plan demographics and may include traditional equity and debt securities as well as alternative assets such as infrastructure, private equity, real estate and derivatives to diversify risk. Derivatives are not used for speculative purposes and may be used to hedge certain liabilities. All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by reference to generally available price quotations, the fair value is determined by considering the discounted cash flows on a risk-adjusted basis and by comparison to similar assets which are publicly traded. In Level I, the fair value of assets is determined by reference to quoted prices in active markets for identical assets that the Company has the ability to access at the measurement date. In Level II, the fair value of assets is determined using valuation techniques such as option pricing models and extrapolation using significant inputs which are observable directly or indirectly. In Level III, the fair value of assets is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. The following table presents plan assets for DB Plans and OPEB Plans measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. Refer to Note 28, Risk management and financial instruments, for additional information. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2024 2023 2024 2023 2024 2023 2024 2023 2024 2023 Asset Category 1 Cash and Cash Equivalents 138 68 — 1 — — 138 69 3 2 Equity Securities: Canadian 128 121 — — — — 128 121 3 3 U.S. 1,234 965 — — — — 1,234 965 28 24 International 182 167 209 187 — — 391 354 9 9 Global — — 100 74 — — 100 74 2 2 Emerging 66 54 150 140 — — 216 194 5 5 Fixed Income Securities: Canadian Bonds: Federal — — 55 266 — — 55 266 1 7 Provincial — — 312 314 — — 312 314 7 8 Municipal — — 14 16 — — 14 16 — — Corporate — — 323 143 — — 323 143 7 4 U.S. Bonds: Federal 151 185 255 240 — — 406 425 9 10 Municipal — — 1 1 — — 1 1 — — Corporate 246 312 158 74 — — 404 386 9 10 International: Government 4 4 17 11 — — 21 15 1 — Corporate — — 66 83 — — 66 83 2 2 Mortgage backed 37 43 23 17 — — 60 60 1 1 Net forward contracts — — (201) (131) — — (201) (131) (4) (4) Other Investments: Real estate — — — — 276 283 276 283 6 7 Infrastructure — — — — 282 269 282 269 7 7 Private equity funds — — — — 32 10 32 10 1 — Funds held on deposit 138 138 — — — — 138 138 3 3 Derivatives — — 1 — — — 1 — — — 2,324 2,057 1,483 1,436 590 562 4,397 4,055 100 100 1 Includes an estimated $110 million for future transfer to South Bow. The final transfer will be adjusted for investment returns and benefit payments from October 1, 2024, the date of the Spinoff Transaction to the transfer date. The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Balance at December 31, 2022 632 Purchases and sales (76) Realized and unrealized gains (losses) 6 Balance at December 31, 2023 562 Purchases and sales (15) Realized and unrealized gains (losses) 43 Balance at December 31, 2024 590 In 2025, the Company's expects to make funding contributions of $6 million for the other post-retirement benefit plans, approximately $71 million for the savings plans and DC Plans and no contributions for the DB Plans. The Company is not expecting to issue any additional letters of credit for the funding of solvency requirements to the Canadian DB plan in 2025. The following are estimated future benefit payments, which reflect expected future service: at December 31 Other Post-Retirement Benefits (millions of Canadian $) Pension Benefits 2025 209 24 2026 212 24 2027 216 24 2028 218 24 2029 221 23 2030 to 2034 1,139 110 The rate used to discount pension and other post-retirement benefit plan obligations was developed based on a yield curve of primarily corporate AA bond yields at December 31, 2024. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement benefit obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate. The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows: at December 31 Pension Other Post-Retirement 2024 2023 2024 2023 Discount rate 4.90 % 4.75 % 5.45 % 5.10 % Rate of compensation increase 3.05 % 3.20 % — — The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows: year ended December 31 Pension Other Post-Retirement 2024 2023 2022 2024 2023 2022 Discount rate 4.75 % 5.15 % 3.05 % 5.15 % 5.45 % 3.10 % Expected long-term rate of return on plan assets 6.60 % 6.45 % 6.10 % 4.50 % 4.50 % 3.25 % Rate of compensation increase 3.15 % 3.25 % 3.00 % — — — The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns and asset mix are also considered in determining the overall expected rate of return. The discount rate is based on market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan. A 6.15 per cent weighted-average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2025 measurement purposes. The rate was assumed to decrease gradually to 4.85 per cent by 2032 and remain at this level thereafter. The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans was as follows: year ended December 31 Pension Other Post-Retirement (millions of Canadian $) 2024 2023 2022 2024 2023 2022 Service cost 1 108 93 145 1 3 5 Other components of net benefit cost 1 Interest cost 160 158 125 14 16 13 Expected return on plan assets (248) (234) (239) (14) (16) (14) Amortization of actuarial loss — — 10 — — 1 Amortization of regulatory asset — — 12 (2) — 1 Settlement gain – AOCI — — (2) — — — (88) (76) (94) (2) — 1 Net Benefit Cost Recognized 20 17 51 (1) 3 6 1 Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income. Pre-tax amounts recognized in AOCI were as follows: at December 31 2024 2023 2022 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Net loss (gain) (24) — 71 6 38 24 Pre-tax amounts recognized in OCI were as follows: year ended December 31 2024 2023 2022 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Amortization of net gain (loss) from AOCI to net income 6 — — — (10) (1) Settlement — — — — 2 — Funded status adjustment (101) (6) 33 (18) (101) 20 (95) (6) 33 (18) (109) 19 In 2022, a settlement occurred for the U.S. DB Plan as a result of lump sum payments made during the year. The impact of the settlement was determined using actuarial assumptions consistent with those employed at December 31, 2022. The settlement gain decreased the U.S. DB Plan's unrealized actuarial gain by $2 million which was included in OCI, and was recorded in net benefit cost in 2022.

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2024
Risk Management and Financial Instruments [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Risk Management Overview TC Energy has exposure to various financial risks and has strategies, policies and limits in place to manage the impact of these risks on its earnings, cash flows and, ultimately, shareholder value. Risk management strategies, policies and limits are designed to ensure TC Energy's risks and related exposures are in line with the Company's business objectives and risk tolerance. TC Energy's risks are managed within limits that are established by the Company's Board, implemented by senior management and monitored by the Company's risk management, internal audit and business segment groups. The Board's Audit Committee oversees how management monitors compliance with risk management policies and procedures and oversees management's review of the adequacy of the risk management framework. Market Risk The Company constructs and invests in energy infrastructure projects, purchases and sells commodities, issues short- and long‑term debt, including amounts in foreign currencies and invests in foreign operations. Certain of these activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the Company's earnings, cash flows and the value of its financial assets and liabilities. The Company assesses contracts used to manage market risk to determine whether all, or a portion, meets the definition of a derivative. Derivative contracts the Company uses to assist in managing exposure to market risk may include the following: • forwards and futures contracts – agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future • swaps – agreements between two parties to exchange streams of payments over time according to specified terms • options – agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. Commodity price risk The following strategies may be used to manage the Company's exposure to market risk resulting from commodity price risk management activities in the Company's non-regulated businesses: • in the Company's natural gas marketing business, TC Energy enters into natural gas transportation and storage contracts as well as natural gas purchase and sale agreements. The Company manages exposure on these contracts using financial instruments and hedging activities to offset market price volatility • in the Company's power businesses, TC Energy manages the exposure to fluctuating commodity prices through long-term contracts and hedging activities including selling and purchasing electricity and natural gas in forward markets • in the Company's non-regulated natural gas storage business, TC Energy's exposure to seasonal natural gas price spreads is managed with a portfolio of third-party storage capacity contracts and through offsetting purchases and sales of natural gas in forward markets to lock in future positive margins. Lower natural gas and electricity prices could lead to reduced investment in the development, expansion and production of these commodities. A reduction in the demand for these commodities could negatively impact opportunities to expand the Company's asset base and/or re-contract with TC Energy's shippers and customers as contractual agreements expire. Physical and transition risks The physical and transition risks related to climate change could impact commodity prices and fossil fuel supply and demand dynamics which could affect the Company's financial performance. TC Energy evaluates the financial resilience of its asset portfolio against a range of future pricing and supply and demand outcomes as part of its strategic planning process. TC Energy’s exposure to climate change-related transition risks and resulting policy changes is managed through its business model, which is based on a long-term, low-risk strategy whereby the majority of TC Energy’s earnings are underpinned by regulated cost-of-service arrangements and/or long-term contracts. The Company factors physical and transition risks into capital planning, financial risk management and operational activities and is working towards reducing the GHG emissions intensity of existing operations. Interest rate risk TC Energy utilizes short- and long-term debt to finance its operations which exposes the Company to interest rate risk. TC Energy typically pays fixed rates of interest on its long-term debt and floating rates on short-term debt including its commercial paper programs and amounts drawn on its credit facilities. A small portion of TC Energy's long-term debt bears interest at floating rates. In addition, the Company is exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. The Company actively manages its interest rate risk using interest rate derivatives. Foreign exchange risk Certain of TC Energy's businesses generate all or most of their earnings in U.S. dollars and, since the Company reports its financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect its net income. This exposure grows as the Company's U.S. dollar-denominated operations grow. A portion of this risk is offset by interest expense on U.S. dollar-denominated debt. The balance of the exposure is actively managed on a rolling basis up to three years in advance using foreign exchange derivatives; however, the natural exposure beyond that period remains. A portion of the Company's Mexico Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while TC Energy's Mexico operations' financial results are denominated in U.S. dollars. These peso‑denominated balances are revalued to U.S. dollars and, as a result, changes in the value of the Mexican peso against the U.S. dollar can affect the Company's net income. In addition, foreign exchange gains or losses calculated for Mexico income tax purposes on the revaluation of U.S. dollar‑denominated monetary assets and liabilities result in a peso‑denominated income tax exposure for these entities, leading to fluctuations in Income (loss) from equity investments and Income tax expense (recovery). These exposures are actively managed using foreign exchange derivatives, although some unhedged exposure remains. Net investment in foreign operations The Company hedges a portion of its net investment in foreign operations (on an after-tax basis) with U.S. dollar‑denominated debt, cross-currency interest rate swaps and foreign exchange options as appropriate. The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows: at December 31 2024 2023 Fair 1,2 Notional Amount Fair 1,2 Notional Amount (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2025) 3 (11) US 100 2 US 200 U.S. dollar foreign exchange options — — 8 US 1,000 (11) US 100 10 US 1,200 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2024 and 2023, Net income (loss) included net realized gains of less than $1 million related to the interest component of cross-currency swap settlements which are reported within Interest expense. The notional amounts and fair values of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2024 2023 (millions of Canadian $, unless otherwise noted) Notional amount 26,000 (US 18,000) 27,800 (US 21,100) Fair value 25,700 (US 17,800) 26,600 (US 20,200) Counterparty Credit Risk TC Energy's exposure to counterparty credit risk includes its cash and cash equivalents, accounts receivable, available-for-sale assets, the fair value of derivative assets, net investment in leases and certain contract assets in Mexico. At times, the Company's counterparties may endure financial challenges resulting from commodity price and market volatility, economic instability and political or regulatory changes. In addition to actively monitoring these situations, there are a number of factors that reduce TC Energy's counterparty credit risk exposure in the event of default, including: • contractual rights and remedies together with the utilization of contractually-based financial assurances • current regulatory frameworks governing certain TC Energy operations • the competitive position of the Company's assets and the demand for the Company's services • potential recovery of unpaid amounts through bankruptcy and similar proceedings. The Company reviews financial assets carried at amortized cost for impairment using the lifetime expected loss of the financial asset at initial recognition and throughout the life of the financial asset. TC Energy uses historical credit loss and recovery data, adjusted for management's judgment regarding current economic and credit conditions, along with reasonable and supportable forecasts to determine any impairment, which is recognized in Plant operating costs and other. The Company’s net investment in leases and certain contract assets are financial assets subject to ECL. TC Energy’s methodology for assessing the ECL regarding these financial assets includes consideration of the probability of default (the probability that the customer will default on its obligation), the loss given default (the economic loss as a proportion of the financial asset balance in the event of a default) and the exposure at default (the financial asset balance at the time of a hypothetical default) with one‑year forward-looking information that includes assumptions for future macroeconomic conditions under three probability‑weighted future scenarios. The macroeconomic factors considered most relevant to the Company's net investment in leases and contract assets include Mexico's GDP, Mexico's government debt to GDP and Mexico's inflation. The ECL amount is updated at each reporting date to reflect changes in assumptions and forecasts for future economic conditions. For the year ended December 31, 2024, the Company recorded a $23 million ECL recovery (2023 – $73 million recovery; 2022 ‑ $149 million expense) with respect to the net investment in leases associated with the in-service TGNH pipelines and $1 million ECL expense (2023 – $10 million recovery; 2022 – $14 million expense) for contract assets related to certain other Mexico natural gas pipelines. Other than the ECL provision noted above, the Company had no significant credit losses at December 31, 2024 and 2023. At December 31, 2024 and 2023, there were no significant credit risk concentrations and no significant amounts past due or impaired. TC Energy has significant credit and performance exposure to financial institutions that hold cash deposits and provide committed credit lines and letters of credit that help manage the Company's exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets. TC Energy's portfolio of financial sector exposure consists primarily of highly-rated investment grade, systemically important financial institutions. Non-Derivative Financial Instruments Fair value of non-derivative financial instruments Available-for-sale assets are recorded at fair value which is calculated using quoted market prices where available including the Company's LMCI equity securities which are classified in Level I of the fair value hierarchy. Certain other non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Other current assets, Net investment in leases, Restricted investments, Other long-term assets, Notes payable, Accounts payable and other, Dividends payable, Accrued interest and Other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity. Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments. Balance sheet presentation of non-derivative financial instruments The following table details the fair value of non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy: at December 31 2024 2023 Carrying Amount Fair Value Carrying Fair (millions of Canadian $) Long-term debt, including current portion (Note 20) 1,2 (47,931) (48,318) (52,914) (52,815) Junior subordinated notes (Note 21) (11,048) (10,824) (10,287) (9,217) (58,979) (59,142) (63,201) (62,032) 1 Long-term debt is recorded at amortized cost, except for US$2.8 billion (2023 – US$2.0 billion) that is attributed to hedged risk and recorded at fair value. 2 Net income (loss) for 2024 included unrealized gains of $128 million (2023 – unrealized losses of $53 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships. Available-for-sale assets summary The following tables summarize additional information about the Company's restricted investments that were classified as available-for-sale assets: at December 31 2024 2023 LMCI Restricted Investments Other Restricted Investments 1 LMCI Restricted Investments Other Restricted Investments 1 (millions of Canadian $) Fair value of fixed income securities 2,3 Maturing within 1 year — 33 — 35 Maturing within 1-5 years 3 256 8 241 Maturing within 5-10 years 1,578 — 1,340 — Fair value of equity securities 2,4 1,070 64 883 50 2,651 353 2,231 326 1 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. 2 Available-for-sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet. 3 Classified in Level II of the fair value hierarchy. 4 Classified in Level I of the fair value hierarchy. year ended December 31 2024 2023 2022 (millions of Canadian $) LMCI Restricted Investments 1 Other Restricted Investments 2 LMCI Restricted Investments 1 Other Restricted Investments 2 LMCI Restricted Investments 1 Other Restricted Investments 2 Net unrealized gains (losses) 218 9 179 13 (223) (7) Net realized gains (losses) 3 3 2 (28) — (28) — 1 Unrealized and realized gains (losses) arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory liabilities or regulatory assets. 2 Unrealized and realized gains (losses) on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income. 3 Realized gains (losses) on the sale of LMCI restricted investments are determined using the average cost basis. Derivative Instruments Fair value of derivative instruments The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year‑end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments. Unrealized gains and losses on derivative instruments are not necessarily representative of the amounts that will be realized on settlement. In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period. The recognition of gains and losses on derivatives for Canadian natural gas regulated pipeline exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are expected to be refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory liabilities or regulatory assets and are refunded to or collected from the rate payers in subsequent years when the derivative settles. Balance sheet presentation of derivative instruments The balance sheet classification of the fair value of derivative instruments was as follows: at December 31, 2024 Cash Flow Hedges Fair Value Hedges Net Held for Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 8) Commodities 2 18 — — 287 305 Foreign exchange — — — 42 42 18 — — 329 347 Other long-term assets (Note 15) Commodities 2 9 — — 104 113 Foreign exchange — — — 9 9 9 — — 113 122 Total Derivative Assets 27 — — 442 469 Accounts payable and other (Note 17) Commodities 2 (1) — — (291) (292) Foreign exchange — — (11) (183) (194) Interest rate — (21) — — (21) (1) (21) (11) (474) (507) Other long-term liabilities (Note 18) Commodities 2 (1) — — (46) (47) Foreign exchange — — — (44) (44) Interest rate — (118) — — (118) (1) (118) — (90) (209) Total Derivative Liabilities (2) (139) (11) (564) (716) Total Derivatives 25 (139) (11) (122) (247) 1 Fair value equals carrying value. 2 Includes purchases and sales of power and natural gas. The balance sheet classification of the fair value of derivative instruments was as follows: at December 31, 2023 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 8) Commodities 2 9 — — 499 508 Foreign exchange — — 10 71 81 9 — 10 570 589 Other long-term assets (Note 15) Commodities 2 3 — — 86 89 Foreign exchange — — — 30 30 Interest rate — 36 — — 36 3 36 — 116 155 Total Derivative Assets 12 36 10 686 744 Accounts payable and other (Note 17) Commodities 2 (1) — — (382) (383) Foreign exchange — — — (14) (14) Interest rate — (18) — — (18) (1) (18) — (396) (415) Other long-term liabilities (Note 18) Commodities 2 — — — (75) (75) Foreign exchange — — — (2) (2) Interest rate — (29) — — (29) — (29) — (77) (106) Total Derivative Liabilities (1) (47) — (473) (521) Total Derivatives 11 (11) 10 213 223 1 Fair value equals carrying value. 2 Includes purchases and sales of power and natural gas. The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk. Derivatives in fair value hedging relationships The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities: at December 31 Carrying Amount Fair Value Hedging Adjustments 1 (millions of Canadian $) 2024 2023 2024 2023 Long-term debt (3,935) (2,630) 98 11 1 At December 31, 2024, adjustments for discontinued hedging relationships included in this balance was a liability of $41 million (2023 – nil). Notional and maturity summary The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations was as follows: at December 31, 2024 Power Natural Gas Foreign Exchange Interest Rate Net sales 1 10,192 53 — — Millions of U.S. dollars — — 5,648 2,800 Millions of Mexican pesos — — 16,750 — Maturity dates 2025-2044 2025-2031 2025-2027 2030-2034 1 Volumes for power and natural gas derivatives are in GWh and Bcf, respectively. at December 31, 2023 Power Natural Gas Foreign Exchange Interest Rate Net sales 1 9,209 50 — — Millions of U.S. dollars — — 4,978 2,000 Millions of Mexican pesos — — 20,000 — Maturity dates 2024-2044 2024-2029 2024-2026 2030-2034 1 Volumes for power and natural gas derivatives are in GWh and Bcf, respectively. Unrealized and Realized Gains (Losses) on Derivative Instruments The following summary does not include hedges of the net investment in foreign operations: year ended December 31 2024 2023 2022 (millions of Canadian $) Derivative Instruments Held for Trading 1 Unrealized gains (losses) in the year Commodities 2 (71) 132 (11) Foreign exchange (Note 22) (266) 246 (149) Interest rate (71) — — Realized gains (losses) in the year Commodities 199 192 46 Foreign exchange (Note 22) (152) 155 (2) Interest rate 29 — — Derivative Instruments in Hedging Relationships Realized gains (losses) in the year Commodities 33 (2) (73) Interest rate (52) (43) (3) 1 Realized and unrealized gains (losses) on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues in the Consolidated statement of income. Realized and unrealized gains (losses) on foreign exchange held-for-trading derivative instruments are included on a net basis in Foreign exchange (gains) losses, net in the Consolidated statement of income. Realized and unrealized gains (losses) on interest rate derivatives are included on a net basis in Interest expense in the Consolidated statement of income. 2 In 2024, unrealized gains of $6 million were reclassified to Net Income (loss) from AOCI related to discontinued cash flow hedges (2023 and 2022 – nil). Derivatives in cash flow hedging relationships The components of OCI (Note 26) related to the change in fair value of derivatives in cash flow hedging relationships before tax and including the portion attributable to non-controlling interests were as follows: year ended December 31 2024 2023 2022 (millions of Canadian $, pre-tax) Gains (losses) in fair value of derivative instruments recognized in OCI 1 Commodities 46 — (94) Interest rate — — 36 46 — (58) 1 No amounts have been excluded from the assessment of hedge effectiveness. Effect of fair value and cash flow hedging relationships The following table details amounts presented in the Consolidated statement of income in which the effects of fair value or cash flow hedging relationships were recorded: year ended December 31 2024 2023 2022 (millions of Canadian $) Fair Value Hedges Interest rate contracts 1 Hedged items (126) (98) (30) Derivatives designated as hedging instruments (52) (43) (1) Cash Flow Hedges Reclassification of gains (losses) on derivative instruments from AOCI to Net income (loss) 2,3 Commodities 4 32 (85) (47) Interest rate 1 (12) (12) (16) 1 Presented within Interest expense in the Consolidated statement of income. 2 Refer to Note 26, Other comprehensive income (loss) and accumulated other comprehensive income (loss), for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests. 3 There are no amounts recognized in earnings that were excluded from effectiveness testing. 4 Presented within Revenues (Power and Energy Solutions) in the Consolidated statement of income. In 2024, unrealized gains of $6 million were reclassified to Net Income (loss) from AOCI related to discontinued cash flow hedges (2023 and 2022– nil). Offsetting of derivative instruments The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TC Energy has no master netting agreements; however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis on the Consolidated balance sheet. The following tables show the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: at December 31, 2024 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 418 (290) 128 Foreign exchange 51 (49) 2 469 (339) 130 Derivative Instrument Liabilities Commodities (339) 290 (49) Foreign exchange (238) 49 (189) Interest rate (139) — (139) (716) 339 (377) 1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2023 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 597 (418) 179 Foreign exchange 111 (16) 95 Interest rate 36 (5) 31 744 (439) 305 Derivative Instrument Liabilities Commodities (458) 418 (40) Foreign exchange (16) 16 — Interest rate (47) 5 (42) (521) 439 (82) 1 Amounts available for offset do not include cash collateral pledged or received. With respect to the derivative instruments presented above, the Company provided cash collateral of $133 million and letters of credit of $59 million at December 31, 2024 (2023 – $57 million and $83 million, respectively) to its counterparties. At December 31, 2024, the Company held less than $1 million in cash collateral and $75 million in letters of credit (2023 – less than $1 million and $12 million, respectively) from counterparties on asset exposures. Credit-risk-related contingent features of derivative instruments Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. The Company may also need to provide collateral if the fair value of its derivative financial instruments exceeds pre-defined exposure limits. Based on contracts in place and market prices at December 31, 2024, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $10 million (2023 – $3 million), for which the Company has provided no collateral in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on December 31, 2024, the Company would have been required to provide collateral equal to the fair value of the related derivative instruments discussed above. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving credit facilities to meet these contingent obligations should they arise. Fair Value Hierarchy The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy. Levels How Fair Value Has Been Determined Level I Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date. An active market is a market in which frequency and volume of transactions provides pricing information on an ongoing basis. Level II This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. Level III This category includes long-dated commodity transactions in certain markets where liquidity is low. The Company uses the most observable inputs available or alternatively long-term broker quotes or negotiated commodity prices that have been contracted for under similar terms in determining an appropriate estimate of these transactions. Where appropriate, these long-dated prices are discounted to reflect the expected pricing from the applicable markets. There is uncertainty caused by using unobservable market data which may not accurately reflect possible future changes in fair value. The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non‑current portions, were categorized as follows: at December 31, 2024 Quoted Prices in Active Markets Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets Commodities 126 214 78 418 Foreign exchange — 51 — 51 Derivative Instrument Liabilities Commodities (116) (217) (6) (339) Foreign exchange — (238) — (238) Interest rate — (139) — (139) 10 (329) 72 (247) 1 There were no transfers from Level II to Level III for the year ended December 31, 2024. The Company has entered into contracts to sell 50 MW of power commencing in 2025 with terms ranging from 15 to 20 years provided from specified renewable sources in the Province of Alberta. The fair value of these contracts is classified in Level III of the fair value hierarchy and is based on the assumption that the contract volumes will be sourced approximately 80 per cent from wind generation, 10 per cent from solar generation and 10 per cent from the market. at December 31, 2023 Quoted Prices in Active Markets (Level I) Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets Commodities 387 200 10 597 Foreign exchange — 111 — 111 Interest rate — 36 — 36 Derivative Instrument Liabilities Commodities (307) (130) (21) (458) Foreign exchange — (16) — (16) Interest rate — (47) — (47) 80 154 (11) 223 1 There were no transfers from Level II to Level III for the year ended December 31, 2023. The following table presents the net change in fair value of derivative assets and liabilities classified in Level III of the fair value hierarchy: (millions of Canadian $, pre-tax) 2024 2023 Balance at beginning of year (11) (11) Net gains (losses) included in Net income (loss) 54 (2) Transfers to Level II 29 2 Balance at End of Year 1 72 (11) 1 Revenues .

CHANGES IN OPERATING WORKING CA

CHANGES IN OPERATING WORKING CAPITAL	12 Months Ended
	Dec. 31, 2024
CHANGES IN OPERATING WORKING CAPITAL
CHANGES IN OPERATING WORKING CAPITAL	CHANGES IN OPERATING WORKING CAPITAL year ended December 31 2024 ¹ 2023 ¹ 2022 ¹ (millions of Canadian $) (Increase) decrease in Accounts receivable (13) (394) (575) (Increase) decrease in Inventories (16) (56) (190) (Increase) decrease in Other current assets (97) 618 118 Increase (decrease) in Accounts payable and other 365 (206) (83) Increase (decrease) in Accrued interest (40) 245 91 (Increase) Decrease in Operating Working Capital 199 207 (639) 1 Includes continuing and discontinued operations.

STRATEGIC ALLIANCE, ACQUISITION

STRATEGIC ALLIANCE, ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2024
Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]
STRATEGIC ALLIANCE, ACQUISITIONS AND DISPOSITIONS	STRATEGIC ALLIANCE, ACQUISITIONS AND DISPOSITIONS U.S. Natural Gas Pipelines Portland Natural Gas Transmission System (PNGTS) In August 2024, the Company and its partner, Northern New England Investment Company, Inc., a subsidiary of Énergir L.P. (Énergir), completed the sale of PNGTS to a third party for a gross purchase price of approximately $1.6 billion (US$1.1 billion), including the third party's assumption of US$250 million of senior notes outstanding at PNGTS, split pro-rata according to the PNGTS ownership interests (TC Energy – 61.7 per cent, Énergir – 38.3 per cent). The Company's share of the proceeds was $743 million (US$546 million), net of transaction costs. The pre-tax gain attributable to the Company of $572 million (US$408 million) was included in Net gain (loss) on sale of assets in the Consolidated statement of income, and the after-tax gain attributable to the Company was $456 million (US$323 million). The gain includes foreign currency translation gains of $15 million which were reclassified from AOCI to Net income (loss). TC Energy is providing customary transition services and will continue to work jointly with the purchaser to facilitate a safe and orderly transition. Columbia Gas and Columbia Gulf In October 2023, TC Energy completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf to Global Infrastructure Partners (GIP) for proceeds of $5.3 billion (US$3.9 billion). The Company continues to have a controlling interest in these companies and will remain the operator of the pipelines. TC Energy and GIP will each fund their proportionate share of annual maintenance, modernization and sanctioned growth capital expenditures through internally generated cash flows, debt financing within the Columbia entities, or from proportionate contributions from TC Energy and GIP. The sale was accounted for as an equity transaction of which $9.5 billion (US$6.9 billion) was recorded as non-controlling interests to reflect the 40 per cent change in the Company’s ownership interest in Columbia Gulf and Columbia Gas. The difference between the non-controlling ownership interest recognized and the consideration received was recorded as a reduction to Additional paid-in capital of $3.5 billion (US$3.0 billion), net of tax and transaction costs. At December 31, 2024, as part of the contingent consideration included in the sale, TC Energy accrued a one-time special distribution to GIP of $33 million (US$23 million), or $24 million (US$17 million) net of tax, in Additional paid-in capital. Mexico Natural Gas Pipelines Transportadora de Gas Natural de la Huasteca In second quarter 2024, in accordance with the terms of the Company's strategic alliance, and in exchange for cash and non-cash consideration of $561 million (US$411 million), the CFE became a partner in TGNH with a 13.01 per cent equity interest in TGNH. The transaction was accounted for as an equity transaction of which $588 million was recognized as non-controlling interests and $21 million was recognized as AOCI attributable to the CFE’s non-controlling interest. The difference between these amounts and the consideration received was recorded as a reduction to Additional paid-in capital of $27 million. Power and Energy Solutions Texas Wind Farms In the first half of 2023, TC Energy acquired 100 per cent of the Class B Membership Interests in Fluvanna Wind Farm (Fluvanna) and Blue Cloud Wind Farm (Blue Cloud), respectively. Each of these operating assets has a tax equity investor which owns 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes and cash flows are allocated. The tax equity investors' interests were recorded as non-controlling interests at their aggregate estimated fair value of $222 million (US$167 million). TC Energy has determined that the use of the Hypothetical Liquidation at Book Value (HLBV) method of allocating earnings between the Company and the tax equity investors is appropriate as the earnings, tax attributes and cash flows from Fluvanna and Blue Cloud are allocated to its Class A and Class B Membership Interest owners on a basis other than ownership percentages. Using the HLBV method, the Company's earnings from the projects is calculated based on how the projects would allocate and distribute cash if the net assets were sold at their carrying amounts on the reporting date under the provisions of the tax equity agreements. TC Energy determined it has a controlling financial interest in both projects and has consolidated the acquired entities as voting interest entities. The tax equity investors’ interests were recorded as non-controlling interests at their estimated fair values of $106 million (US$80 million) for Fluvanna and $116 million (US$87 million) for Blue Cloud. These transactions are accounted for as asset acquisitions and therefore did not result in the recognition of goodwill.

COMMITMENTS, CONTINGENCIES AND

COMMITMENTS, CONTINGENCIES AND GUARANTEES	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, CONTINGENCIES AND GUARANTEES	COMMITMENTS, CONTINGENCIES AND GUARANTEES Commitments TC Energy and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business. Purchases under these contracts in 2024 were $347 million (2023 – $335 million; 2022 – $314 million). The Company has entered into PPAs with solar and wind-power generating facilities ranging from 2025 to 2038 that require the purchase of generated energy and associated environmental attributes. At December 31, 2024, the total planned capacity secured under the PPAs is approximately 750 MW with the generation subject to operating availability and capacity factors. These PPAs do not meet the definition of a lease or derivative. Future payments and their timing cannot be reasonably estimated as they are dependent on when certain underlying facilities are placed into service and the amount of energy generated. Certain of these purchase commitments have offsetting sale PPAs for all or a portion of the related output from the facility. Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts. At December 31, 2024, TC Energy had approximately $1.1 billion of capital expenditure commitments, primarily consisting of: • $0.4 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with ANR and other pipeline projects • $0.3 billion for its Canadian natural gas pipelines related to construction costs associated with the Valhalla North and Berland River projects. Contingencies TC Energy is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2024, the Company had accrued approximately $8 million (2023 – $19 million) related to operating facilities, which represents the present value of the estimated future amount it expects to spend to remediate the sites. However, additional liabilities may be incurred as assessments take place and remediation efforts continue. TC Energy and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. The Company assesses all legal matters on an ongoing basis, including those of its equity investments, to determine if they meet the requirements for disclosure or accrual of a contingent loss. With the potential exception of the matters discussed below, it is the opinion of management that the ultimate resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations. The claims discussed below are material and there is a reasonable possibility of loss; however, they have not been assessed as probable and a reasonable estimate of loss cannot be made. Coastal GasLink LP Coastal GasLink LP is in dispute with a number of contractors related to construction of the Coastal GasLink pipeline. Material legal matters pertaining to Coastal GasLink are summarized as follows: Pacific Atlantic Pipeline Construction Ltd. Coastal GasLink LP is in arbitration with one of its previous prime contractors, Pacific Atlantic Pipeline Construction Ltd. (PAPC). Coastal GasLink LP terminated its contract with PAPC for cause, due to the failure of PAPC to complete work as scheduled and made a demand on the parental guarantee for payment of the guaranteed obligations. Following Coastal GasLink LP’s demand on the guarantee, in August 2022, PAPC initiated arbitration. As of December 31, 2024, PAPC purports to seek at least $460 million in damages for wrongful termination for cause, termination damages and payments alleged to be outstanding. Coastal GasLink LP disputes the merits of PAPC’s claims and has counterclaimed against PAPC and its parent company and guarantor, Bonatti S.p.A., citing delays and failures by PAPC to perform and manage work in accordance with the terms of its contract. Coastal GasLink LP estimates its damages to be $1.3 billion. PAPC and Bonatti S.p.A. dispute Coastal GasLink LP's claims and assert that Coastal GasLink LP's damages, if any, are subject to a contractual limit of approximately $220 million. The hearing previously scheduled to commence in November 2024 has now been rescheduled to third quarter 2025. At December 31, 2024, the final outcome of this matter cannot be reasonably estimated. Separately, Coastal GasLink LP has drawn on a $117 million irrevocable standby letter of credit (LOC) provided by PAPC based on a bona fide belief that Coastal GasLink LP’s damages are in excess of the face value of the LOC. PAPC applied for an injunction restraining Coastal GasLink LP from drawing on the LOC pending the completion of the arbitration between Coastal GasLink LP, PAPC and Bonatti S.p.A., but was unsuccessful. Coastal GasLink LP is now able to use the recovered LOC funds. PAPC and Bonatti S.p.A. have amended their original claims to seek additional damages in relation to the draw on the LOC. The amount claimed has not been articulated beyond the $117 million. The parties have agreed that the issue of damages arising from Coastal GasLink LP's draw on the LOC will be determined, if necessary, at a date subsequent to the arbitration hearing noted above. Macro Spiecapag Coastal GasLink Joint Venture Coastal GasLink LP is in arbitration with its former prime contractor, Macro Spiecapag Coastal GasLink Joint Venture (MSJV). In May 2021, Coastal GasLink LP terminated a portion of the work under its contract with MSJV. MSJV continued as prime contractor for the remaining portion of the work; however, it did not complete the remaining work as scheduled. Coastal GasLink LP claims damages in the approximate amount of $560 million for delay, owner indirect costs, contractor replacement costs and repayment of payments made on a without prejudice basis. MSJV has counterclaimed against Coastal GasLink LP for damages for wrongful termination and outstanding costs in the approximate amount of $480 million. An arbitration schedule is expected to be established in second quarter 2025. At December 31, 2024, the final outcome of this matter cannot be reasonably estimated. 2016 Columbia Pipeline Acquisition Lawsuit In 2023, the Delaware Chancery Court (the Court) issued its decision in the class action lawsuit commenced by former shareholders of Columbia Pipeline Group Inc. (CPG) related to the acquisition of CPG by TC Energy in 2016. The Court found that the former CPG executives breached their fiduciary duties, that the former CPG Board breached its duty of care in overseeing the sale process and that TC Energy aided and abetted those breaches. On May 15, 2024, the Court allocated responsibility for the total sale process damages of US$398 million in the amount of 50 per cent to the former Columbia CEO and CFO, collectively, and 50 per cent to TC Energy. Pursuant to the Final Order and Judgment (Final Judgment), TC Energy’s allocated share of the sale process claim damages is US$199 million, plus US$153 million in interest as of June 14, 2024. The Court also entered judgment related to a disclosure claim for which TC Energy’s allocated share of damages is US$84 million, plus US$64 million in interest as of June 14, 2024. The damages for the two claims are not cumulative and TC Energy would only be required to pay the greater of the sale process damages and disclosure claim damages after final determination of those amounts on appeal, including any additional interest assessed to the date of payment. TC Energy disagrees with many of the Court’s findings and believes the Court’s ruling departs from established Delaware law. TC Energy has filed a notice of appeal, which is scheduled to be heard by the Delaware Supreme Court on March 12, 2025. A final decision is expected in mid-2025. During the appeal process, in lieu of paying the judgment, TC Energy posted an appeal bond in the amount of US$380 million, which approximates the amount of the Final Judgment plus nine months of post-judgment interest. The Company’s legal assessment is that it is not probable that TC Energy will incur a loss upon completion of the appeal process, and therefore, the Company has not accrued a provision for this claim at December 31, 2024. Guarantees TC Energy and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the financial performance of the entity which owns the pipeline. Such agreements include a guarantee and a letter of credit which are primarily related to the delivery of natural gas. TC Energy and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company and its partners in certain other jointly-owned entities have either: i) jointly and severally; ii) jointly or iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas. For certain of these entities, any payments made by TC Energy under these guarantees in excess of its ownership interest are to be reimbursed by its partners. The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees were as follows: at December 31 2024 2023 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas Renewable to 2053 93 — 97 — Bruce Power Renewable to 2065 88 — 88 — Other jointly-owned entities to 2032 59 1 24 1 240 1 209 1 1 TC Energy's share of the potential estimated current or contingent exposure.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES Consolidated VIEs A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The consolidated VIEs whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations, or are not considered a business, were as follows: at December 31 (millions of Canadian $) 2024 1 2023 2 ASSETS Current Assets Cash and cash equivalents 311 188 Accounts receivable 839 473 Inventories 205 90 Other current assets 121 49 Current assets of discontinued operations — 5 1,476 805 Plant, Property and Equipment 49,904 27,477 Equity Investments 865 823 Restricted Investments 950 — Goodwill 479 439 Regulatory Assets 53 12 Other Long-Term Assets 59 — Long-Term Assets of Discontinued Operations — 172 53,786 29,728 LIABILITIES Current Liabilities Accounts payable and other 1,866 1,092 Accrued interest 202 210 Current portion of long-term debt 2,062 28 Current liabilities of discontinued operations — 43 4,130 1,373 Regulatory Liabilities 1,232 280 Other Long-Term Liabilities 70 46 Deferred Income Tax Liabilities 7 22 Long-Term Debt 12,387 11,388 Long-Term Liabilities of Discontinued Operations — 10 17,826 13,119 1 On April 1, 2024, the NGTL System was classified as a VIE when its ownership was transferred from Nova Gas Transmission Ltd. to NGTL GP Ltd. on behalf of NGTL Limited Partnership. 2 Columbia Gas and Columbia Gulf were classified as a VIE upon TC Energy's sale of a 40 per cent non-controlling equity interest on October 4, 2023. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. Non-Consolidated VIEs The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs were as follows: at December 31 (millions of Canadian $) 2024 2023 Balance Sheet Exposure Equity Investments Bruce Power 7,043 6,241 Coastal GasLink 1,006 294 Pipeline equity investments and other 160 166 Long-Term Assets of Discontinued Operations Pipeline equity investments and other — 951 Off-Balance Sheet Exposure 1 Bruce Power 1,877 1,538 Coastal GasLink 2 265 855 Pipeline equity investments and other 2 2 Discontinued operations — 56 Maximum exposure to loss 10,353 10,103 1 Includes maximum potential exposure to guarantees and future funding commitments. 2 TC Energy is contractually obligated to fund the capital costs to complete the Coastal GasLink pipeline by funding the remaining equity requirements of Coastal GasLink LP through incremental capacity on the subordinated loan agreement with Coastal GasLink LP until final costs are determined. In December 2024, TC Energy made an equity contribution of $3,137 million to Coastal GasLink LP, which used the funds to repay the $3,147 million balance owing to TC Energy under the subordinated loan agreement. The repayment reduced the Company's funding commitment under the subordinated loan agreement to $228 million. In addition to the subordinated loan agreement, TC Energy has entered into an equity contribution agreement to fund a maximum of $37 million for its proportionate share of the equity requirements related to the Cedar Link project. Refer to Note 7, Coastal GasLink, for additional information.

ACCOUNTING POLICIES (Policies)

ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These consolidated financial statements include the accounts of TC Energy and its subsidiaries. The Company consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. TC Energy uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. The Spinoff Transaction represented a strategic shift that had a major effect on the Company's operations and consolidated financial results. Accordingly, the historical results of the Liquids Pipelines business are presented as discontinued operations and have been excluded from continuing operations and segment disclosures for all periods presented. The Notes to the consolidated financial statements reflect continuing operations only, unless otherwise indicated. Prior to the spinoff, the operations of the Liquids Pipelines business were materially reported as the Company's Liquids Pipelines segment. Refer to Note 4, Discontinued operations, and Note 5, Segmented information, for additional information. Certain prior year amounts have been reclassified to conform to current year presentation.
Use of Estimates and Judgments	Use of Estimates and Judgments In preparing these consolidated financial statements, TC Energy is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Certain estimates and judgments have a material impact where the assumptions underlying these accounting estimates relate to matters that are highly uncertain at the time they are made or are subjective. These estimates and judgments include, but are not limited to, the assessment of goodwill impairment indicators and fair value of reporting units that contain goodwill (Note 14). Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial statements, but do not involve significant subjectivity or uncertainty. These estimates and judgments include, but are not limited to: • provisions for indemnities related to the South Bow Separation Agreement (Note 4) • recoverability and depreciation rates of plant, property and equipment (Note 9) • allocation of consideration to lease and non-lease components in a contract that contains a lease (Note 10) • assumptions used to measure the carrying amount of and expected credit losses on net investment in leases and certain contract assets (Notes 10 and 28) • fair value of equity investments (Note 11) • carrying value of regulatory assets and liabilities (Note 13) • recognition of asset retirement obligations (Note 18) • provisions for income taxes, including valuation allowances and releases as well as tax positions that may be reviewed as part of an audit by tax authorities (Note 19) • assumptions used to measure retirement and other post-retirement benefit obligations (Note 27) • fair value of financial instruments (Note 28) • fair value of Fluvanna Wind Farm and Blue Cloud Wind Farm (Texas Wind Farms) assets (Note 30) • commitments and provisions for contingencies and guarantees (Note 31). TC Energy continues to assess climate-related impacts on the consolidated financial statements. There are ongoing developments in the ESG frameworks and regulatory initiatives that could further impact accounting estimates and judgments including, but not limited to, assessment of asset useful lives, goodwill valuation, impairment of plant, property and equipment, accrued environmental costs and asset retirement obligations. The impact of these changes is continuously assessed to ensure any changes in assumptions that would impact estimates listed above are adjusted on a timely basis. Actual results could differ from these estimates.
Regulation	Regulation Certain Canadian, U.S. and Mexico natural gas pipeline and storage assets are regulated with respect to construction, operations and the determination of tolls. In Canada, regulated natural gas pipelines are subject to the authority of the Canada Energy Regulator (CER), the Alberta Energy Regulator or the B.C. Oil and Gas Commission. In the U.S., regulated interstate natural gas pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TC Energy's rate-regulated businesses which may differ from that otherwise recognized in non-rate-regulated businesses to reflect the economic impact of the regulators' decisions regarding revenues and tolls. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An operation qualifies for the use of RRA when it meets three criteria: • a regulator must establish or approve the rates for the regulated services or activities • the regulated rates must be designed to recover the cost of providing the services or products • it is reasonable to assume that rates set at levels to recover the cost can be charged to and collected from customers because of the demand for services or products and the level of direct or indirect competition. TC Energy's businesses that apply RRA currently include natural gas pipelines in Canada, U.S. and Mexico and regulated U.S. natural gas storage.
Revenue Recognition	Revenue Recognition The total consideration for services and products to which the Company expects to be entitled can include fixed and variable amounts. The Company has variable revenue that is subject to factors outside the Company's influence, such as market prices, actions of third parties and weather conditions. The Company considers this variable revenue to be "constrained" as it cannot be reliably estimated and, therefore, recognizes variable revenue when the service is provided. Revenues from contracts with customers are recognized net of any commodity taxes collected from customers which are subsequently remitted to governmental authorities. The Company's contracts with customers include natural gas pipelines capacity arrangements and transportation contracts, power generation contracts, natural gas storage and other contracts. Revenues from non-lease components associated with a lease arrangement are recognized systematically over the term of the contract. The majority of income earned from marketing activities, as it relates to the purchase and sale of natural gas and electricity, is recorded on a net basis in the month of delivery. Canadian Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Canadian natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. Revenues from the Company's Canadian natural gas pipelines under federal jurisdiction are subject to regulatory decisions by the CER. The tolls charged on these pipelines are based on revenue requirements designed to recover the costs of providing natural gas capacity for transportation services, which includes a return of and on capital, as approved by the CER. The Company's Canadian natural gas pipelines are generally not subject to earnings volatility related to variances in revenues and costs. These variances, except as related to incentive arrangements, are generally subject to deferral treatment and are recovered or refunded in future tolls. Revenues recognized prior to a CER decision on rates for that period reflect the CER's last approved return on equity (ROE) assumptions. Adjustments to revenues are recorded when the CER decision is received. Canadian natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Other Through the year, the Company was contracted to provide pipeline construction services to a partially-owned entity for a development fee. The development fee was considered variable consideration due to refund provisions in the contract. The Company recognized its estimate of the most likely amount of the variable consideration to which it was entitled. The development fee was recognized over time as the services were provided based on the input method using an estimate of activity level. U.S. Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's U.S. natural gas pipelines are generated from contractual arrangements for committed capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Company's U.S. interstate natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final. U.S. natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Natural Gas Storage and Other Revenues from the Company's regulated U.S. natural gas storage services are generated mainly from firm committed capacity storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage including specifications with regard to the amount of natural gas that can be injected or withdrawn on a daily basis. Revenues are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. Natural gas storage services revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it stores for customers. The Company owns mineral rights associated with certain natural gas storage facilities. These mineral rights can be leased or contributed to producers of natural gas in return for a royalty interest which is recognized when natural gas and associated liquids are produced. Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from certain of the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Other The Company generates revenues from operating and maintenance services provided on leased pipelines. Revenues earned from these services are recognized ratably over the term of the contract. Power and Energy Solutions Power Revenues from the Company's Power and Energy Solutions business are primarily derived from long-term contractual commitments to provide power capacity to meet the demands of the market and from the sale of electricity to both centralized markets and to customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and capacity payments are recognized as the services are provided and as electricity and steam is delivered. Power generation revenues are invoiced and received on a monthly basis. Natural Gas Storage and Other
Cash and Cash Equivalents	Cash and Cash Equivalents The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.
Inventories	Inventories Inventories primarily consist of materials and supplies including spare parts and fuel, proprietary natural gas inventory in storage and emissions allowances and credits not held for compliance. The Company purchases certain emissions allowances and credits as part of bundled arrangements that also include the purchase of electricity for a fixed price. The cost allocated to emissions allowances and credits under such arrangements is based on observable market prices. Inventories are carried at the lower of cost and net realizable value.
Assets Held For Sale	Assets Held for Sale The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, net of selling costs and any losses are recognized in net income. Gains related to the expected sale of these assets are not recognized until the transaction closes. Once an asset is classified as held for sale, depreciation expense is no longer recorded.
Plant, Property and Equipment	Plant, Property and Equipment Natural Gas Pipelines Plant, property and equipment for natural gas pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from 0.75 per cent to 6.67 per cent and metering and other plant equipment are depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in Plant, property and equipment with a corresponding credit recognized in Allowance for funds used during construction in the Consolidated statement of income. The equity component of AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines. Natural gas pipelines' linepack and natural gas storage base gas are valued at cost and are maintained to ensure adequate pressure exists to transport natural gas through pipelines and deliver natural gas held in storage. Linepack and base gas are not depreciated. When rate-regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation with no amount recorded to net income. Costs incurred to remove plant, property and equipment from service, net of any salvage proceeds, are also recorded in accumulated depreciation. Other The Company participates as a working interest partner in the development of certain Marcellus and Utica acreage. The working interest allows the Company to invest in drilling activities in addition to receiving a royalty interest in well production. The Company uses the successful efforts method of accounting for natural gas and crude oil resulting from its portion of drilling activities. Capitalized well costs are depleted based on the units of production method. Power and Energy Solutions Plant, property and equipment for Power and Energy Solutions assets are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. Natural gas storage base gas, which is valued at original cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver gas held in storage. Base gas is not depreciated. Corporate Corporate plant, property and equipment is recorded at cost and depreciated on a straight-line basis over its estimated useful life at average annual rates ranging from four per cent to 20 per cent. Capital Projects in Development The Company capitalizes project costs once advancement of the project to construction stage is probable or costs are otherwise likely to be recoverable. The Company capitalizes interest costs for non-regulated projects in development and AFUDC for regulated projects in development. Capital projects in development are included in Other long-term assets on the Consolidated balance sheet. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to plant, property and equipment under construction.
Lessee Accounting Policy	Leases The Company determines if a contract contains a lease at inception of a contract by using judgment in assessing the following aspects: 1) the contract specifies an identified asset which is physically distinct or, if not physically distinct, represents substantially all of the capacity of the asset; 2) the contract provides the customer with the right to obtain substantially all of the economic benefits from the use of the asset and 3) the customer has the right to direct how and for what purpose the identified asset is used throughout the period of the contract. If the contract is determined to contain a lease, further judgment is required to identify separate lease components of the arrangement by assessing whether the lessee can benefit from the right of use either on its own or together with other resources that are readily available to the lessee, as well as if the right of use is neither highly dependent on, nor highly interrelated, with the other rights to use the underlying assets in the contract. The Company considers non-lease components as distinct elements of a contract that are not related to the use of the leased asset. A good or service that is provided to a customer is distinct if: 1) the customer can benefit from the good or service either on its own or together with other resources that are readily available to the customer and 2) the entity’s promise to transfer the good or service to the customer is separately identifiable from other promises in the contract. The Company applies the practical expedient to not separate lease and non-lease components for all lessee contracts and facilities for which the Company is the lessor in an operating lease. Lessee Accounting Policy Operating leases are recognized as right-of-use (ROU) assets and included in Plant, property and equipment while corresponding liabilities are included in Accounts payable and other and Other long-term liabilities on the Consolidated balance sheet. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at the commencement date of the lease agreement. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. As the Company's lease contracts do not provide an implicit interest rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Operating lease expense is recognized on a straight-line basis over the lease term and included in Plant operating costs and other in the Consolidated statement of income. The Company applies the practical expedient to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption.
Lessor Accounting Policy	Lessor Accounting Policy The Company provides transportation and other services on certain assets to customers according to long-term service agreements through sales-type and operating leases. In a sales-type lease, the Company measures the total consideration within the contract at lease commencement. When a lease arrangement contains more than one lease and/or non-lease component, a portion of the contract consideration is allocated to each component based on the stand-alone selling price for each distinct service. The Company applies judgment to determine reasonable estimates of the expected future cost of satisfying the performance obligations of each service. The payments associated with lease components are apportioned between a reduction in the lease receivable and sales-type lease income. At lease commencement, the Company recognizes a net investment in lease represented by the present value of both the future lease payments and the estimated residual value of the leased asset. The plant, property and equipment of the leased asset is derecognized, with related gains/losses, if any, recognized in the Consolidated statement of income. Sales-type lease income is determined using the rate implicit in the lease and is recorded in Revenues. The Company is the lessor within certain other contracts, including PPAs, that are accounted for as operating leases. In an operating lease, the leased asset remains capitalized in Plant, property and equipment on the Consolidated balance sheet and is depreciated over its useful life, while lease payments are recognized as revenue over the term of the lease on a straight-line basis. Variable lease payments are recognized as income in the period in which they occur.
Impairment of Long-Lived Assets and Impairment of Financial Assets	Impairment of Long-Lived Assets The Company reviews long-lived assets such as plant, property and equipment and capital projects in development for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows for an asset within plant, property and equipment, or the estimated selling price of any long-lived asset is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the asset. Impairment of Financial Assets The Company reviews financial assets, inclusive of net investment in leases and certain contract assets, carried at amortized cost for impairment using the lifetime expected loss of the financial asset at initial recognition and throughout the life of the financial asset. An expected credit loss (ECL) is calculated using a model and methodology based on assumptions and judgment considering historical data, current counterparty information as well as reasonable and supportable forecasts of future economic conditions. The ECL is recognized in Plant operating costs and other in the Consolidated statement of income, and is presented on the Consolidated balance sheet as a reduction to the carrying value of the related financial asset.
Impairment of Equity Method Investments	Impairment of Equity Method Investments The Company reviews equity method investments for impairment when an event or change in circumstances has a significant adverse effect on the investment's fair value. Where the Company concludes an investment's fair value is below its carrying value, the Company then determines whether the impairment is other-than-temporary, and if so, an impairment loss is recognized for the excess of the carrying value over the estimated fair value of the investment, not exceeding the carrying value of the investment.
Acquisitions and Goodwill	Acquisitions and Goodwill The Company accounts for business combinations using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair values at the date of acquisition. The excess of the fair value of the consideration transferred over the estimated fair value of the net assets acquired is classified as goodwill. Goodwill is not amortized and is tested for impairment on an annual basis, or more frequently if events or changes in circumstances indicate that it might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company can initially assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. The factors the Company considers include, but are not limited to, macroeconomic conditions, industry and market considerations, current valuation multiples and discount rates, cost factors, historical and forecasted financial results and events specific to that reporting unit. If the Company concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the Company will then perform a quantitative goodwill impairment test. The Company can elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Company compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. The fair value of a reporting unit is determined by using a discounted cash flow analysis which requires the use of assumptions that may include, but are not limited to, revenue and capital expenditure projections, valuation multiples and discount rates. The Company has elected to allocate goodwill impairment charges first to goodwill that is non-deductible for income tax purposes, with any remaining charge allocated to tax-deductible goodwill. When a portion of a reporting unit that constitutes a business is disposed, goodwill associated with that business is included in the carrying amount of the business in determining the gain or loss on disposal. The amount of goodwill disposed is determined based on the relative fair values of the business to be disposed and the portion of the reporting unit that will be retained. A goodwill impairment test will be completed for both the goodwill disposed and the portion of the goodwill that will be retained.
Non-Controlling Interests	Non-Controlling Interests Non-controlling interests (NCI) represent third-party ownership interests in certain consolidated subsidiaries of the Company. Partial dispositions which result in a change in the Company's ownership interest, but do not result in a change in control, of a subsidiary that constitutes a business are accounted for as equity transactions. No gain or loss is recognized in earnings. At the time of partial disposition, NCI is recorded as the third party's ownership interest in the Company's carrying value of the net assets of the subsidiary. Any difference between the amount by which the NCI is adjusted and the fair value of the consideration paid or received is recognized in Additional paid-in capital and/or Retained earnings (Accumulated deficit).
Loans and Receivables	Loans and Receivables Loans receivable from affiliates and accounts receivable are measured at amortized cost.
Restricted Investments	Restricted Investments The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are classified as available for sale and are recorded at fair value on the Consolidated balance sheet. As a result of the CER’s Land Matters Consultation Initiative (LMCI), TC Energy is required to collect funds to cover estimated future pipeline abandonment costs for larger CER-regulated Canadian pipelines. Funds collected are placed in trusts that hold and invest the funds and are accounted for as restricted investments (LMCI restricted investments). LMCI restricted investments may only be used to fund the abandonment of the CER-regulated pipeline facilities, therefore, a corresponding regulatory liability is recorded on the Consolidated balance sheet. The Company also has other restricted investments that have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.
Income Taxes	Income Taxes The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in net income in the period in which they occur, except for changes in balances related to regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the regulator. Deferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet. The Company’s exposure to uncertain tax positions is evaluated and a provision is made where it is more likely than not that this exposure will materialize. Canadian income taxes are not provided for on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Any interest and/or penalty incurred related to income tax is reflected in Income tax expense.
Asset Retirement Obligations	Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Plant operating costs and other in the Consolidated statement of income. In determining the fair value of ARO, the following assumptions are used: • the expected retirement date • the scope and cost of abandonment and reclamation activities that are required • appropriate inflation and discount rates. The Company's AROs are substantially related to its power generation facilities. The scope and timing of asset retirements related to the Company's natural gas pipelines and storage facilities are indeterminable because the Company intends to operate them as long as there is supply and demand. As a result, the Company has not recorded an amount for ARO related to these assets.
Environmental Liabilities and Emission Allowances and Credits	Environmental Liabilities and Emission Allowances and Credits The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. These estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations and are subject to revision in future periods based on actual costs incurred or new circumstances. TC Energy evaluates recoveries from insurers and other third parties separately from the liability and, when recovery is probable, an asset is recorded separately from the associated liability. These recoveries are presented, along with environmental remediation costs, on a net basis in Plant operating costs and other in the Consolidated statement of income. Variations in one or more of the categories described above could result in additional costs such as fines, penalties and/or expenditures associated with litigation and settlement of claims with respect to environmental liabilities. Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and derecognized when they are utilized or cancelled/retired by government agencies. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TC Energy are not attributed a value for accounting purposes. When required, TC Energy accrues emission liabilities on the Consolidated balance sheet using the best estimate of the amount required to settle the compliance obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues within the Power and Energy Solutions segment in the Consolidated statement of income. The Company records allowances and credits held for compliance in Other current assets and Other long-term assets on the Consolidated balance sheet. Allowances and credits not held for compliance are classified as Inventories on the Consolidated balance sheet.
Stock Options and Other Compensation Programs	Stock Options and Other Compensation Programs TC Energy's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period with an offset to Additional paid-in capital. Forfeitures are accounted for when they occur. Upon exercise of stock options, amounts originally recorded against Additional paid-in capital are reclassified to Common shares on the Consolidated balance sheet. The Company has medium-term incentive plans under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.
Employee Post-Retirement Benefits	Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), savings plans and other post-retirement benefit plans (OPEB Plans). Contributions made by the Company to the DC Plans and savings plans are expensed in the period in which contributions are made. The cost of the DB Plans and OPEB Plans received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life (EARSL) of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the EARSL of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income (loss)(OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated other comprehensive income (loss)(AOCI) and into net income over the EARSL of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the EARSL of active employees.
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 the Company or reporting subsidiary operates. This is referred to as the functional currency. Transactions denominated in foreign currencies are translated into 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 rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are recorded in net income except for exchange gains and losses on any foreign currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in tolls, as permitted by the CER.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities All derivative instruments are recorded on the Consolidated balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions. The Company applies hedge accounting to arrangements that qualify for and are designated for hedge accounting treatment. This includes fair value and cash flow hedges as well as hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the change in the fair value of the hedging derivative is recognized in OCI. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. Termination payments on interest rate derivatives are classified as a financing activity in the Consolidated statement of cash flows. In hedging the foreign currency exposure of a net investment in a foreign operation, the foreign exchange gains and losses on the hedging instruments are recognized in OCI. The amounts recognized previously in AOCI are reclassified to net income in the event the Company reduces its net investment in a foreign operation. In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory liabilities or regulatory assets and are refunded to or collected from rate payers in subsequent periods when the derivative settles. Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in net income.
Long-Term Debt Transaction Costs and Issuance Costs	Long-Term Debt Transaction Costs and Issuance Costs The Company records long-term debt transaction costs and issuance costs as a deduction from the carrying amount of the related debt liability and amortizes these costs using the effective interest method except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms.
Guarantees	Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of a partially-owned entity or by partially-owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments or Plant, property and equipment and a corresponding liability is recorded in Other long-term liabilities. The release from the obligation is recognized either over the term of the guarantee or upon expiration or settlement of the guarantee.
Variable Interest Entities	Variable Interest Entities 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. The assessment of whether an entity is a VIE and, if so, whether the Company is the primary beneficiary, is completed at the inception of the entity or at a reconsideration event. Consolidated VIEs The Company's consolidated VIEs consist of legal entities where the Company has a variable interest and for which it is considered the primary beneficiary. As the primary beneficiary, the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including: purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE. Non-Consolidated VIEs The Company’s non-consolidated VIEs consist of legal entities where the Company has a variable interest but is not the primary beneficiary as it does not have the power (either explicit or implicit), through voting or similar rights, to direct the activities that most significantly impact the economic performance of these VIEs or where this power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it with residual claims on assets after liabilities are paid. Non-consolidated VIEs are accounted for as equity investments. The Company’s maximum exposure to loss is the maximum loss that could potentially be recorded through net income in future periods as a result of the Company’s variable interest in a VIE.
Accounting Changes	Changes in Accounting Policies for 2024 Segment Reporting In November 2023, the Financial Accounting Standards Board (FASB) issued new guidance to improve disclosures about a public entity's reportable segments and address requests from investors for additional, more detailed information about a reportable segment's expenses. The guidance was effective for annual periods beginning January 1, 2024 and interim periods beginning January 1, 2025. The Company adopted the guidance effective January 1, 2024. Refer to Note 5, Segmented information. Leases In March 2023, the FASB issued new guidance that clarified the accounting for leasehold improvements associated with common control leases. This new guidance was effective January 1, 2024 and adoption did not have a material impact on the Company's consolidated financial statements. Future Accounting Changes Income Taxes In December 2023, the FASB issued new guidance to enhance the transparency and decision usefulness of income tax disclosures through improvements to the rate reconciliation and income taxes paid information. The guidance also includes certain other amendments to improve the effectiveness of income tax disclosures. This new guidance is effective for annual periods beginning January 1, 2025. The guidance is applied prospectively with retrospective application permitted. Early adoption is permitted for annual financial statements not yet issued. The Company intends to adopt the guidance prospectively and does not intend to early adopt the guidance. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements, but does not expect the guidance to have a material impact on the Company's financial position or results of operations. Disaggregation of Income Statement Expenses

DISCONTINUED OPERATIONS (Tables

DISCONTINUED OPERATIONS (Tables)	12 Months Ended
	Dec. 31, 2024
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Discontinued Operations	Income from Discontinued Operations year ended December 31 (millions of Canadian $) 2024 ¹ 2023 2022 Revenues 2,217 2,667 2,668 Income (Loss) from Equity Investments 50 67 55 Operating and Other Expenses Plant operating costs and other 806 814 704 Commodity purchases resold 387 437 512 Property taxes 84 116 121 Depreciation and amortization 253 332 322 Asset impairment charge and other 21 (4) (118) 1,551 1,695 1,541 Segmented Earnings (Losses) from Discontinued Operations 716 1,039 1,182 Financial Charges Interest expense 218 297 288 Interest income and other (21) 30 (6) 197 327 282 Income (Loss) from Discontinued Operations before Income Taxes 519 712 900 Income tax expense (recovery) 124 100 267 Net Income (Loss) from Discontinued Operations, Net of Tax 395 612 633 1 Represents nine months of Liquids Pipelines earnings in 2024 compared to a full year of Liquids Pipelines earnings in 2023 and 2022. Assets and Liabilities of Discontinued Operations at December 31 (millions of Canadian $) 2024 2023 ASSETS Current Assets Accounts receivable — 1,782 Inventories — 211 Other current assets 235 1,084 235 3,077 Plant, Property and Equipment — 11,118 Equity Investments — 1,074 Other Long-Term Assets 136 241 371 15,510 LIABILITIES Current Liabilities Accounts payable and other 170 2,682 170 2,682 Other Long-Term Liabilities 110 127 Deferred Income Tax Liabilities — 1,153 280 3,962 Cash Flows from Discontinued Operations year ended December 31 (millions of Canadian $) 2024 2023 2022 Net cash provided by operations 670 1,026 709 Net cash (used in) provided by investing activities (89) 87 502

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Information regarding the Company's business segments is as follows: year ended December 31, 2024 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 5,600 6,339 870 954 8 13,771 Intersegment revenues 2 — 99 — 49 (148) — 5,600 6,438 870 1,003 (140) 13,771 Income (loss) from equity investments 34 341 283 900 — 1,558 Operating costs 2 (2,246) (2,381) (132) (700) 9 3 (5,450) Depreciation and amortization (1,382) (955) (92) (101) (5) 3 (2,535) Other segment items 4 10 610 — — — 620 Segmented Earnings (Losses) 2,016 4,053 929 1,102 (136) 7,964 Interest expense (3,019) Allowance for funds used during construction 784 Foreign exchange gains (losses), net (147) Interest income and other 324 Income (Loss) from Continuing Operations before Income Taxes 5,906 Income tax (expense) recovery from continuing operations (922) Net Income (Loss) from Continuing Operations 4,984 Net Income (Loss) from Discontinued Operations, Net of Tax 395 Net Income (Loss) 5,379 Net (income) loss attributable to non-controlling interests (681) Net Income (Loss) Attributable to Controlling Interests 4,698 Preferred share dividends (104) Net Income (Loss) Attributable to Common Shares 4,594 Capital Spending 5 Capital expenditures 1,273 2,568 2,228 62 50 6,181 Capital projects in development — 5 — 45 — 50 Contributions to equity investments 6 827 2 — 717 — 1,546 2,100 2,575 2,228 824 50 7,777 Discontinued operations 127 7,904 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Includes shared costs and depreciation previously allocated to the Liquids Pipelines segment. Refer to Note 4, Discontinued operations, for additional information. 4 Other segment items include a Net gain (loss) on sale of assets. 5 Included in Investing activities in the Consolidated statement of cash flows. 6 Contributions to equity investments in the Canadian Natural Gas Pipelines segment of $3.1 billion are offset by the equivalent amount in Other distributions from equity investments, although they are reported on a gross basis in the Company’s Consolidated statement of cash flows. Refer to Note 7, Coastal GasLink, for additional information. year ended December 31, 2023 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 5,173 6,229 846 1,019 — 13,267 Intersegment revenues 2 — 101 — 22 (123) — 5,173 6,330 846 1,041 (123) 13,267 Income (loss) from equity investments 220 324 78 688 — 1,310 Impairment of equity investment (2,100) — — — — (2,100) Operating costs 2 (2,058) (2,189) (39) (633) (15) 3 (4,934) Depreciation and amortization (1,325) (934) (89) (92) (6) 3 (2,446) Segmented Earnings (Losses) (90) 3,531 796 1,004 (144) 5,097 Interest expense (2,966) Allowance for funds used during construction 575 Foreign exchange gains (losses), net 320 Interest income and other 272 Income (Loss) from Continuing Operations before Income Taxes 3,298 Income tax (expense) recovery from continuing operations (842) Net Income (Loss) from Continuing Operations 2,456 Net income (loss) from Discontinued Operations, Net of Tax 612 Net Income (Loss) 3,068 Net Income (loss) attributable to non-controlling interests (146) Net Income (Loss) Attributable to Controlling Interests 2,922 Preferred share dividends (93) Net Income (Loss) Attributable to Common Shares 2,829 Capital Spending 4 Capital expenditures 2,953 2,536 2,292 144 33 7,958 Capital projects in development — — — 142 — 142 Contributions to equity investments 3,231 124 — 794 — 4,149 6,184 2,660 2,292 1,080 33 12,249 Discontinued operations 49 12,298 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Includes shared costs and depreciation previously allocated to the Liquids Pipelines segment. Refer to Note 4, Discontinued operations, for additional information. 4 Included in Investing activities in the Consolidated statement of cash flows. year ended December 31, 2022 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 4,764 5,933 688 924 — 12,309 Intersegment revenues 2 — 132 — 12 (144) — 4,764 6,065 688 936 (144) 12,309 Income (loss) from equity investments 18 292 122 539 28 3 999 Impairment of equity investment (3,048) — — — — (3,048) Operating costs 2 (1,976) (2,282) (221) (570) 72 4 (4,977) Depreciation and amortization (1,198) (887) (98) (72) (7) 4 (2,262) Other segment items 5 — (571) — — — (571) Segmented Earnings (Losses) (1,440) 2,617 491 833 (51) 2,450 Interest expense (2,300) Allowance for funds used during construction 369 Foreign exchange gains (losses), net 3 (185) Interest income and other 140 Income (Loss) from Continuing Operations before Income Taxes 474 Income tax (expense) recovery from continuing operations (322) Net Income (Loss) from Continuing Operations 152 Net Income (Loss) from Discontinued Operations, Net of Tax 633 Net Income (Loss) 785 Net (income) loss attributable to non-controlling interests (37) Net Income (Loss) Attributable to Controlling Interests 748 Preferred share dividends (107) Net Income (Loss) Attributable to Common Shares 641 Capital Spending 6 Capital expenditures 3,274 2,137 1,027 93 41 6,572 Capital projects in development — — — 49 — 49 Contributions to equity investments 7 1,445 — — 752 — 2,197 4,719 2,137 1,027 894 41 8,818 Discontinued operations 143 8,961 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Operating costs in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income (loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains and losses on the peso-denominated loans from affiliates which are fully offset in Foreign exchange gains (losses), net by the corresponding foreign exchange losses and gains on the affiliate receivable balance until March 15, 2022, when it was fully repaid upon maturity. Refer to Note 12, Loans receivable from affiliates, for additional information. 4 Includes shared costs and depreciation previously allocated to the Liquids Pipelines segment. Refer to Note 4, Discontinued operations, for additional information. 5 Other segment items includes a goodwill impairment charge. Refer to Note 14, Goodwill, for additional information. 6 Included in Investing activities in the Consolidated statement of cash flows. 7 Contributions to equity investments in the Corporate segment of $1.2 billion are offset by the equivalent amount in Other distributions from equity investments, although they are reported on a gross basis in the Company’s Consolidated statement of cash flows. Refer to Note 12, Loans receivable from affiliates, for additional information. at December 31 2024 2023 (millions of Canadian $) Total Assets by Segment Canadian Natural Gas Pipelines 31,167 29,782 U.S. Natural Gas Pipelines 56,304 50,499 Mexico Natural Gas Pipelines 15,995 12,003 Power and Energy Solutions 10,217 9,525 Corporate 4,189 7,715 117,872 109,524 Discontinued Operations 371 15,510 118,243 125,034
Revenue from External Customers by Geographic Areas	year ended December 31 2024 2023 2022 (millions of Canadian $) Revenues Canada – domestic 5,579 5,337 4,920 Canada – export 953 821 765 United States 6,369 6,263 5,936 Mexico 870 846 688 13,771 13,267 12,309
Schedule of Long-Lived Assets by Country	at December 31 2024 2023 (millions of Canadian $) Plant, Property and Equipment Canada 26,354 26,434 United States 40,580 35,640 Mexico 10,567 7,377 77,501 69,451

REVENUES (Tables)

REVENUES (Tables)	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenues	year ended December 31, 2024 Canadian U.S. Mexico Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 5,586 5,382 438 — 11,406 Power generation — — — 266 266 Natural gas storage and other 1,2 14 869 124 383 1,390 5,600 6,251 562 649 13,062 Other revenues 3 — 88 — 305 393 Sales-type lease income 4 — — 308 — 308 Corporate revenues 5 — — — — 8 5,600 6,339 870 954 13,771 1 Includes $14 million of fee revenues from an affiliate related to the development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy. 2 Includes $98 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service Transportadora de Gas Natural de La Huasteca (TGNH) pipelines. Refer to Note 10, Leases, for additional information. 3 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information. 4 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. 5 Includes $7 million of revenues generated from the Transition Services Agreement with South Bow. Refer to Note 4, Discontinued operations, for additional information. year ended December 31, 2023 Canadian U.S. Mexico Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 5,141 5,107 442 — 10,690 Power generation — — — 427 427 Natural gas storage and other 1,2 32 874 125 363 1,394 5,173 5,981 567 790 12,511 Other revenues 3 — 248 — 229 477 Sales-type lease income 4 — — 279 — 279 5,173 6,229 846 1,019 13,267 1 Includes $31 million of fee revenues from an affiliate related to the development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy. 2 Includes $97 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. 3 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information. 4 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. year ended December 31, 2022 Canadian U.S. Mexico Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,696 4,621 507 — 9,824 Power generation — — — 490 490 Natural gas storage and other 1,2 68 1,298 54 391 1,811 4,764 5,919 561 881 12,125 Other revenues 3,4 — 14 — 43 57 Sales-type lease income 5 — — 127 — 127 4,764 5,933 688 924 12,309 1 Includes $68 million of fee revenues from an affiliate related to the development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy. 2 Includes $37 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. 3 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information. 4 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from H.R. 1, the Tax Cuts and Jobs Act (U.S. Tax Reform). Refer to Note 13, Rate-regulated businesses. 5 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information.
Contract Balances	Contract Balances at December 31 2024 2023 Affected line item on the (millions of Canadian $) Receivables from contracts with customers 1,452 1,388 Accounts receivable Contract assets (Note 8) 165 151 Other current assets Long-term contract assets (Note 15) 608 457 Other long-term assets Contract liabilities 1 (Note 17) 30 47 Accounts payable and other Long-term contract liabilities 1 — 2 Other long-term liabilities 1

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2024
Other Assets [Abstract]
Schedule of Other Current Assets	at December 31 2024 2023 (millions of Canadian $) Fair value of derivative contracts (Note 28) 347 589 Current portion of net investment in leases (Note 10) 333 306 Contract assets (Note 6) 165 151 Cash provided as collateral 128 28 Regulatory assets (Note 13) 123 76 Prepaid expenses 86 87 Emissions credits 75 94 Other 82 88 1,339 1,419

PLANT, PROPERTY AND EQUIPMENT (

PLANT, PROPERTY AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Schedule of Plant, Property and Equipment	at December 31 2024 2023 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 20,497 7,413 13,084 20,232 6,855 13,377 Compression 7,146 2,497 4,649 6,603 2,349 4,254 Metering and other 1,668 883 785 1,589 830 759 29,311 10,793 18,518 28,424 10,034 18,390 Under construction 503 — 503 787 — 787 29,814 10,793 19,021 29,211 10,034 19,177 Canadian Mainline Pipeline 10,907 8,165 2,742 10,729 7,996 2,733 Compression 4,540 3,448 1,092 4,437 3,354 1,083 Metering and other 749 331 418 729 308 421 16,196 11,944 4,252 15,895 11,658 4,237 Under construction 163 — 163 147 — 147 16,359 11,944 4,415 16,042 11,658 4,384 Other Canadian Natural Gas Pipelines 1 Other 2,927 1,742 1,185 2,846 1,682 1,164 Under construction 31 — 31 23 — 23 2,958 1,742 1,216 2,869 1,682 1,187 49,131 24,479 24,652 48,122 23,374 24,748 U.S. Natural Gas Pipelines Columbia Gas Pipeline 14,826 1,472 13,354 12,952 1,247 11,705 Compression 6,153 677 5,476 5,310 559 4,751 Metering and other 4,570 455 4,115 4,074 372 3,702 25,549 2,604 22,945 22,336 2,178 20,158 Under construction 891 — 891 771 — 771 26,440 2,604 23,836 23,107 2,178 20,929 ANR Pipeline 2,477 745 1,732 2,117 657 1,460 Compression 4,446 938 3,508 3,928 773 3,155 Metering and other 1,832 521 1,311 1,625 458 1,167 8,755 2,204 6,551 7,670 1,888 5,782 Under construction 853 — 853 404 — 404 9,608 2,204 7,404 8,074 1,888 6,186 at December 31 2024 2023 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Other U.S. Natural Gas Pipelines Columbia Gulf 4,127 304 3,823 3,600 256 3,344 GTN 3,405 1,467 1,938 2,992 1,295 1,697 Great Lakes 2,602 1,537 1,065 2,359 1,401 958 Other 2 1,695 628 1,067 2,071 800 1,271 11,829 3,936 7,893 11,022 3,752 7,270 Under construction 694 — 694 584 — 584 12,523 3,936 8,587 11,606 3,752 7,854 48,571 8,744 39,827 42,787 7,818 34,969 Mexico Natural Gas Pipelines 3 Pipeline 2,590 523 2,067 2,290 422 1,868 Compression 476 107 369 447 82 365 Metering and other 398 99 299 395 85 310 3,464 729 2,735 3,132 589 2,543 Under construction 7,807 — 7,807 4,823 — 4,823 11,271 729 10,542 7,955 589 7,366 Power and Energy Solutions Natural Gas Power Generation 1,273 671 602 1,239 637 602 Natural Gas Storage and Other 873 281 592 845 256 589 Renewable Power Generation 779 54 725 581 19 562 2,925 1,006 1,919 2,665 912 1,753 Under construction 56 — 56 153 — 153 2,981 1,006 1,975 2,818 912 1,906 Corporate 944 439 505 909 447 462 112,898 35,397 77,501 102,591 33,140 69,451 1 Includes Foothills, Ventures LP and Great Lakes Canada. 2 Includes North Baja, Tuscarora, Louisiana Intrastate, Crossroads, U.S. Energy Marketing and mineral rights business. On August 15, 2024, the Company completed the sale of Portland Natural Gas Transmission System (PNGTS). Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 3 During the year ended December 31, 2024, the Company derecognized nil (2023 – $407 million) of Plant, property and equipment and recorded a corresponding asset for Net investment in leases for the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information.

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
Operating Lease Cost and Other Information	Operating lease cost was as follows: year ended December 31 (millions of Canadian $) 2024 2023 Operating lease cost 1 117 105 Sublease income (6) (4) Net operating lease cost 111 101 1 Includes short-term leases and variable lease costs. Other information related to operating leases is noted in the following tables: year ended December 31 (millions of Canadian $) 2024 2023 Cash paid for amounts included in the measurement of operating lease liabilities 74 72 ROU assets obtained in exchange for new operating lease liabilities 96 83 at December 31 2024 2023 Weighted average remaining lease term 13 years 13 years Weighted average discount rate 3.3 % 3.3 % The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2024 2023 Accounts payable and other (Note 17) 60 57 Other long-term liabilities (Note 18) 451 400 511 457
Maturities of Operating Lease Liabilities	Maturities of operating lease liabilities are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 73 71 One to two years 73 68 Two to three years 66 66 Three to four years 64 59 Four to five years 63 58 More than five years 275 224 Total operating lease payments 614 546 Imputed interest (103) (89) Operating lease liabilities 511 457
Future Lease Payments to be Received Under Operating Leases	Future lease payments to be received under operating leases are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 107 111 One to two years 76 94 Two to three years 9 70 Three to four years 10 — Four to five years 10 — More than five years 55 — 267 275
Sales-type Lease, Lease Income	The following table lists the components of the aggregate net investment in leases reflected on the Company's Consolidated balance sheet: at December 31 (millions of Canadian $) 2024 2023 Net Investment in Leases Minimum lease payments 10,164 9,627 Unearned lease income (7,323) (7,006) Lease receivable 2,841 2,621 Expected credit loss provision 1 (59) (76) Present value of unguaranteed residual value 28 24 2,810 2,569 Current portion included in Other current assets (Note 8) (333) (306) 2,477 2,263 1 Includes $6 million (2023 – nil) of foreign currency translation losses.
Future Lease Payments	Future lease payments to be received under the existing sales-type leases are as follows: at December 31 (millions of Canadian $) 2024 2023 Less than one year 333 305 One to two years 333 305 Two to three years 333 305 Three to four years 333 305 Four to five years 333 305 More than five years 8,499 8,102 10,164 9,627

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2024
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Investments	(millions of Canadian $) Ownership Interest at December 31, 2024 Income (Loss) from Equity Investments Equity year ended December 31 at December 31 2024 2023 2022 2024 2023 Canadian Natural Gas Pipelines TQM 1 50 % 17 17 17 160 166 Coastal GasLink 1,2 35 % 17 203 1 1,006 294 U.S. Natural Gas Pipelines Northern Border 50 % 130 101 92 647 599 Millennium 47.5 % 95 109 103 (21) 476 Iroquois 50 % 100 98 77 221 227 Other Various 16 16 20 135 120 Mexico Natural Gas Pipelines Sur de Texas 60 % 283 78 150 1,403 1,078 Power and Energy Solutions Bruce Power 1 48.3 % 900 690 537 7,043 6,242 Other Various — (2) 2 42 38 1,558 1,310 999 10,636 9,240 1 Classified as a VIE. Refer to Note 32, Variable interest entities, for additional information. 2 Refer to Note 7, Coastal GasLink, for additional information. Summarized Financial Information of Equity Investments year ended December 31 2024 2023 2022 (millions of Canadian $) Income Revenues 6,962 6,197 5,681 Operating and other expenses (3,783) (3,343) (3,290) Net income 3,026 2,457 2,031 Net income attributable to TC Energy 1,558 1,310 999 at December 31 2024 2023 (millions of Canadian $) Balance Sheet Current assets 3,959 3,279 Non-current assets 44,835 41,270 Current liabilities (2,111) (2,403) Non-current liabilities (21,729) (21,894)
Schedule of Distribution Received and Contribution made to Equity Investments	Distributions received from equity investments and contributions made to equity investments for the years ended December 31, 2024, 2023 and 2022 were as follows: year ended December 31 2024 2023 2022 (millions of Canadian $) Distributions Distributions received from operating activities of equity investments 1,607 1,158 955 Coastal GasLink LP subordinated loan repayment 1,2 3,147 — — Sur de Texas debt repayments 2,3 — — 2,404 Other 2 539 23 228 5,293 1,181 3,587 Contributions 2 Contributions to Coastal GasLink LP 1 3,964 3,231 1,414 Sur de Texas debt financing 3 — — 1,199 Contributions made to other equity investments 719 918 783 4,683 4,149 3,396 1 In December 2024, TC Energy made an equity contribution of $3,137 million to Coastal GasLink LP, which used the funds to repay the balance owing to TC Energy under the subordinated loan agreement. The contribution and repayment were included in Investing activities in the Consolidated statement of cash flows. Refer to Note 7, Coastal GasLink, for additional information. 2 Included in Investing activities in the Consolidated statement of cash flows. 3 Represents TC Energy's proportionate share of the Sur de Texas debt financing requirements and subsequent repayments. Refer to Note 12, Loans receivable from affiliates, for additional information.

LOANS RECEIVABLE FROM AFFILIA_2

LOANS RECEIVABLE FROM AFFILIATES (Tables)	12 Months Ended
	Dec. 31, 2024
Receivables [Abstract]
Schedule of Loan Receivable Interest Income and Foreign Exchange Impact	The Company's Consolidated statement of income reflects the related interest income and foreign exchange impact on this loan receivable until its repayment on March 15, 2022, which were fully offset upon consolidation with corresponding amounts included in TC Energy’s proportionate share of Sur de Texas equity earnings as follows: year ended December 31 Affected line item in the Consolidated statement of income (millions of Canadian $) 2024 2023 2022 Interest income 1 — — 19 Interest income and other Interest expense 2 — — (19) Income (loss) from equity investments Foreign exchange losses 1 — — (28) Foreign exchange (gains) losses, net Foreign exchange gains 1 — — 28 Income (loss) from equity investments 1 Included in the Corporate segment. 2 Included in the Mexico Natural Gas Pipelines segment.

RATE-REGULATED BUSINESSES (Tabl

RATE-REGULATED BUSINESSES (Tables)	12 Months Ended
	Dec. 31, 2024
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	at December 31 Remaining Recovery/ Settlement Period (years) 2024 2023 (millions of Canadian $) Regulatory Assets Deferred income taxes 1 n/a 2,593 2,204 Operating and debt-service regulatory assets 2 1 56 29 Pensions and other post-retirement benefits 1,3 n/a — 54 Foreign exchange on long-term debt 1,4 1-5 39 11 Other n/a 117 108 2,805 2,406 Less: Current portion included in Other current assets (Note 8) 123 76 2,682 2,330 Regulatory Liabilities Pipeline abandonment trust balances 5 n/a 2,686 2,252 Deferred income taxes – U.S. Tax Reform 6 n/a 1,197 1,137 Canadian Mainline short-term adjustment and toll-stabilization accounts 7,8 n/a 553 437 Cost of removal 9 n/a 376 351 Canadian Mainline bridging amortization account 7 6 322 376 Deferred income taxes 1 n/a 188 198 Pensions and other post-retirement benefits 3 n/a 122 6 Canadian Mainline long-term adjustment account 7,10 2 74 111 Operating and debt-service regulatory liabilities 2 1 50 23 ANR post-employment and retirement benefits other than pension 11 n/a 45 42 Other n/a 43 54 5,656 4,987 Less: Current portion included in Accounts payable and other (Note 17) 353 284 5,303 4,703 1 These regulatory assets and liabilities are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets or liabilities are not included in rate base and do not yield a return on investment during the recovery period. 2 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances to be included in determination of rates in the following year. 3 These balances represent the regulatory offset to pension plan and other post-retirement benefit obligations to the extent the amounts are expected to be collected from or refunded to customers in future rates. 4 Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. 5 This balance represents the amounts collected in tolls from customers and included in the LMCI restricted investments to fund future abandonment of the Company's CER-regulated pipeline facilities. 6 The U.S. corporate income tax rate was reduced from 35 per cent to 21 per cent in 2017 as a result of H.R.1, the Tax Cuts and Jobs Act (U.S. Tax Reform). This U.S. regulated operations balance, where applicable, represents established regulatory liabilities driven by 2018 FERC prescribed changes related to U.S. Tax Reform being amortized over varying terms that approximate the expected reversal of the underlying deferred tax liabilities that gave rise to the regulatory liabilities. 7 These regulatory accounts are used to capture revenue and cost variances plus toll-stabilization adjustments during the 2015-2030 settlement term. 8 Under the terms of the 2021-2026 Mainline Settlement, a portion of the STAA account commenced amortization in 2023 and the remainder commenced amortization in 2024, as predetermined thresholds were met, over the terms outlined per the settlement agreement. 9 This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated operations for future costs to be incurred. 10 Under the terms of the 2021-2026 Mainline Settlement, $223 million is amortized over the six-year settlement term. 11

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	The Company's Goodwill balance on the Consolidated balance sheet is comprised of the following amounts: at December 31 2024 2023 (millions) Canadian U.S. dollars Canadian dollars U.S. dollars Columbia Pipeline Group, Inc. 10,588 7,351 9,708 7,351 ANR 2,803 1,946 2,570 1,946 Great Lakes 176 122 161 122 North Baja 70 48 63 48 Tuscarora 33 23 30 23 13,670 9,490 12,532 9,490 Changes in Goodwill were as follows: (millions of Canadian $) U.S. Natural Balance at January 1, 2023 12,843 Foreign exchange rate changes (311) Balance at December 31, 2023 1 12,532 Foreign exchange rate changes 1,138 Balance at December 31, 2024 1 13,670 1 Represents gross amounts of goodwill as at December 31, 2024 of $15,405 million (2023 – $14,267 million), net of accumulated impairment of $1,735 million (2023 – $1,735 million).

OTHER LONG-TERM ASSETS (Tables)

OTHER LONG-TERM ASSETS (Tables)	12 Months Ended
	Dec. 31, 2024
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Schedule of Other Long-Term Assets	at December 31 2024 2023 (millions of Canadian $) Employee post-retirement benefits (Note 27) 758 518 Long-term contract assets (Note 6) 608 457 Deferred income tax assets (Note 19) 428 1,319 Capital projects in development 164 234 Fair value of derivative contracts (Note 28) 122 155 Other 330 198 2,410 2,881

NOTES PAYABLE (Tables)

NOTES PAYABLE (Tables)	12 Months Ended
	Dec. 31, 2024
Short-Term Debt [Abstract]
Schedule of Notes Payable	at December 31 2024 2023 (millions of Canadian $, unless otherwise noted) Outstanding Weighted Average Interest Rate per Annum Outstanding Weighted Average Interest Rate per Annum Canada 1 308 4.7 % — — U.S. (2024 – US$55; 2023 – nil) 79 4.7 % — — 387 — 1 At December 31, 2024, Notes payable consisted of Canadian dollar-denominated notes of nil (2023 – nil) and U.S. dollar-denominated notes of US$214 million (2023 – nil).
Schedule of Credit Facilities	These unsecured credit facilities included the following: at December 31 (billions of Canadian $, unless otherwise noted) 2024 2023 Borrowers Description Matures Total Facilities Unused Capacity 1 Total Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities 2 : TCPL Supports commercial paper program and for general corporate purposes December 2029 3.0 3.0 3.0 TCPL / TCPL USA Supports commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL December 2025 US 1.0 US 0.7 US 2.5 TCPL / TCPL USA Supports commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL December 2027 US 2.5 US 2.5 US 2.5 Columbia Pipelines Holding Company LLC 3 Supports commercial paper program and general corporate purposes of the borrower December 2027 US 1.5 US 1.5 US 1.0 Demand senior unsecured revolving credit facilities 2 : TCPL / TCPL USA Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL Demand 2.0 4 1.1 2.0 4 1 Unused capacity is net of commercial paper outstanding and facility draws. 2 Provisions of various trust indentures and credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and preferred shares. These trust indentures and credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2024, the Company was in compliance with all financial covenants. 3 Columbia Pipelines Holding Company LLC (CPHC LLC) is a partially-owned subsidiary of TC Energy with 40 per cent non-controlling interest. 4 Or the U.S. dollar equivalent.

ACCOUNTS PAYABLE AND OTHER (Tab

ACCOUNTS PAYABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2024
Payables and Accruals [Abstract]
Schedule of Accounts Payable and Other	at December 31 2024 2023 (millions of Canadian $) Trade payables 3,699 3,092 Fair value of derivative contracts (Note 28) 507 415 Regulatory liabilities (Note 13) 353 284 Income tax liabilities 143 76 Operating lease liabilities (Note 10) 60 57 Contract liabilities (Note 6) 30 47 Other 505 334 5,297 4,305

OTHER LONG-TERM LIABILITIES (Ta

OTHER LONG-TERM LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2024
Deferred Costs, Noncurrent [Abstract]
Schedule of Other Long-Term Liabilities	at December 31 2024 2023 (millions of Canadian $) Operating lease obligations (Note 10) 451 400 Fair value of derivative contracts (Note 28) 209 106 Asset retirement obligations 108 64 Employee post-retirement benefits (Note 27) 94 97 Other 189 324 1,051 991

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Schedule of Geographic Components of Income	Geographic Components of Income before Income Taxes year ended December 31 2024 2023 2022 (millions of Canadian $) Canada 1,219 (344) (2,133) Foreign 4,687 3,642 2,607 Income before Income Taxes 5,906 3,298 474
Schedule of Provision for Income Taxes	year ended December 31 2024 2023 2022 (millions of Canadian $) Current Canada 102 61 41 Foreign 393 803 322 495 864 363 Deferred Canada 135 8 (459) Foreign 292 (30) 418 427 (22) (41) Income Tax Expense 922 842 322
Reconciliation of Income Tax Expense	year ended December 31 2024 2023 2022 (millions of Canadian $) Income before income taxes 5,906 3,298 474 Federal and provincial statutory tax rate 23.0 % 23.0 % 23.0 % Expected income tax expense 1,358 759 109 Mexico foreign exchange exposure (246) 132 9 Income tax differential related to regulated operations (227) (260) (174) Income from non-controlling interests and equity investments (224) (56) (54) Foreign income tax rate differentials 167 (84) (216) Non-taxable capital (gains) and losses 18 182 173 Impact of Mexico inflationary adjustments 7 1 24 Valuation allowance (release) 4 182 198 Settlement of Mexico prior years' income tax assessments — — 196 Non-deductible goodwill impairment — — 91 Other 65 (14) (34) Income Tax Expense 922 842 322
Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet	at December 31 2024 2023 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,987 1,664 Disallowed interest carryforward 115 — Regulatory and other deferred amounts 612 583 Unrealized foreign exchange losses on long-term debt 467 206 Other 143 160 3,324 2,613 Less: Valuation allowance 931 690 2,393 1,923 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment 6,488 5,599 Equity investments 1,280 1,043 Taxes on future revenue requirement 612 496 Financial instruments 168 168 Other 301 270 8,849 7,576 Net Deferred Income Tax Liabilities 6,456 5,653 The above deferred tax amounts have been classified on the Consolidated balance sheet as follows: at December 31 2024 2023 (millions of Canadian $) Deferred Income Tax Assets Other long-term assets (Note 15) 428 1,319 Deferred Income Tax Liabilities Deferred income tax liabilities 6,884 6,972 Net Deferred Income Tax Liabilities 6,456 5,653
Reconciliation of the Annual Changes in the Total Unrecognized Tax Benefit	Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2024 2023 2022 (millions of Canadian $) Unrecognized tax benefit at beginning of year 85 91 80 Gross increases – tax positions in prior years 3 9 6 Gross decreases – tax positions in prior years (2) (1) — Gross increases – tax positions in current year 5 16 7 Gross decrease – tax positions in current year (2) — — Settlement (13) — — Lapse of statutes of limitations (4) (30) (2) Unrecognized Tax Benefit at End of Year 72 85 91

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	at December 31 2024 2023 Maturity Dates Outstanding Interest Rate 1 Outstanding Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Medium Term Notes Canadian 2025 to 2052 13,141 4.7 % 15,466 4.6 % Senior Unsecured Notes U.S. (2024 – US$11,792; 2023 – US$16,167) 2025 to 2049 16,985 5.5 % 21,349 5.0 % 30,126 36,815 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian — — 100 9.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2024 and 2023 – US$33) 2026 47 7.5 % 43 7.5 % 551 647 COLUMBIA PIPELINES OPERATING COMPANY LLC Senior Unsecured Notes U.S. (2024 – US$6,500; 2023 – US$6,100) 2025 to 2063 9,362 6.0 % 8,055 6.1 % COLUMBIA PIPELINES HOLDING COMPANY LLC Senior Unsecured Notes U.S. (2024 – US$1,900; 2023 – US$1,000) 2026 to 2034 2,737 5.9 % 1,320 6.2 % ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2024 – US$1,047; 2023 – US$1,172) 2025 to 2037 1,509 3.7 % 1,548 4.1 % TC PIPELINES, LP Senior Unsecured Notes U.S. (2024 and 2023 – US$850) 2025 to 2027 1,224 4.2 % 1,122 4.2 % GAS TRANSMISSION NORTHWEST LLC Senior Unsecured Notes U.S. (2024 and 2023 – US$375) 2030 to 2035 540 4.4 % 495 4.4 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM 2 Senior Unsecured Notes U.S. (2024 – nil; 2023 – US$250) — — 330 2.8 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2024 – US$104; 2023 – US$125) 2028 to 2030 150 7.6 % 165 7.6 % at December 31 2024 2023 Maturity Dates Outstanding Interest Rate 1 Outstanding Interest Rate 1 (millions of Canadian $, unless otherwise noted) TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. Senior Unsecured Term Loan U.S. (2024 – US$1,370; 2023 – US$1,800) 2028 1,973 7.2 % 2,377 7.7 % Senior Unsecured Revolving Credit Facility U.S. (2024 – nil; 2023 – US$185) 2028 — — 244 7.7 % 1,973 2,621 48,172 53,118 Current portion of long-term debt (2,955) (2,938) Unamortized debt discount and issue costs (252) (312) Fair value adjustments 3 11 108 44,976 49,976 1 Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. The effective interest rate is calculated by discounting the expected future interest payments, adjusted for loan fees, premiums and discounts. Weighted average and effective interest rates are stated as at the respective outstanding dates. 2 On August 15, 2024, US$250 million of senior notes outstanding held at PNGTS were assumed by the purchaser as part of the sale of PNGTS. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 3 The fair value adjustments include $109 million (2023 – $119 million) related to the acquisition of Columbia Pipeline Group, Inc. These adjustments also include a decrease of $139 million (2023 – $11 million) related to hedged interest rate risk and an increase of $41 million (2023 - nil) related to discontinued hedge interest rate risk. Refer to Note 28, Risk management and financial instruments, for additional information. The Company issued long-term debt over the three years ended December 31, 2024 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED August 2024 Term Loan 1 August 2024 US 1,242 Floating May 2023 Senior Unsecured Term Loan 2 May 2026 US 1,024 Floating March 2023 Senior Unsecured Notes 3 March 2026 US 850 6.20 % March 2023 Senior Unsecured Notes 3 March 2026 US 400 Floating March 2023 Medium Term Notes July 2030 1,250 5.28 % March 2023 Medium Term Notes 3 March 2026 600 5.42 % March 2023 Medium Term Notes 3 March 2026 400 Floating May 2022 Medium Term Notes May 2032 800 5.33 % May 2022 Medium Term Notes May 2026 400 4.35 % May 2022 Medium Term Notes May 2052 300 5.92 % COLUMBIA PIPELINES OPERATING COMPANY LLC September 2024 Senior Unsecured Notes October 2054 US 400 5.70 % August 2023 Senior Unsecured Notes November 2033 US 1,500 6.04 % August 2023 Senior Unsecured Notes November 2053 US 1,250 6.54 % August 2023 Senior Unsecured Notes August 2030 US 750 5.93 % August 2023 Senior Unsecured Notes August 2043 US 600 6.50 % August 2023 Senior Unsecured Notes August 2063 US 500 6.71 % COLUMBIA PIPELINES HOLDING COMPANY LLC September 2024 Senior Unsecured Notes October 2031 US 400 5.10 % January 2024 Senior Unsecured Notes January 2034 US 500 5.68 % August 2023 Senior Unsecured Notes August 2028 US 700 6.04 % August 2023 Senior Unsecured Notes August 2026 US 300 6.06 % GAS TRANSMISSION NORTHWEST LLC June 2023 Senior Unsecured Notes June 2030 US 50 4.92 % TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. January 2023 Senior Unsecured Term Loan January 2028 US 1,800 Floating January 2023 Senior Unsecured Revolving Credit Facility January 2028 US 500 Floating ANR PIPELINE COMPANY May 2022 Senior Unsecured Notes May 2032 US 300 3.43 % May 2022 Senior Unsecured Notes May 2034 US 200 3.58 % May 2022 Senior Unsecured Notes May 2037 US 200 3.73 % May 2022 Senior Unsecured Notes May 2029 US 100 3.26 % 1 In August 2024, TCPL entered into a term loan to facilitate the Spinoff Transaction and, in August 2024, the term loan was fully repaid and retired upon delivery of senior unsecured notes issued by 6297782 LLC. Refer to Note 4, Discontinued operations, for additional information. 2 Fully repaid and retired in September 2023. 3
Schedule of Repayments of Long-Term Debt	At December 31, 2024, principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2025 2026 2027 2028 2029 Principal repayments on long-term debt 2,955 2,810 3,158 6,083 1,333
Schedule of Retired Long-Term Debt	The Company retired/repaid long-term debt over the three years ended December 31, 2024 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED October 2024 Senior Unsecured Notes US 1,250 1.00 % October 2024 Senior Unsecured Notes 1 US 850 6.20 % October 2024 Senior Unsecured Notes 2 US 739 2.50 % October 2024 Senior Unsecured Notes 2 US 441 4.88 % October 2024 Senior Unsecured Notes 1 US 400 Floating October 2024 Senior Unsecured Notes 2 US 313 4.75 % October 2024 Senior Unsecured Notes 2 US 201 5.00 % October 2024 Senior Unsecured Notes 2 US 180 5.10 % October 2024 Medium Term Notes 1 600 5.42 % October 2024 Medium Term Notes 2 575 4.18 % October 2024 Medium Term Notes 1 400 Floating August 2024 Term Loan 3 US 1,242 Floating June 2024 Medium Term Notes 750 Floating October 2023 Senior Unsecured Notes US 625 3.75 % September 2023 Senior Unsecured Term Loan US 1,024 Floating July 2023 Medium Term Notes 750 3.69 % December 2022 Medium Term Notes 25 9.95 % August 2022 Senior Unsecured Notes US 1,000 2.50 % NOVA GAS TRANSMISSION LTD. March 2024 Debentures 100 9.90 % April 2023 Debentures US 200 7.88 % ANR PIPELINE COMPANY February 2024 Senior Unsecured Notes US 125 7.38 % TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. Various 2024 Senior Unsecured Term Loan US 430 Floating Various 2024 Senior Unsecured Revolving Credit Facility US 185 Floating Various 2023 Senior Unsecured Revolving Credit Facility US 315 Floating TUSCARORA GAS TRANSMISSION COMPANY November 2023 Unsecured Term Loan US 32 Floating 1 In October 2024, callable notes were retired at par. 2 In October 2024, TCPL purchased and cancelled notes at a 7.73 per cent weighted average discount, as a settlement of cash tender offers. 3 In August 2024, TCPL entered into a term loan to facilitate the Spinoff Transaction and, in August 2024, the term loan was fully repaid and retired upon delivery of senior unsecured notes issued by 6297782 LLC. Refer to Note 4, Discontinued operations, for additional information. In October 2024, TCPL commenced and completed its cash tender offers to purchase and cancel certain senior unsecured notes and medium term notes at a 7.73 per cent weighted average discount. In addition, the Company repaid and retired outstanding callable notes at par. These extinguishments of debt resulted in a pre-tax net gain of $228 million, primarily due to the fair value discount and recognition of unamortized debt issue costs related to these notes. The net gain on debt extinguishment was recorded in Interest expense in the Consolidated statement of income.
Schedule of Interest Expense	Interest Expense year ended December 31 2024 2023 2022 (millions of Canadian $) Interest on long-term debt 2,800 2,562 1,883 Interest on junior subordinated notes 638 617 543 Interest on short-term debt 60 165 153 Capitalized interest (191) (187) (27) Amortization and other financial charges 1 158 106 36 Gain on debt extinguishment (228) — — 3,237 3,263 2,588 Interest allocated to discontinued operations (Note 4) (218) (297) (288) 3,019 2,966 2,300 1 Amortization and other financial charges include amortization of transaction costs and debt discounts calculated using the effective interest method and losses on derivatives used to manage the Company's exposure to changes in interest rates.

JUNIOR SUBORDINATED NOTES (Tabl

JUNIOR SUBORDINATED NOTES (Tables)	12 Months Ended
	Dec. 31, 2024
Junior Subordinated Notes [Abstract]
Schedule of Junior Subordinated Notes	at December 31 2024 2023 Maturity Outstanding Effective Interest Rate 1 Outstanding Effective Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED US$1,000 issued 2007 at 6.35% 2 2067 1,440 6.2 % 1,320 6.5 % US$750 issued 2015 at 5.88% 3,4 2075 1,080 7.5 % 990 7.8 % US$1,200 issued 2016 at 6.13% 3,4 2076 1,729 8.0 % 1,585 8.3 % US$1,500 issued 2017 at 5.55% 3,4 2077 2,161 7.2 % 1,981 7.5 % $1,500 issued 2017 at 4.90% 3,4 2077 1,500 6.8 % 1,500 7.0 % US$1,100 issued 2019 at 5.75% 3,4 2079 1,584 7.7 % 1,453 8.0 % $500 issued 2021 at 4.45% 3,5 2081 500 5.7 % 500 5.7 % US$800 issued 2022 at 5.85% 3,5 2082 1,152 7.3 % 1,056 7.1 % 11,146 10,385 Unamortized debt discount and issue costs (98) (98) 11,048 10,287 1 The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for issue costs and discounts. 2 Junior subordinated notes of US$1.0 billion were issued in 2007 at a fixed rate of 6.35 per cent and converted in 2017 to bear interest at a floating rate. 3 The Junior subordinated notes were issued to TransCanada Trust (the Trust), a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TC Energy's financial statements since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. 4 The coupon rate is initially a fixed interest rate for the first 10 years and converts to a floating rate thereafter. 5 The coupon rate is initially a fixed interest rate for the first 10 years and resets every five years thereafter.

FOREIGN EXCHANGE (GAINS) LOSS_2

FOREIGN EXCHANGE (GAINS) LOSSES, NET (Tables)	12 Months Ended
	Dec. 31, 2024
Foreign Currency [Abstract]
Schedule of Foreign Exchange Contracts	year ended December 31 2024 2023 2022 (millions of Canadian $) Derivative instruments held for trading (Note 28) 418 (401) 151 Other (271) 81 34 147 (320) 185

NON-CONTROLLING INTERESTS (Tabl

NON-CONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2024
Noncontrolling Interest [Abstract]
Schedule of Non-controlling Interests	The Company's Net income (loss) attributable to non-controlling interests included in the Consolidated statement of income and Non-controlling interests included on the Consolidated balance sheet were as follows: (millions of Canadian $) Non-Controlling Interests Ownership at December 31, 2024 Income (Loss) Attributable to Non-Controlling Interests year ended December 31 at December 31 2024 2023 2022 2024 2023 Columbia Gas and Columbia Gulf 40 % 1 571 143 — 9,844 9,167 Portland Natural Gas Transmission System nil 1 30 41 37 — 106 Texas Wind Farms 100 % 1,2 (29) (38) — 168 182 TGNH 13.01 % 1 109 — — 756 — 681 146 37 10,768 9,455 1 Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 2 Tax equity investors own 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes and cash flows are allocated. TC Energy owns 100 per cent of the Class B Membership Interests.

COMMON SHARES (Tables)

COMMON SHARES (Tables)	12 Months Ended
	Dec. 31, 2024
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Schedule of Common Shares	Number of Shares Amount (thousands) (millions of Canadian $) Outstanding at January 1, 2022 980,816 26,716 Issued under public offering 1 28,400 1,754 Dividend reinvestment and share purchase plan 5,916 342 Exercise of options 2,830 183 Outstanding at December 31, 2022 1,017,962 28,995 Dividend reinvestment and share purchase plan 19,464 1,003 Exercise of options 62 4 Outstanding at December 31, 2023 1,037,488 30,002 Exercise of options 1,607 99 Outstanding at December 31, 2024 1,039,095 30,101 1 Net of underwriting commissions and deferred income taxes.
Schedule of Weighted Average Shares	Weighted Average Common Shares Outstanding at December 31 (millions) 2024 2023 2022 Basic 1,038 1,030 995 Diluted 1,038 1,030 996
Schedule of Stock Options Activity	Number of Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (thousands) (years) Options outstanding at January 1, 2024 7,436 $62.36 Options exercised (363) $56.85 Options forfeited/expired (598) $63.70 Options Outstanding at September 30, 2024 6,475 $62.54 3.5 Options Exercisable at September 30, 2024 4,975 $63.54 3.0 Options cancelled on October 1, 2024 (6,475) $62.54 Options issued on October 1, 2024 5,889 $59.72 Options exercised (1,244) $54.49 Options forfeited/expired (171) $72.17 Options Outstanding at December 31, 2024 4,474 $60.69 3.6 Options Exercisable at December 31, 2024 3,169 $62.50 3.1
Schedule of Options Valuation Assumptions	The Company used a binomial model for determining the fair value of options granted and applied the following weighted average assumptions: year ended December 31 2024 1 2023 2022 Weighted average fair value — $7.88 $8.24 Expected life (years) 2 — 5.1 5.4 Interest rate — 2.9 % 1.6 % Volatility 3 — 24 % 22 % Dividend yield — 6.3 % 5.5 % 1 Commencing in 2024, the Company no longer issues stock options to employees or officers. 2 Expected life is based on historical exercise activity. 3 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.
Schedule of Additional Option Information	The following table summarizes additional stock option information: year ended December 31 2024 2023 2022 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 17 — 33 Total fair value of options that have vested 99 76 89 Total options vested 1.5 million 1.5 million 1.6 million

PREFERRED SHARES (Tables)

PREFERRED SHARES (Tables)	12 Months Ended
	Dec. 31, 2024
Preferred Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Schedule of Preferred Shares	at December 31, 2024 Number of Shares Outstanding Current Yield Annual Dividend Per Share 1,2 Redemption Price Per Share Redemption and Conversion Option Date Right to Convert Into Carrying Value December 31 3 2024 2023 2022 (thousands) (millions of Canadian $) Cumulative First Preferred Shares Series 1 18,424 4.94 % 4 $1.23475 $25.00 December 31, 2029 Series 2 456 360 360 Series 2 3,576 Floating 5 Floating $25.00 December 31, 2029 Series 1 83 179 179 Series 3 9,997 1.69 % $0.4235 $25.00 June 30, 2025 Series 4 246 246 246 Series 4 4,003 Floating 5 Floating $25.00 June 30, 2025 Series 3 97 97 97 Series 5 12,071 1.95 % $0.48725 $25.00 January 30, 2026 Series 6 294 294 294 Series 6 1,929 Floating 5 Floating $25.00 January 30, 2026 Series 5 48 48 48 Series 7 24,000 5.99 % 4 $1.49625 $25.00 April 30, 2029 Series 8 589 589 589 Series 9 16,703 5.08 % 4 $1.27 $25.00 October 30, 2029 Series 10 410 442 442 Series 10 1,297 Floating 5 Floating $25.00 October 30, 2029 Series 9 32 — — Series 11 10,000 3.35 % $0.83775 $25.00 November 28, 2025 Series 12 244 244 244 2,499 2,499 2,499 1 Each of the even-numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90-day Government of Canada Treasury bill rate (T-bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10), or 2.96 per cent (Series 12). These rates reset quarterly with the then current T-Bill rate. 2 The odd-numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then Five-Year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), or 2.96 per cent (Series 11). 3 Net of underwriting commissions and deferred income taxes. 4 The fixed rate dividend for Series 1, Series 7 and Series 9 preferred shares increased from 3.48 per cent to 4.94 per cent on December 31, 2024, 3.90 per cent to 5.99 per cent on April 30, 2024 and from 3.76 per cent to 5.08 per cent on October 30, 2024, respectively, and is due to reset on every fifth anniversary thereafter. No Series 7 preferred shares were converted on the April 30, 2024 conversion date. 5 The floating quarterly dividend rate for the Series 2 preferred shares is 5.40 per cent for the period starting December 31, 2024 to, but excluding, March 31, 2025. The floating quarterly dividend rate for the Series 4 preferred shares is 4.76 per cent for the period starting December 31, 2024 to, but excluding, March 31, 2025. The floating quarterly dividend rate for the Series 6 preferred shares is 5.52 per cent for the period starting October 30, 2024 to, but excluding, January 30, 2025 The floating quarterly dividend rate for the Series 10 preferred shares is 6.33 per cent for the period starting October 30, 2024 to, but excluding, January 30, 2025. These rates will reset each quarter going forward.

OTHER COMPREHENSIVE INCOME(LO_2

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) (Tables)	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
Components of Other Comprehensive Income (Loss)	Components of other comprehensive income (loss), including the portion attributable to non-controlling interests and related tax effects, were as follows: year ended December 31, 2024 Before Tax Amount Income Tax (Expense) Recovery Net of Tax Amount (millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations 1,582 20 1,602 Reclassification of foreign currency translation (gains) on net investment on disposal of foreign operations 1 (25) — (25) Change in fair value of net investment hedges (23) 5 (18) Change in fair value of cash flow hedges 46 (11) 35 Reclassification to net income of (gains) losses on cash flow hedges (20) 4 (16) Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans 107 (24) 83 Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans (6) — (6) Other comprehensive income (loss) on equity investments 230 (57) 173 Other Comprehensive Income (Loss) 1,891 (63) 1,828 1 Represents the controlling and non-controlling currency translation adjustment gains related to PNGTS. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. year ended December 31, 2023 Before Tax Amount Income Tax (Expense) Recovery Net of Tax Amount (millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations (1,148) 7 (1,141) Change in fair value of net investment hedges 23 (6) 17 Reclassification to net income of (gains) losses on cash flow hedges 97 (23) 74 Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans (15) 4 (11) Other comprehensive income (loss) on equity investments (283) 72 (211) Other Comprehensive Income (Loss) (1,326) 54 (1,272) year ended December 31, 2022 Before Tax Amount Income Tax (Expense) Recovery Net of Tax Amount (millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations 1,410 84 1,494 Change in fair value of net investment hedges (48) 12 (36) Change in fair value of cash flow hedges (58) 19 (39) Reclassification to net income of (gains) losses on cash flow hedges 63 (21) 42 Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans 81 (18) 63 Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans 9 (3) 6 Other comprehensive income (loss) on equity investments 1,156 (289) 867 Other Comprehensive Income (Loss) 2,613 (216) 2,397
Schedule of Changes in Accumulated Other Comprehensive Income	The changes in AOCI by component, net of tax, are as follows: (millions of Canadian $) Currency Translation Adjustments Cash Flow Hedges Pension and Other Post-Retirement Benefit Plan Adjustments Equity Investments Total AOCI balance at January 1, 2022 (1,009) (112) (113) (200) (1,434) Other comprehensive income (loss) before reclassifications 1 1,450 (39) 63 870 2,344 Amounts reclassified from AOCI — 42 6 (3) 45 Net current period other comprehensive income (loss) 1,450 3 69 867 2,389 AOCI balance at December 31, 2022 441 (109) (44) 667 955 Other comprehensive income (loss) before reclassifications 1 (231) — (11) (195) (437) Amounts reclassified from AOCI — 74 — (16) 58 Net current period other comprehensive income (loss) (231) 74 (11) (211) (379) Impact of non-controlling interest 2 (527) — — — (527) AOCI balance at December 31, 2023 (317) (35) (55) 456 49 Other comprehensive income (loss) before reclassifications 1 692 35 83 188 998 Amounts reclassified from AOCI 3,4 (15) (16) (6) (15) (52) Net current period other comprehensive income (loss) 677 19 77 173 946 Impact of non-controlling interest 5 (21) — — — (21) Impact of spinoff of Liquids Pipelines business 6 (741) — — — (741) AOCI balance at December 31, 2024 (402) (16) 22 629 233 1 Other comprehensive income(loss) before reclassifications of currency translation adjustments are net of non-controlling interest gains of $903 million (2023 – losses of $366 million; 2022 – gains of $8 million). 2 Represents the AOCI attributable to the 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf upon its sale on October 4, 2023. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 3 Gains related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $5 million ($4 million, net of tax) at December 31, 2024. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time; however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. 4 Includes the controlling interest of the AOCI attributable to PNGTS recognized in Net gain (loss) on sale of assets upon the sale of PNGTS on August 15, 2024. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 5 Represents the AOCI attributable to CFE's 13.01 per cent non-controlling equity interest in TGNH. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. 6 Represents the AOCI attributable to the Spinoff Transaction. Refer to Note 4, Discontinued operations, for additional information.
Schedule of Reclassifications out of Accumulated Other Comprehensive Income	Details about reclassifications out of AOCI into the Consolidated statement of income were as follows: year ended December 31 Amounts reclassified from AOCI 1 Affected line item in the Consolidated statement of income 2024 2023 2022 (millions of Canadian $) Cash flow hedges Commodities 32 (85) (47) Revenues (Power and Energy Solutions) Interest rate (12) (12) (16) Interest expense 20 (97) (63) Total before tax (4) 23 21 Income tax (expense) recovery 16 (74) (42) Net of tax Pension and other post-retirement benefit plan adjustments Amortization of actuarial gains (losses) 6 — (11) Plant operating costs and other 2 Settlement gain (loss) — — 2 Plant operating costs and other 2 6 — (9) Total before tax — — 3 Income tax (expense) recovery 6 — (6) Net of tax Equity investments Equity income (loss) 19 22 4 Income (loss) from equity investments (4) (6) (1) Income tax (expense) recovery 15 16 3 Net of tax Currency translation adjustments Foreign currency translation gains on disposal of foreign operations 15 — — Net gain (loss) on sale of assets — — — Income tax (expense) recovery 15 — — Net of tax 1 Amounts in parentheses indicate expenses to the Consolidated statement of income. 2 These AOCI components are included in the computation of net benefit cost. Refer to Note 27, Employee post-retirement benefits, for additional information.

EMPLOYEE POST-RETIREMENT BENE_2

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2024
Retirement Benefits [Abstract]
Schedule of Contributions for Defined Benefit Plans	Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2024 2023 2022 (millions of Canadian $) DB Plans — 28 78 Other post-retirement benefit plans 8 9 8 Savings and DC Plans 71 64 64 79 101 150
Schedule of Change in Benefit Obligations, Change in Plan Assets, and Funded Status	The Company's funded status was comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2024 2023 2024 2023 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,356 3,081 285 310 Service cost 108 93 1 3 Interest cost 160 158 14 16 Employee contributions 11 7 2 2 Benefits paid (194) (185) (24) (44) Actuarial (gain) loss (39) 219 (5) 2 South Bow - transition of benefit obligation 2 (118) — (1) — Foreign exchange rate changes 58 (17) 16 (4) Benefit obligation – end of year 3,342 3,356 288 285 Change in Plan Assets Plan assets at fair value – beginning of year 3,697 3,481 358 354 Actual return on plan assets 485 385 17 24 Employer contributions 3,4 — 28 (41) 9 Employee contributions 11 7 2 2 Benefits paid (194) (185) (25) (23) South Bow - transition of plan assets 2 (119) — — — Foreign exchange rate changes 68 (19) 28 (8) Plan assets at fair value – end of year 3,948 3,697 339 358 Funded Status – Plan Surplus 606 341 51 73 1 The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation. 2 Reflects the impact of the Spinoff Transaction of the Liquids Pipelines business on October 1, 2024. 3 The Company reduced letters of credit by $133 million in the Canadian DB Plan (2023 – $78 million) for funding purposes. 4 OPEB surplus of $49 million was transferred to pay future active employee medical expenses. Additional pension benefit plan assets were as follows: at December 31 Pension (millions of Canadian $) 2024 2023 TC Energy plan assets at fair value 3,948 3,697 South Bow plan assets held in trust 1 110 — Plan assets at fair value – end of year 4,058 3,697 1 Related to the transfer of pension assets to South Bow. The final transfer will be adjusted for investment returns and benefit payments from October 1, 2024 to the transfer date. The $110 million is reflected in Long-term assets of discontinued operations.
Schedule of Amounts Recognized in the Balance Sheet for its DB Plans and Other Post-Retirement Benefits Plans	The amounts recognized on the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans were as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2024 2023 2024 2023 Other long-term assets (Note 15) 606 341 152 177 Accounts payable and other — — (7) (7) Other long-term liabilities (Note 18) — — (94) (97) 606 341 51 73
Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets	Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that were not fully funded: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2024 2023 2024 2023 Projected benefit obligation 1 — — (101) (104) Plan assets at fair value — — — — Funded Status – Plan Deficit — — (101) (104) 1 The projected benefit obligation for the pension benefit plans differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels.
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for All DB Plans	The funded status based on the accumulated benefit obligation for all DB Plans was as follows: at December 31 2024 2023 (millions of Canadian $) Accumulated benefit obligation (3,097) (3,090) Plan assets at fair value 1 4,058 3,697 Funded Status – Plan Surplus 961 607 1 Includes an estimated $110 million for future transfer to South Bow. The final transfer will be adjusted for investment returns and benefit payments from October 1, 2024, the date of the Spinoff Transaction to the transfer date.
Schedule of Weighted Average Asset Allocations and Target Allocations by Asset Category	The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: at December 31 Percentage of Target Allocations 2024 2023 2024 Fixed income securities 37 % 41 % 25% to 50% Equity securities 49 % 44 % 25% to 55% Other investments 14 % 15 % 10% to 35% 100 % 100 %
Schedule of Allocation of Plan Assets, Employer and Related Party Securities	Fixed income and equity securities include the Company's and its related parties debt and common shares as follows: at December 31 Percentage of (millions of Canadian $) 2024 2023 2024 2023 Fixed income securities 44 7 1.1 % 0.2 % Equity securities 3 2 0.1 % 0.1 %
Schedule of Plan Assets for DB Plans and Other Post-Retirement Benefits Measured at Fair Value	The following table presents plan assets for DB Plans and OPEB Plans measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. Refer to Note 28, Risk management and financial instruments, for additional information. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2024 2023 2024 2023 2024 2023 2024 2023 2024 2023 Asset Category 1 Cash and Cash Equivalents 138 68 — 1 — — 138 69 3 2 Equity Securities: Canadian 128 121 — — — — 128 121 3 3 U.S. 1,234 965 — — — — 1,234 965 28 24 International 182 167 209 187 — — 391 354 9 9 Global — — 100 74 — — 100 74 2 2 Emerging 66 54 150 140 — — 216 194 5 5 Fixed Income Securities: Canadian Bonds: Federal — — 55 266 — — 55 266 1 7 Provincial — — 312 314 — — 312 314 7 8 Municipal — — 14 16 — — 14 16 — — Corporate — — 323 143 — — 323 143 7 4 U.S. Bonds: Federal 151 185 255 240 — — 406 425 9 10 Municipal — — 1 1 — — 1 1 — — Corporate 246 312 158 74 — — 404 386 9 10 International: Government 4 4 17 11 — — 21 15 1 — Corporate — — 66 83 — — 66 83 2 2 Mortgage backed 37 43 23 17 — — 60 60 1 1 Net forward contracts — — (201) (131) — — (201) (131) (4) (4) Other Investments: Real estate — — — — 276 283 276 283 6 7 Infrastructure — — — — 282 269 282 269 7 7 Private equity funds — — — — 32 10 32 10 1 — Funds held on deposit 138 138 — — — — 138 138 3 3 Derivatives — — 1 — — — 1 — — — 2,324 2,057 1,483 1,436 590 562 4,397 4,055 100 100 1 Includes an estimated $110 million for future transfer to South Bow. The final transfer will be adjusted for investment returns and benefit payments from October 1, 2024, the date of the Spinoff Transaction to the transfer date.
Schedule of the Net Change in the Level III Fair Value Category	The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Balance at December 31, 2022 632 Purchases and sales (76) Realized and unrealized gains (losses) 6 Balance at December 31, 2023 562 Purchases and sales (15) Realized and unrealized gains (losses) 43 Balance at December 31, 2024 590
Schedule of Estimated Future Benefit Payments	The following are estimated future benefit payments, which reflect expected future service: at December 31 Other Post-Retirement Benefits (millions of Canadian $) Pension Benefits 2025 209 24 2026 212 24 2027 216 24 2028 218 24 2029 221 23 2030 to 2034 1,139 110
Schedule of Weighted Average Assumptions Used in Calculating Benefit Obligation	The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows: at December 31 Pension Other Post-Retirement 2024 2023 2024 2023 Discount rate 4.90 % 4.75 % 5.45 % 5.10 % Rate of compensation increase 3.05 % 3.20 % — —
Schedule of Significant Weighted Average Actuarial Assumptions Adopted in Measuring Net Benefit Plan Costs	The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows: year ended December 31 Pension Other Post-Retirement 2024 2023 2022 2024 2023 2022 Discount rate 4.75 % 5.15 % 3.05 % 5.15 % 5.45 % 3.10 % Expected long-term rate of return on plan assets 6.60 % 6.45 % 6.10 % 4.50 % 4.50 % 3.25 % Rate of compensation increase 3.15 % 3.25 % 3.00 % — — —
Schedule of Net Benefit Costs	The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans was as follows: year ended December 31 Pension Other Post-Retirement (millions of Canadian $) 2024 2023 2022 2024 2023 2022 Service cost 1 108 93 145 1 3 5 Other components of net benefit cost 1 Interest cost 160 158 125 14 16 13 Expected return on plan assets (248) (234) (239) (14) (16) (14) Amortization of actuarial loss — — 10 — — 1 Amortization of regulatory asset — — 12 (2) — 1 Settlement gain – AOCI — — (2) — — — (88) (76) (94) (2) — 1 Net Benefit Cost Recognized 20 17 51 (1) 3 6 1 Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income.
Schedule of the Pre-Tax Amounts Recognized in AOCI	Pre-tax amounts recognized in AOCI were as follows: at December 31 2024 2023 2022 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Net loss (gain) (24) — 71 6 38 24
Schedule of the Pre-Tax Amounts Recognized in OCI	Pre-tax amounts recognized in OCI were as follows: year ended December 31 2024 2023 2022 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Amortization of net gain (loss) from AOCI to net income 6 — — — (10) (1) Settlement — — — — 2 — Funded status adjustment (101) (6) 33 (18) (101) 20 (95) (6) 33 (18) (109) 19

RISK MANAGEMENT AND FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2024
Risk Management and Financial Instruments [Abstract]
Summary of Derivative Instruments	The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows: at December 31 2024 2023 Fair 1,2 Notional Amount Fair 1,2 Notional Amount (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2025) 3 (11) US 100 2 US 200 U.S. dollar foreign exchange options — — 8 US 1,000 (11) US 100 10 US 1,200 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2024 and 2023, Net income (loss) included net realized gains of less than $1 million related to the interest component of cross-currency swap settlements which are reported within Interest expense. The notional amounts and fair values of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2024 2023 (millions of Canadian $, unless otherwise noted) Notional amount 26,000 (US 18,000) 27,800 (US 21,100) Fair value 25,700 (US 17,800) 26,600 (US 20,200) The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations was as follows: at December 31, 2024 Power Natural Gas Foreign Exchange Interest Rate Net sales 1 10,192 53 — — Millions of U.S. dollars — — 5,648 2,800 Millions of Mexican pesos — — 16,750 — Maturity dates 2025-2044 2025-2031 2025-2027 2030-2034 1 Volumes for power and natural gas derivatives are in GWh and Bcf, respectively. at December 31, 2023 Power Natural Gas Foreign Exchange Interest Rate Net sales 1 9,209 50 — — Millions of U.S. dollars — — 4,978 2,000 Millions of Mexican pesos — — 20,000 — Maturity dates 2024-2044 2024-2029 2024-2026 2030-2034 1
Schedule of Financial Instruments	The following table details the fair value of non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy: at December 31 2024 2023 Carrying Amount Fair Value Carrying Fair (millions of Canadian $) Long-term debt, including current portion (Note 20) 1,2 (47,931) (48,318) (52,914) (52,815) Junior subordinated notes (Note 21) (11,048) (10,824) (10,287) (9,217) (58,979) (59,142) (63,201) (62,032) 1 Long-term debt is recorded at amortized cost, except for US$2.8 billion (2023 – US$2.0 billion) that is attributed to hedged risk and recorded at fair value. 2 Net income (loss) for 2024 included unrealized gains of $128 million (2023 – unrealized losses of $53 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships. Available-for-sale assets summary The following tables summarize additional information about the Company's restricted investments that were classified as available-for-sale assets: at December 31 2024 2023 LMCI Restricted Investments Other Restricted Investments 1 LMCI Restricted Investments Other Restricted Investments 1 (millions of Canadian $) Fair value of fixed income securities 2,3 Maturing within 1 year — 33 — 35 Maturing within 1-5 years 3 256 8 241 Maturing within 5-10 years 1,578 — 1,340 — Fair value of equity securities 2,4 1,070 64 883 50 2,651 353 2,231 326 1 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. 2 Available-for-sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet. 3 Classified in Level II of the fair value hierarchy. 4 Classified in Level I of the fair value hierarchy. The balance sheet classification of the fair value of derivative instruments was as follows: at December 31, 2024 Cash Flow Hedges Fair Value Hedges Net Held for Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 8) Commodities 2 18 — — 287 305 Foreign exchange — — — 42 42 18 — — 329 347 Other long-term assets (Note 15) Commodities 2 9 — — 104 113 Foreign exchange — — — 9 9 9 — — 113 122 Total Derivative Assets 27 — — 442 469 Accounts payable and other (Note 17) Commodities 2 (1) — — (291) (292) Foreign exchange — — (11) (183) (194) Interest rate — (21) — — (21) (1) (21) (11) (474) (507) Other long-term liabilities (Note 18) Commodities 2 (1) — — (46) (47) Foreign exchange — — — (44) (44) Interest rate — (118) — — (118) (1) (118) — (90) (209) Total Derivative Liabilities (2) (139) (11) (564) (716) Total Derivatives 25 (139) (11) (122) (247) 1 Fair value equals carrying value. 2 Includes purchases and sales of power and natural gas. The balance sheet classification of the fair value of derivative instruments was as follows: at December 31, 2023 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 8) Commodities 2 9 — — 499 508 Foreign exchange — — 10 71 81 9 — 10 570 589 Other long-term assets (Note 15) Commodities 2 3 — — 86 89 Foreign exchange — — — 30 30 Interest rate — 36 — — 36 3 36 — 116 155 Total Derivative Assets 12 36 10 686 744 Accounts payable and other (Note 17) Commodities 2 (1) — — (382) (383) Foreign exchange — — — (14) (14) Interest rate — (18) — — (18) (1) (18) — (396) (415) Other long-term liabilities (Note 18) Commodities 2 — — — (75) (75) Foreign exchange — — — (2) (2) Interest rate — (29) — — (29) — (29) — (77) (106) Total Derivative Liabilities (1) (47) — (473) (521) Total Derivatives 11 (11) 10 213 223 1 Fair value equals carrying value. 2 Includes purchases and sales of power and natural gas.
Unrealized Gain (Loss) on Investments	year ended December 31 2024 2023 2022 (millions of Canadian $) LMCI Restricted Investments 1 Other Restricted Investments 2 LMCI Restricted Investments 1 Other Restricted Investments 2 LMCI Restricted Investments 1 Other Restricted Investments 2 Net unrealized gains (losses) 218 9 179 13 (223) (7) Net realized gains (losses) 3 3 2 (28) — (28) — 1 Unrealized and realized gains (losses) arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory liabilities or regulatory assets. 2 Unrealized and realized gains (losses) on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income. 3 Realized gains (losses) on the sale of LMCI restricted investments are determined using the average cost basis.
Realized Gain (Loss) on Investments	year ended December 31 2024 2023 2022 (millions of Canadian $) LMCI Restricted Investments 1 Other Restricted Investments 2 LMCI Restricted Investments 1 Other Restricted Investments 2 LMCI Restricted Investments 1 Other Restricted Investments 2 Net unrealized gains (losses) 218 9 179 13 (223) (7) Net realized gains (losses) 3 3 2 (28) — (28) — 1 Unrealized and realized gains (losses) arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory liabilities or regulatory assets. 2 Unrealized and realized gains (losses) on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income. 3 Realized gains (losses) on the sale of LMCI restricted investments are determined using the average cost basis.
Derivative Instruments - Balance Sheet and Income Statement Information	The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities: at December 31 Carrying Amount Fair Value Hedging Adjustments 1 (millions of Canadian $) 2024 2023 2024 2023 Long-term debt (3,935) (2,630) 98 11 1 At December 31, 2024, adjustments for discontinued hedging relationships included in this balance was a liability of $41 million (2023 – nil). The following summary does not include hedges of the net investment in foreign operations: year ended December 31 2024 2023 2022 (millions of Canadian $) Derivative Instruments Held for Trading 1 Unrealized gains (losses) in the year Commodities 2 (71) 132 (11) Foreign exchange (Note 22) (266) 246 (149) Interest rate (71) — — Realized gains (losses) in the year Commodities 199 192 46 Foreign exchange (Note 22) (152) 155 (2) Interest rate 29 — — Derivative Instruments in Hedging Relationships Realized gains (losses) in the year Commodities 33 (2) (73) Interest rate (52) (43) (3) 1 Realized and unrealized gains (losses) on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues in the Consolidated statement of income. Realized and unrealized gains (losses) on foreign exchange held-for-trading derivative instruments are included on a net basis in Foreign exchange (gains) losses, net in the Consolidated statement of income. Realized and unrealized gains (losses) on interest rate derivatives are included on a net basis in Interest expense in the Consolidated statement of income. 2 In 2024, unrealized gains of $6 million were reclassified to Net Income (loss) from AOCI related to discontinued cash flow hedges (2023 and 2022 – nil). The following table details amounts presented in the Consolidated statement of income in which the effects of fair value or cash flow hedging relationships were recorded: year ended December 31 2024 2023 2022 (millions of Canadian $) Fair Value Hedges Interest rate contracts 1 Hedged items (126) (98) (30) Derivatives designated as hedging instruments (52) (43) (1) Cash Flow Hedges Reclassification of gains (losses) on derivative instruments from AOCI to Net income (loss) 2,3 Commodities 4 32 (85) (47) Interest rate 1 (12) (12) (16) 1 Presented within Interest expense in the Consolidated statement of income. 2 Refer to Note 26, Other comprehensive income (loss) and accumulated other comprehensive income (loss), for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests. 3 There are no amounts recognized in earnings that were excluded from effectiveness testing. 4 Presented within Revenues (Power and Energy Solutions) in the Consolidated statement of income. In 2024, unrealized gains of $6 million were reclassified to Net Income (loss) from AOCI related to discontinued cash flow hedges (2023 and 2022– nil).
Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships	The components of OCI (Note 26) related to the change in fair value of derivatives in cash flow hedging relationships before tax and including the portion attributable to non-controlling interests were as follows: year ended December 31 2024 2023 2022 (millions of Canadian $, pre-tax) Gains (losses) in fair value of derivative instruments recognized in OCI 1 Commodities 46 — (94) Interest rate — — 36 46 — (58) 1 No amounts have been excluded from the assessment of hedge effectiveness.
Schedule of Offsetting Assets	The following tables show the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: at December 31, 2024 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 418 (290) 128 Foreign exchange 51 (49) 2 469 (339) 130 Derivative Instrument Liabilities Commodities (339) 290 (49) Foreign exchange (238) 49 (189) Interest rate (139) — (139) (716) 339 (377) 1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2023 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 597 (418) 179 Foreign exchange 111 (16) 95 Interest rate 36 (5) 31 744 (439) 305 Derivative Instrument Liabilities Commodities (458) 418 (40) Foreign exchange (16) 16 — Interest rate (47) 5 (42) (521) 439 (82) 1 Amounts available for offset do not include cash collateral pledged or received.
Schedule of Offsetting Liabilities	The following tables show the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: at December 31, 2024 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 418 (290) 128 Foreign exchange 51 (49) 2 469 (339) 130 Derivative Instrument Liabilities Commodities (339) 290 (49) Foreign exchange (238) 49 (189) Interest rate (139) — (139) (716) 339 (377) 1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2023 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 597 (418) 179 Foreign exchange 111 (16) 95 Interest rate 36 (5) 31 744 (439) 305 Derivative Instrument Liabilities Commodities (458) 418 (40) Foreign exchange (16) 16 — Interest rate (47) 5 (42) (521) 439 (82) 1 Amounts available for offset do not include cash collateral pledged or received.
Schedule of Fair Value of Assets and Liabilities Measured on a Recurring Basis	The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non‑current portions, were categorized as follows: at December 31, 2024 Quoted Prices in Active Markets Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets Commodities 126 214 78 418 Foreign exchange — 51 — 51 Derivative Instrument Liabilities Commodities (116) (217) (6) (339) Foreign exchange — (238) — (238) Interest rate — (139) — (139) 10 (329) 72 (247) 1 There were no transfers from Level II to Level III for the year ended December 31, 2024. The Company has entered into contracts to sell 50 MW of power commencing in 2025 with terms ranging from 15 to 20 years provided from specified renewable sources in the Province of Alberta. The fair value of these contracts is classified in Level III of the fair value hierarchy and is based on the assumption that the contract volumes will be sourced approximately 80 per cent from wind generation, 10 per cent from solar generation and 10 per cent from the market. at December 31, 2023 Quoted Prices in Active Markets (Level I) Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets Commodities 387 200 10 597 Foreign exchange — 111 — 111 Interest rate — 36 — 36 Derivative Instrument Liabilities Commodities (307) (130) (21) (458) Foreign exchange — (16) — (16) Interest rate — (47) — (47) 80 154 (11) 223 1 There were no transfers from Level II to Level III for the year ended December 31, 2023.
Schedule of Net Change in the Level III Fair Value Category	The following table presents the net change in fair value of derivative assets and liabilities classified in Level III of the fair value hierarchy: (millions of Canadian $, pre-tax) 2024 2023 Balance at beginning of year (11) (11) Net gains (losses) included in Net income (loss) 54 (2) Transfers to Level II 29 2 Balance at End of Year 1 72 (11) 1 Revenues .

CHANGES IN OPERATING WORKING _2

CHANGES IN OPERATING WORKING CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2024
CHANGES IN OPERATING WORKING CAPITAL
Schedule of changes in operating working capital	year ended December 31 2024 ¹ 2023 ¹ 2022 ¹ (millions of Canadian $) (Increase) decrease in Accounts receivable (13) (394) (575) (Increase) decrease in Inventories (16) (56) (190) (Increase) decrease in Other current assets (97) 618 118 Increase (decrease) in Accounts payable and other 365 (206) (83) Increase (decrease) in Accrued interest (40) 245 91 (Increase) Decrease in Operating Working Capital 199 207 (639) 1 Includes continuing and discontinued operations.

COMMITMENTS, CONTINGENCIES AN_2

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Schedule of Guarantees	The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees were as follows: at December 31 2024 2023 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas Renewable to 2053 93 — 97 — Bruce Power Renewable to 2065 88 — 88 — Other jointly-owned entities to 2032 59 1 24 1 240 1 209 1 1 TC Energy's share of the potential estimated current or contingent exposure.

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Variable Interest Entities	The consolidated VIEs whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations, or are not considered a business, were as follows: at December 31 (millions of Canadian $) 2024 1 2023 2 ASSETS Current Assets Cash and cash equivalents 311 188 Accounts receivable 839 473 Inventories 205 90 Other current assets 121 49 Current assets of discontinued operations — 5 1,476 805 Plant, Property and Equipment 49,904 27,477 Equity Investments 865 823 Restricted Investments 950 — Goodwill 479 439 Regulatory Assets 53 12 Other Long-Term Assets 59 — Long-Term Assets of Discontinued Operations — 172 53,786 29,728 LIABILITIES Current Liabilities Accounts payable and other 1,866 1,092 Accrued interest 202 210 Current portion of long-term debt 2,062 28 Current liabilities of discontinued operations — 43 4,130 1,373 Regulatory Liabilities 1,232 280 Other Long-Term Liabilities 70 46 Deferred Income Tax Liabilities 7 22 Long-Term Debt 12,387 11,388 Long-Term Liabilities of Discontinued Operations — 10 17,826 13,119 1 On April 1, 2024, the NGTL System was classified as a VIE when its ownership was transferred from Nova Gas Transmission Ltd. to NGTL GP Ltd. on behalf of NGTL Limited Partnership. 2 Columbia Gas and Columbia Gulf were classified as a VIE upon TC Energy's sale of a 40 per cent non-controlling equity interest on October 4, 2023. Refer to Note 30, Strategic alliance, acquisitions and dispositions, for additional information. The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs were as follows: at December 31 (millions of Canadian $) 2024 2023 Balance Sheet Exposure Equity Investments Bruce Power 7,043 6,241 Coastal GasLink 1,006 294 Pipeline equity investments and other 160 166 Long-Term Assets of Discontinued Operations Pipeline equity investments and other — 951 Off-Balance Sheet Exposure 1 Bruce Power 1,877 1,538 Coastal GasLink 2 265 855 Pipeline equity investments and other 2 2 Discontinued operations — 56 Maximum exposure to loss 10,353 10,103 1 Includes maximum potential exposure to guarantees and future funding commitments. 2 TC Energy is contractually obligated to fund the capital costs to complete the Coastal GasLink pipeline by funding the remaining equity requirements of Coastal GasLink LP through incremental capacity on the subordinated loan agreement with Coastal GasLink LP until final costs are determined. In December 2024, TC Energy made an equity contribution of $3,137 million to Coastal GasLink LP, which used the funds to repay the $3,147 million balance owing to TC Energy under the subordinated loan agreement. The repayment reduced the Company's funding commitment under the subordinated loan agreement to $228 million. In addition to the subordinated loan agreement, TC Energy has entered into an equity contribution agreement to fund a maximum of $37 million for its proportionate share of the equity requirements related to the Cedar Link project. Refer to Note 7, Coastal GasLink, for additional information.

DESCRIPTION OF TC ENERGY'S BU_2

DESCRIPTION OF TC ENERGY'S BUSINESS (Details)		12 Months Ended
	Oct. 01, 2024 shares	Dec. 31, 2024 plant segment mi km Bcf
Segment Reporting Information [Line Items]
Number of business segments in which the entity operates (in segments) | segment		4
TC Energy | Common shares
Segment Reporting Information [Line Items]
Spinoff of Liquids Pipelines business (in shares) | shares	1
South Bow Canadian Infrastructure Holdings Ltd | Common shares
Segment Reporting Information [Line Items]
Spinoff of Liquids Pipelines business (in shares) | shares	0.2
Canadian Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) | km		41,121
Investments of regulated natural gas pipelines (in miles) | mi		25,552
U.S. Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) | km		49,681
Investments of regulated natural gas pipelines (in miles) | mi		30,870
Investments of regulated natural gas storage facilities (in billion cubic feet) | Bcf		532
Mexico Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) | km		2,885
Investments of regulated natural gas pipelines (in miles) | mi		1,791
Power and Energy Solutions
Segment Reporting Information [Line Items]
Number of electrical power generation plants (in plants) | plant		4,650
Non-regulated natural gas storage facilities (in billion cubic feet) | Bcf		118

ACCOUNTING POLICIES (Details)

ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2024
Employee Post-Retirement Benefits
Moving average period of basis used to determine expected return on plan assets	5 years
Portion amortized out of AOCI and into net income	10%
Minimum | Corporate
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	4%
Minimum | Pipeline | Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	0.75%
Minimum | Power generation and natural gas storage plant, equipment and structures | Power and Energy Solutions
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	2%
Maximum | Corporate
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	20%
Maximum | Pipeline | Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	6.67%
Maximum | Power generation and natural gas storage plant, equipment and structures | Power and Energy Solutions
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	20%

DISCONTINUED OPERATIONS - Narra

DISCONTINUED OPERATIONS - Narrative (Details) $ in Millions, $ in Billions			3 Months Ended	12 Months Ended
	Aug. 28, 2024 CAD ($) subsidiary	Aug. 28, 2024 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Oct. 01, 2024 CAD ($)	Sep. 30, 2024 CAD ($)	Dec. 31, 2022 CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Outstanding			$ 48,172	$ 48,172	$ 53,118
Stockholders' equity			38,360	38,360	39,008			$ 34,116
Retained earnings (Accumulated deficit)			(5,241)	(5,241)	(2,997)
Accumulated other comprehensive income (loss) (Note 26)			$ 233	233	49
South Bow Canadian Infrastructure Holdings Ltd
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of legal entities (in subsidiaries) | subsidiary	2
South Bow Canadian Infrastructure Holdings Ltd
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Maximum liability for South Bow						$ 30
Keystone Pipeline System
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Environmental remediation liability costs					794
Environmental remediation liability					676		$ 92
Insurance received				99	575
Proceeds from sale of insurance					36
Pre-tax expense				37
Disposed of by sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Pre tax separation, before reclassification				197	40
Pre tax separation, before reclassification, after tax				$ 167	$ 34
Amount		$ 1.3
Stockholders' equity						3,691
Retained earnings (Accumulated deficit)						2,950
Accumulated other comprehensive income (loss) (Note 26)						$ 741
Disposed of by sale | South Bow Canadian Infrastructure Holdings Ltd
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Outstanding	$ 7,900
Net proceeds	$ 6,200
Disposed of by sale | South Bow Canadian Infrastructure Holdings Ltd
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Transition services agreement, term			2 years
Ownership interest sold						86%

DISCONTINUED OPERATIONS - Incom

DISCONTINUED OPERATIONS - Income from Discontinued Operations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income from discontinued operations, net of taxes	$ 395	$ 612	$ 633
Liquids Pipelines
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues	2,217	2,667	2,668
Income (Loss) from Equity Investments	50	67	55
Plant operating costs and other	806	814	704
Commodity purchases resold	387	437	512
Property taxes	84	116	121
Depreciation and amortization	253	332	322
Asset impairment charge and other	21	(4)	(118)
Operating and other expenses	1,551	1,695	1,541
Segmented Earnings (Losses) from Discontinued Operations	716	1,039	1,182
Interest expense	218	297	288
Interest income and other	(21)	30	(6)
Financial charges	197	327	282
Income (Loss) from Discontinued Operations before Income Taxes	519	712	900
Income tax expense (recovery)	124	100	267
Income from discontinued operations, net of taxes	$ 395	$ 612	$ 633

DISCONTINUED OPERATIONS - Asset

DISCONTINUED OPERATIONS - Assets and Liabilities of Discontinued Operations (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Disposal Group, Including Discontinued Operation, Assets, Current [Abstract]
Accounts receivable	$ 0	$ 1,782
Inventories	0	211
Other current assets	235	1,084
Current assets of discontinued operations (Note 4)	235	3,077
Plant, Property and Equipment	0	11,118
Equity Investments	0	1,074
Other Long-Term Assets	136	241
Long-Term Assets of Discontinued Operations (Note 4)	371	15,510
Current Liabilities
Accounts payable and other	170	2,682
Current liabilities of discontinued operations (Note 4)	170	2,682
Other Long-Term Liabilities	110	127
Deferred Income Tax Liabilities	0	1,153
Liabilities	$ 280	$ 3,962

DISCONTINUED OPERATIONS - Cash

DISCONTINUED OPERATIONS - Cash Flows from Discontinued Operations (Details) - Disposed of by sale - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Summarized cash flows information for Discontinued operations [Abstract]
Net cash provided by operations	$ 670	$ 1,026	$ 709
Net cash (used in) provided by investing activities	$ (89)	$ 87	$ 502

SEGMENTED INFORMATION - Schedul

SEGMENTED INFORMATION - Schedule of Segment Reporting Information, by Segment (Details) - CAD ($) $ in Millions		12 Months Ended
	Mar. 15, 2022	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segmented information
Revenues		$ 13,771	$ 13,267	$ 12,309
Income (loss) from equity investments		1,558	1,310	999
Impairment of equity investment (Note 7)		0	(2,100)	(3,048)
Operating costs		(5,450)	(4,934)	(4,977)
Depreciation and amortization		(2,535)	(2,446)	(2,262)
Other segment items		(620)		(571)
Segmented Earnings (Losses)		7,964	5,097	2,450
Interest expense		(3,019)	(2,966)	(2,300)
Allowance for funds used during construction		784	575	369
Foreign exchange gains (losses), net		(147)	320	(185)
Interest income and other		324	272	140
Income (Loss) from Continuing Operations before Income Taxes		5,906	3,298	474
Income tax (expense) recovery from continuing operations		(922)	(842)	(322)
Net Income (Loss) from Continuing Operations		4,984	2,456	152
Net Income (Loss) from Discontinued Operations, Net of Tax		395	612	633
Net Income (Loss)		5,379	3,068	785
Net (income) loss attributable to non-controlling interests		(681)	(146)	(37)
Net Income (Loss) Attributable to Controlling Interests		4,698	2,922	748
Preferred share dividends		(104)	(93)	(107)
Net income (loss) attributable to common shares from continuing operations		4,594	2,829	641
Capital Spending
Capital expenditures		6,181	7,958	6,572
Capital projects in development		50	142	49
Contributions to equity investments, net of distributions		1,546
Contributions to equity method investments		7,777	4,149	8,818
Contributions to equity method investments, net of other corporate distributions				2,197
Contributions to equity investments			12,249
Discontinued operations		127	49	143
Capital Spending		7,904	12,298	8,961
Assets		118,243	125,034
Coastal GasLink
Capital Spending
Contributions to equity investments, net of distributions		3,100
Discontinued Operations
Capital Spending
Assets		371	15,510
Continuing Operations
Capital Spending
Assets		117,872	109,524
Sur de Texas | Line of credit | Joint venture
Capital Spending
Contributions to equity investments, net of distributions	$ 1,200
Intersegment eliminations
Segmented information
Revenues		(148)	(123)	(144)
Corporate
Segmented information
Revenues		(140)	(123)	(144)
Income (loss) from equity investments		0	0	28
Impairment of equity investment (Note 7)			0	0
Operating costs		9	(15)	72
Depreciation and amortization		(5)	(6)	(7)
Other segment items		0		0
Segmented Earnings (Losses)		(136)	(144)	(51)
Capital Spending
Capital expenditures		50	33	41
Capital projects in development		0	0	0
Contributions to equity investments, net of distributions		0		0
Contributions to equity method investments		50	0	41
Contributions to equity investments			33
Assets		4,189	7,715
Canadian Natural Gas Pipelines
Segmented information
Revenues		5,600	5,173	4,764
Canadian Natural Gas Pipelines | Coastal GasLink
Segmented information
Income (loss) from equity investments		17	203	1
Canadian Natural Gas Pipelines | Operating segments
Segmented information
Revenues		5,600	5,173	4,764
Income (loss) from equity investments		34	220	18
Impairment of equity investment (Note 7)			(2,100)	(3,048)
Operating costs		(2,246)	(2,058)	(1,976)
Depreciation and amortization		(1,382)	(1,325)	(1,198)
Other segment items		10		0
Segmented Earnings (Losses)		2,016	(90)	(1,440)
Capital Spending
Capital expenditures		1,273	2,953	3,274
Capital projects in development		0	0	0
Contributions to equity investments, net of distributions		827		1,445
Contributions to equity method investments		2,100	3,231	4,719
Contributions to equity investments			6,184
Assets		31,167	29,782
Canadian Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues		0	0	0
U.S. Natural Gas Pipelines
Segmented information
Revenues		6,339	6,229	5,933
U.S. Natural Gas Pipelines | Operating segments
Segmented information
Revenues		6,438	6,330	6,065
Income (loss) from equity investments		341	324	292
Impairment of equity investment (Note 7)			0	0
Operating costs		(2,381)	(2,189)	(2,282)
Depreciation and amortization		(955)	(934)	(887)
Other segment items		610		(571)
Segmented Earnings (Losses)		4,053	3,531	2,617
Capital Spending
Capital expenditures		2,568	2,536	2,137
Capital projects in development		5	0	0
Contributions to equity investments, net of distributions		2		0
Contributions to equity method investments		2,575	124	2,137
Contributions to equity investments			2,660
Assets		56,304	50,499
U.S. Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues		(99)	(101)	(132)
Mexico Natural Gas Pipelines
Segmented information
Revenues		870	846	688
Mexico Natural Gas Pipelines | Operating segments
Segmented information
Revenues		870	846	688
Income (loss) from equity investments		283	78	122
Impairment of equity investment (Note 7)			0	0
Operating costs		(132)	(39)	(221)
Depreciation and amortization		(92)	(89)	(98)
Other segment items		0		0
Segmented Earnings (Losses)		929	796	491
Capital Spending
Capital expenditures		2,228	2,292	1,027
Capital projects in development		0	0	0
Contributions to equity investments, net of distributions		0		0
Contributions to equity method investments		2,228	0	1,027
Contributions to equity investments			2,292
Assets		15,995	12,003
Mexico Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues		0	0	0
Power and Energy Solutions
Segmented information
Revenues		954	1,019	924
Power and Energy Solutions | Operating segments
Segmented information
Revenues		1,003	1,041	936
Income (loss) from equity investments		900	688	539
Impairment of equity investment (Note 7)			0	0
Operating costs		(700)	(633)	(570)
Depreciation and amortization		(101)	(92)	(72)
Other segment items		0		0
Segmented Earnings (Losses)		1,102	1,004	833
Capital Spending
Capital expenditures		62	144	93
Capital projects in development		45	142	49
Contributions to equity investments, net of distributions		717		752
Contributions to equity method investments		824	794	894
Contributions to equity investments			1,080
Assets		10,217	9,525
Power and Energy Solutions | Intersegment eliminations
Segmented information
Revenues		(49)	(22)	(12)
Corporate
Segmented information
Revenues		$ 8	$ 0	$ 0

SEGMENTED INFORMATION - Revenue

SEGMENTED INFORMATION - Revenue from External Customers by Geographic Areas (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Revenues	$ 13,771	$ 13,267	$ 12,309
Canada – domestic
Segment Reporting Information [Line Items]
Revenues	5,579	5,337	4,920
Canada – export
Segment Reporting Information [Line Items]
Revenues	953	821	765
United States
Segment Reporting Information [Line Items]
Revenues	6,369	6,263	5,936
Mexico
Segment Reporting Information [Line Items]
Revenues	$ 870	$ 846	$ 688

SEGMENTED INFORMATION - Sched_2

SEGMENTED INFORMATION - Schedule of Long-Lived Assets by Country (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 77,501	$ 69,451
Canada
Segment Reporting Information [Line Items]
Property, plant and equipment, net	26,354	26,434
United States
Segment Reporting Information [Line Items]
Property, plant and equipment, net	40,580	35,640
Mexico
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 10,567	$ 7,377

REVENUES - Disaggregation of Re

REVENUES - Disaggregation of Revenues (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 13,062	$ 12,511	$ 12,125
Other revenues	393	477	57
Sales-type lease income	308	279	127
Revenues	13,771	13,267	12,309
Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	11,406	10,690	9,824
Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	266	427	490
Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,390	1,394	1,811
Canadian Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5,600	5,173	4,764
Other revenues	0	0	0
Sales-type lease income	0	0	0
Revenues	$ 5,600	5,173	4,764
Canadian Natural Gas Pipelines | Coastal GasLink
Disaggregation of Revenue [Line Items]
Ownership interest percentage	35%
Canadian Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 5,586	5,141	4,696
Canadian Natural Gas Pipelines | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Canadian Natural Gas Pipelines | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	14	32	68
Canadian Natural Gas Pipelines | Coastal GasLink | Related party
Disaggregation of Revenue [Line Items]
Revenues	14	31	68
U.S. Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6,251	5,981	5,919
Other revenues	88	248	14
Sales-type lease income	0	0	0
Revenues	6,339	6,229	5,933
U.S. Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5,382	5,107	4,621
U.S. Natural Gas Pipelines | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
U.S. Natural Gas Pipelines | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	869	874	1,298
Mexico Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	562	567	561
Other revenues	0	0	0
Sales-type lease income	308	279	127
Revenues	870	846	688
Mexico Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	438	442	507
Mexico Natural Gas Pipelines | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Mexico Natural Gas Pipelines | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	124	125	54
Power and Energy Solutions
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	649	790	881
Other revenues	305	229	43
Sales-type lease income	0	0	0
Revenues	954	1,019	924
Power and Energy Solutions | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Power and Energy Solutions | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	266	427	490
Power and Energy Solutions | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	383	363	391
TGNH | Non-lease components
Disaggregation of Revenue [Line Items]
Revenues	98	97	37
Corporate
Disaggregation of Revenue [Line Items]
Other revenues	8
Revenues	8	$ 0	$ 0
Corporate | South Bow Canadian Infrastructure Holdings Ltd
Disaggregation of Revenue [Line Items]
Other revenues	$ 7

REVENUES - Contract Balances (D

REVENUES - Contract Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 1,452	$ 1,388
Contract assets (Note 8)	165	151
Long-term contract assets (Note 15)	608	457
Contract liabilities1 (Note 17)	30	47
Long-term contract liabilities	0	2
Revenue recognized	$ 41	$ 47

REVENUES - Remaining Performanc

REVENUES - Remaining Performance Obligations - Narrative (Details) $ in Billions	Dec. 31, 2024 CAD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 29.1
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 6.4
Future revenues, expected timing of satisfaction, period	1 year

COASTAL GASLINK (Details)

COASTAL GASLINK (Details) $ in Billions	9 Months Ended	12 Months Ended
	Sep. 30, 2023 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 17, 2024 CAD ($)	Nov. 18, 2024 CAD ($)	Dec. 31, 2023 USD ($)
Equity Investments
Payment to reduce company's funding commitment		$ 4,683,000,000	$ 4,149,000,000	$ 3,433,000,000
Long-term debt					$ 2.8			$ 2
Equity Investments (Note 11)		10,636,000,000	9,240,000,000
Subordinated Loan Agreement | Subordinated debt
Equity Investments
Unused borrowing capacity, amount			855,000,000
Funding commitment		228,000,000
Coastal GasLink
Equity Investments
Additional aggregate cost							$ 199,000,000
Impairment losses pre tax	$ 5,148,000,000
Impairment charges after tax	$ 4,586,000,000
Equity Investments (Note 11)		1,006,000,000	294,000,000
Coastal GasLink | Subordinated Loan Agreement | Subordinated debt | Related party
Equity Investments
Issuances		627,000,000	2,520,000,000
Coastal GasLink | Coastal GasLink | Subordinated Loan Agreement | Subordinated debt
Equity Investments
Revolving credit facility, borrowing capacity		3,375,000,000
Line of credit facility, outstanding amount		0	2,520,000,000			$ 3,147,000,000
Payment to reduce company's funding commitment		3,137,000,000
Coastal GasLink | Coastal GasLink | Subordinated Demand Revolving Credit Facility Agreement | Subordinated debt
Equity Investments
Revolving credit facility, borrowing capacity		120,000,000	100,000,000
Long-term debt		$ 0	$ 0

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Other Assets [Abstract]
Fair value of derivative contracts (Note 28)	$ 347	$ 589
Current portion of net investment in leases (Note 10)	333	306
Contract assets (Note 6)	165	151
Cash provided as collateral	128	28
Regulatory assets (Note 13)	123	76
Prepaid expenses	86	87
Emissions credits	75	94
Other	82	88
Other current assets	$ 1,339	$ 1,419

PLANT, PROPERTY AND EQUIPMENT_2

PLANT, PROPERTY AND EQUIPMENT (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Cost	$ 112,898	$ 102,591
Accumulated Depreciation	35,397	33,140
Net Book Value	77,501	69,451
TGNH
Property, Plant and Equipment [Line Items]
Sales-type lease, net investment in lease, before allowance for credit loss	0	407
Operating segments | Canadian Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	49,131	48,122
Accumulated Depreciation	24,479	23,374
Net Book Value	24,652	24,748
Operating segments | Canadian Natural Gas Pipelines | NGTL System
Property, Plant and Equipment [Line Items]
Cost	29,814	29,211
Accumulated Depreciation	10,793	10,034
Net Book Value	19,021	19,177
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	16,359	16,042
Accumulated Depreciation	11,944	11,658
Net Book Value	4,415	4,384
Operating segments | Canadian Natural Gas Pipelines | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	2,958	2,869
Accumulated Depreciation	1,742	1,682
Net Book Value	1,216	1,187
Operating segments | Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | NGTL System
Property, Plant and Equipment [Line Items]
Cost	29,311	28,424
Accumulated Depreciation	10,793	10,034
Net Book Value	18,518	18,390
Operating segments | Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	16,196	15,895
Accumulated Depreciation	11,944	11,658
Net Book Value	4,252	4,237
Operating segments | Canadian Natural Gas Pipelines | Pipeline | NGTL System
Property, Plant and Equipment [Line Items]
Cost	20,497	20,232
Accumulated Depreciation	7,413	6,855
Net Book Value	13,084	13,377
Operating segments | Canadian Natural Gas Pipelines | Pipeline | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	10,907	10,729
Accumulated Depreciation	8,165	7,996
Net Book Value	2,742	2,733
Operating segments | Canadian Natural Gas Pipelines | Compression | NGTL System
Property, Plant and Equipment [Line Items]
Cost	7,146	6,603
Accumulated Depreciation	2,497	2,349
Net Book Value	4,649	4,254
Operating segments | Canadian Natural Gas Pipelines | Compression | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	4,540	4,437
Accumulated Depreciation	3,448	3,354
Net Book Value	1,092	1,083
Operating segments | Canadian Natural Gas Pipelines | Metering and other | NGTL System
Property, Plant and Equipment [Line Items]
Cost	1,668	1,589
Accumulated Depreciation	883	830
Net Book Value	785	759
Operating segments | Canadian Natural Gas Pipelines | Metering and other | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	749	729
Accumulated Depreciation	331	308
Net Book Value	418	421
Operating segments | Canadian Natural Gas Pipelines | Under construction | NGTL System
Property, Plant and Equipment [Line Items]
Cost	503	787
Accumulated Depreciation	0	0
Net Book Value	503	787
Operating segments | Canadian Natural Gas Pipelines | Under construction | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	163	147
Accumulated Depreciation	0	0
Net Book Value	163	147
Operating segments | Canadian Natural Gas Pipelines | Under construction | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	31	23
Accumulated Depreciation	0	0
Net Book Value	31	23
Operating segments | Canadian Natural Gas Pipelines | Other | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	2,927	2,846
Accumulated Depreciation	1,742	1,682
Net Book Value	1,185	1,164
Operating segments | U.S. Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	48,571	42,787
Accumulated Depreciation	8,744	7,818
Net Book Value	39,827	34,969
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	26,440	23,107
Accumulated Depreciation	2,604	2,178
Net Book Value	23,836	20,929
Operating segments | U.S. Natural Gas Pipelines | ANR
Property, Plant and Equipment [Line Items]
Cost	9,608	8,074
Accumulated Depreciation	2,204	1,888
Net Book Value	7,404	6,186
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	11,829	11,022
Accumulated Depreciation	3,936	3,752
Net Book Value	7,893	7,270
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	25,549	22,336
Accumulated Depreciation	2,604	2,178
Net Book Value	22,945	20,158
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | ANR
Property, Plant and Equipment [Line Items]
Cost	8,755	7,670
Accumulated Depreciation	2,204	1,888
Net Book Value	6,551	5,782
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	1,695	2,071
Accumulated Depreciation	628	800
Net Book Value	1,067	1,271
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	14,826	12,952
Accumulated Depreciation	1,472	1,247
Net Book Value	13,354	11,705
Operating segments | U.S. Natural Gas Pipelines | Pipeline | ANR
Property, Plant and Equipment [Line Items]
Cost	2,477	2,117
Accumulated Depreciation	745	657
Net Book Value	1,732	1,460
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Columbia Gulf
Property, Plant and Equipment [Line Items]
Cost	4,127	3,600
Accumulated Depreciation	304	256
Net Book Value	3,823	3,344
Operating segments | U.S. Natural Gas Pipelines | Pipeline | GTN
Property, Plant and Equipment [Line Items]
Cost	3,405	2,992
Accumulated Depreciation	1,467	1,295
Net Book Value	1,938	1,697
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Great Lakes
Property, Plant and Equipment [Line Items]
Cost	2,602	2,359
Accumulated Depreciation	1,537	1,401
Net Book Value	1,065	958
Operating segments | U.S. Natural Gas Pipelines | Compression | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	6,153	5,310
Accumulated Depreciation	677	559
Net Book Value	5,476	4,751
Operating segments | U.S. Natural Gas Pipelines | Compression | ANR
Property, Plant and Equipment [Line Items]
Cost	4,446	3,928
Accumulated Depreciation	938	773
Net Book Value	3,508	3,155
Operating segments | U.S. Natural Gas Pipelines | Metering and other | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	4,570	4,074
Accumulated Depreciation	455	372
Net Book Value	4,115	3,702
Operating segments | U.S. Natural Gas Pipelines | Metering and other | ANR
Property, Plant and Equipment [Line Items]
Cost	1,832	1,625
Accumulated Depreciation	521	458
Net Book Value	1,311	1,167
Operating segments | U.S. Natural Gas Pipelines | Under construction
Property, Plant and Equipment [Line Items]
Accumulated Depreciation	0	0
Operating segments | U.S. Natural Gas Pipelines | Under construction | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	694	584
Accumulated Depreciation	0	0
Net Book Value	694	584
Operating segments | U.S. Natural Gas Pipelines | Under construction | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	891	771
Accumulated Depreciation	0	0
Net Book Value	891	771
Operating segments | U.S. Natural Gas Pipelines | Under construction | ANR
Property, Plant and Equipment [Line Items]
Cost	853	404
Net Book Value	853	404
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment, including under construction | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	12,523	11,606
Accumulated Depreciation	3,936	3,752
Net Book Value	8,587	7,854
Operating segments | Mexico Natural Gas Pipelines | Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost	3,464	3,132
Accumulated Depreciation	729	589
Net Book Value	2,735	2,543
Operating segments | Mexico Natural Gas Pipelines | Pipeline
Property, Plant and Equipment [Line Items]
Cost	2,590	2,290
Accumulated Depreciation	523	422
Net Book Value	2,067	1,868
Operating segments | Mexico Natural Gas Pipelines | Compression
Property, Plant and Equipment [Line Items]
Cost	476	447
Accumulated Depreciation	107	82
Net Book Value	369	365
Operating segments | Mexico Natural Gas Pipelines | Metering and other
Property, Plant and Equipment [Line Items]
Cost	398	395
Accumulated Depreciation	99	85
Net Book Value	299	310
Operating segments | Mexico Natural Gas Pipelines | Under construction
Property, Plant and Equipment [Line Items]
Cost	7,807	4,823
Accumulated Depreciation	0	0
Net Book Value	7,807	4,823
Operating segments | Mexico Natural Gas Pipelines | Property, plant and equipment, including under construction
Property, Plant and Equipment [Line Items]
Cost	11,271	7,955
Accumulated Depreciation	729	589
Net Book Value	10,542	7,366
Operating segments | Power and Energy Solutions | Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost	2,925	2,665
Accumulated Depreciation	1,006	912
Net Book Value	1,919	1,753
Operating segments | Power and Energy Solutions | Natural Gas
Property, Plant and Equipment [Line Items]
Cost	1,273	1,239
Accumulated Depreciation	671	637
Net Book Value	602	602
Operating segments | Power and Energy Solutions | Natural Gas Storage and Other
Property, Plant and Equipment [Line Items]
Cost	873	845
Accumulated Depreciation	281	256
Net Book Value	592	589
Operating segments | Power and Energy Solutions | Renewable Power Generation
Property, Plant and Equipment [Line Items]
Cost	779	581
Accumulated Depreciation	54	19
Net Book Value	725	562
Operating segments | Power and Energy Solutions | Under construction
Property, Plant and Equipment [Line Items]
Cost	56	153
Accumulated Depreciation	0	0
Net Book Value	56	153
Operating segments | Power and Energy Solutions | Property, plant and equipment, including under construction
Property, Plant and Equipment [Line Items]
Cost	2,981	2,818
Accumulated Depreciation	1,006	912
Net Book Value	1,975	1,906
Corporate
Property, Plant and Equipment [Line Items]
Cost	944	909
Accumulated Depreciation	439	447
Net Book Value	$ 505	$ 462

LEASES - (Lessee) Narrative (De

LEASES - (Lessee) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Lessee, Lease, Description [Line Items]
Operating lease termination period	1 year
Right-of-use asset	$ 480	$ 435
Minimum
Lessee, Lease, Description [Line Items]
Operating leases optional renewable terms	1 year
Maximum
Lessee, Lease, Description [Line Items]
Operating leases optional renewable terms	25 years

LEASES - (Lessee) Operating Lea

LEASES - (Lessee) Operating Lease Cost and Other Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Operating lease cost
Operating lease cost	$ 117	$ 105
Sublease income	(6)	(4)
Net operating lease cost	111	101
Cash paid for amounts included in the measurement of operating lease liabilities	74	72
ROU assets obtained in exchange for new operating lease liabilities	$ 96	$ 83
Weighted average remaining lease term	13 years	13 years
Weighted average discount rate	3.30%	3.30%

LEASES - (Lessee) Maturities of

LEASES - (Lessee) Maturities of Operating Lease Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Less than one year	$ 73	$ 71
One to two years	73	68
Two to three years	66	66
Three to four years	64	59
Four to five years	63	58
More than five years	275	224
Total operating lease payments	614	546
Imputed interest	(103)	(89)
Operating lease liabilities	511	457
Operating lease, reported as accounts payable and other	60	57
Operating lease, reported as other long-term liabilities	$ 451	$ 400
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts payable and other (Note 17)	Accounts payable and other (Note 17)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other Long-Term Liabilities (Note 18)	Other Long-Term Liabilities (Note 18)

LEASES - (Lessor) Narrative (De

LEASES - (Lessor) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Fixed portion of the operating lease income	$ 114	$ 112	$ 110
Cost for facilities accounted for as operating leases	697	646
Accumulated depreciation for facilities accounted for as operating leases	$ 351	$ 333

LEASES - (Lessor) Future Lease

LEASES - (Lessor) Future Lease Payments to be Received Under Operating Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Less than one year	$ 107	$ 111
One to two years	76	94
Two to three years	9	70
Three to four years	10	0
Four to five years	10	0
More than five years	55	0
Total payments to be received	$ 267	$ 275

LEASES - Sale Type Leases Narra

LEASES - Sale Type Leases Narrative (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Sales-type lease income	$ 308,000,000	$ 279,000,000	$ 127,000,000
Expected credit loss provision (Note 28)	(22,000,000)	(83,000,000)	163,000,000
TGNH
Lessee, Lease, Description [Line Items]
Expected credit loss provision (Note 28)	(23,000,000)	(73,000,000)	149,000,000
Mexico Natural Gas Pipelines
Lessee, Lease, Description [Line Items]
Sales-type lease income	308,000,000	279,000,000	$ 127,000,000
Mexico Natural Gas Pipelines | TGNH
Lessee, Lease, Description [Line Items]
Sales-type lease, aggregate investment	$ 0	$ 407,000,000

LEASES - Sales-Type Leases (Det

LEASES - Sales-Type Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Less than one year	$ 333	$ 305
One to two years	333	305
Two to three years	333	305
Three to four years	333	305
Four to five years	333	305
More than five years	8,499	8,102
Payments to be received	$ 10,164	$ 9,627

LEASES - Component of Aggregate

LEASES - Component of Aggregate Investment in Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Lessee, Lease, Description [Line Items]
Minimum lease payments	$ 10,164	$ 9,627
Unearned lease income	(7,323)	(7,006)
Lease receivable	2,841	2,621
Expected credit loss provision	(59)	(76)
Present value of unguaranteed residual value	28	24
Sales-type lease, net investment in lease, before allowance for credit loss	2,810	2,569
Current portion included in Other current assets (Note 8)	(333)	(306)
Sales-type lease, net investment in lease, before allowance for credit loss, noncurrent	2,477	2,263
Currency Translation Adjustments
Lessee, Lease, Description [Line Items]
Expected credit loss provision	$ 6	$ 0

EQUITY INVESTMENTS - Ownership

EQUITY INVESTMENTS - Ownership Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Equity Investments
Income (Loss) from Equity Investments	$ 1,558	$ 1,310	$ 999
Equity Investments	$ 10,636	9,240
TQM | Canadian Natural Gas Pipelines
Equity Investments
Ownership interest percentage	50%
Income (Loss) from Equity Investments	$ 17	17	17
Equity Investments	$ 160	166
Coastal GasLink | Canadian Natural Gas Pipelines
Equity Investments
Ownership interest percentage	35%
Income (Loss) from Equity Investments	$ 17	203	1
Equity Investments	$ 1,006	294
Northern Border | U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage	50%
Income (Loss) from Equity Investments	$ 130	101	92
Equity Investments	$ 647	599
Millennium | U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage	47.50%
Income (Loss) from Equity Investments	$ 95	109	103
Equity Investments	$ (21)	476
Iroquois | U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage	50%
Income (Loss) from Equity Investments	$ 100	98	77
Equity Investments	221	227
Other | U.S. Natural Gas Pipelines
Equity Investments
Income (Loss) from Equity Investments	16	16	20
Equity Investments	135	120
Other | Power and Energy Solutions
Equity Investments
Income (Loss) from Equity Investments	0	(2)	2
Equity Investments	$ 42	38
Sur de Texas | Mexico Natural Gas Pipelines
Equity Investments
Ownership interest percentage	60%
Income (Loss) from Equity Investments	$ 283	78	150
Equity Investments	$ 1,403	1,078
Bruce Power | Power and Energy Solutions
Equity Investments
Ownership interest percentage	48.30%
Income (Loss) from Equity Investments	$ 900	690	$ 537
Equity Investments	$ 7,043	$ 6,242

EQUITY INVESTMENTS - Narrative

EQUITY INVESTMENTS - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2024
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets	$ 278	$ 769
Coastal GasLink | LNG Canada
Equity Investments
Proceeds from incentive fees	$ 200

EQUITY INVESTMENTS - Schedule o

EQUITY INVESTMENTS - Schedule of Distribution Received and Contribution Paid (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Equity Investments
Distributions received from equity investments	$ 5,293	$ 1,181	$ 3,587
Contributions to equity investments	4,683	4,149	3,396
Contributions to equity investments, net of distributions	1,546
Coastal GasLink
Equity Investments
Contributions to equity investments	3,964	3,231	1,414
Contributions to equity investments, net of distributions	3,100
Sur de Texas
Equity Investments
Distributions received from equity investments	0	0	2,404
Contributions to equity investments	0	0	1,199
Equity investments
Equity Investments
Distributions received from equity investments	1,607	1,158	955
Contributions to equity investments	719	918	783
Coastal GasLink
Equity Investments
Distributions received from equity investments	3,147	0	0
Other
Equity Investments
Distributions received from equity investments	$ 539	$ 23	$ 228

EQUITY INVESTMENTS - Summarized

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income
Revenues	$ 13,771	$ 13,267	$ 12,309
Operating and other expenses	(7,985)	(7,380)	(7,810)
Net income	4,698	2,922	748
Income (Loss) from Equity Investments	1,558	1,310	999
Balance Sheet
Current assets	5,733	11,372
Current liabilities	(10,511)	(11,817)
Group of Investees
Income
Revenues	6,962	6,197	5,681
Operating and other expenses	(3,783)	(3,343)	(3,290)
Net income	3,026	2,457	$ 2,031
Balance Sheet
Current assets	3,959	3,279
Non-current assets	44,835	41,270
Current liabilities	(2,111)	(2,403)
Non-current liabilities	$ (21,729)	$ (21,894)

LOANS RECEIVABLE FROM AFFILIA_3

LOANS RECEIVABLE FROM AFFILIATES - Narrative (Details) $ in Millions, $ in Billions, $ in Billions	Mar. 15, 2022 USD ($)	Mar. 15, 2022 CAD ($)	Dec. 31, 2024	Dec. 31, 2017 MXN ($)
Revolving credit facility | Line of credit | Joint venture | Sur de Texas
Loans and Leases Receivable Disclosure [Line Items]
Revolving credit facility, borrowing capacity				$ 21.3
Amount		$ 1.2
Inter-affiliate debt issuance	$ 938	$ 1.2
Coastal GasLink | Canadian Natural Gas Pipelines
Loans and Leases Receivable Disclosure [Line Items]
Ownership interest percentage			35%
Sur de Texas | Mexico Natural Gas Pipelines
Loans and Leases Receivable Disclosure [Line Items]
Ownership interest percentage			60%

LOANS RECEIVABLE FROM AFFILIA_4

LOANS RECEIVABLE FROM AFFILIATES - Schedule of Loan Receivable Interest Income and Foreign Exchange Impact (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Loans and Leases Receivable Disclosure [Line Items]
Interest income	$ 324	$ 272	$ 140
Interest expense	(3,019)	(2,966)	(2,300)
Foreign exchange gains (losses)	147	(320)	185
Sur de Texas | Joint venture
Loans and Leases Receivable Disclosure [Line Items]
Interest income	0	0	19
Interest expense	0	0	(19)
Foreign exchange gains (losses)	$ 0	$ 0	$ (28)

RATE-REGULATED BUSINESSES - Nar

RATE-REGULATED BUSINESSES - Narrative (Details) $ in Billions, $ in Billions	1 Months Ended		12 Months Ended
	Sep. 30, 2024 CAD ($)	Apr. 30, 2020	Dec. 31, 2024 USD ($)
Columbia Gas Transmission
Public Utilities, General Disclosures [Line Items]
Regulatory liability, amortization period			4 years
Maximum cost recovery and return on investment			$ 1.2
NGTL System
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity			10.10%
Deemed common equity, percent			40%
Regulatory liability, amortization period	5 years
Maximum cost recovery and return on investment	$ 3.3
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity			10.10%
Deemed common equity, percent			40%
Unanimous negotiated settlement period		6 years

RATE-REGULATED BUSINESSES - Ass

RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) $ in Millions, $ in Millions	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)
Regulatory Assets
Regulatory Assets	$ 2,805		$ 2,406
Less: Current portion included in Other current assets (Note 8)	123		76
Regulatory Assets, noncurrent	2,682		2,330
Regulatory Liabilities
Regulatory Liabilities	5,656		4,987
Less: Current portion included in Accounts payable and other (Note 17)	353		284
Regulatory liabilities, noncurrent	5,303		4,703
Pipeline abandonment trust balances
Regulatory Liabilities
Regulatory Liabilities	2,686		2,252
Deferred income taxes - U.S. Tax Reform
Regulatory Liabilities
Regulatory Liabilities	1,197		1,137
Canadian Mainline short-term adjustment and toll-stabilization accounts
Regulatory Liabilities
Regulatory Liabilities	553		437
Cost of removal
Regulatory Liabilities
Regulatory Liabilities	$ 376		351
Canadian Mainline bridging amortization account
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	6 years	6 years
Regulatory Liabilities
Regulatory Liabilities	$ 322		376
Deferred income taxes
Regulatory Liabilities
Regulatory Liabilities	188		198
Pensions and other post retirement benefits
Regulatory Liabilities
Regulatory Liabilities	122		6
Pensions and other post retirement benefits | ANR PIPELINE COMPANY
Regulatory Liabilities
Regulatory Liabilities	$ 45		42
Canadian Mainline long-term adjustment account
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	2 years	2 years
Regulatory Liabilities
Regulatory Liabilities	$ 74		111
Operating and debt-service regulatory liabilities
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Regulatory Liabilities
Regulatory Liabilities	$ 50		23
Other
Regulatory Liabilities
Regulatory Liabilities	43		54
Long term adjustment account, amount to be amortized over one year
Regulatory Liabilities
Regulatory Liabilities	$ 223
Regulatory liability, amortization period	6 years	6 years
Postretirement benefit costs | ANR PIPELINE COMPANY
Regulatory Liabilities
Amount to be addressed In next settlement	$ 45	$ 32
Deferred income taxes
Regulatory Assets
Regulatory Assets	$ 2,593		2,204
Operating and debt-service regulatory assets
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Regulatory Assets	$ 56		29
Pensions and other post retirement benefits
Regulatory Assets
Regulatory Assets	0		54
Foreign exchange on long-term debt
Regulatory Assets
Regulatory Assets	$ 39		11
Foreign exchange on long-term debt | Minimum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Foreign exchange on long-term debt | Maximum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	5 years	5 years
Other
Regulatory Assets
Regulatory Assets	$ 117		$ 108

GOODWILL - Acquisitions (Detail

GOODWILL - Acquisitions (Details) $ in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2022 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)
Goodwill
Balance at the beginning of the period		$ 12,532	$ 9,490
Balance at the end of the period		13,670	9,490	$ 12,532
U.S. Natural Gas Pipelines
Goodwill
Balance at the beginning of the period		12,532		12,843
Foreign exchange rate changes		1,138		(311)
Balance at the end of the period		13,670		12,532
Goodwill, gross		15,405		14,267
Goodwill, net		1,735		1,735
Goodwill, impairment loss, net of tax	$ 531
COLUMBIA PIPELINE GROUP, INC.
Goodwill
Balance at the beginning of the period		9,708	7,351
Balance at the end of the period		10,588	7,351	9,708
ANR PIPELINE COMPANY
Goodwill
Balance at the beginning of the period		2,570	1,946
Balance at the end of the period		2,803	1,946	2,570
Great Lakes
Goodwill
Balance at the beginning of the period		161	122
Balance at the end of the period		176	122	161
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Goodwill
Balance at the beginning of the period		63	48
Balance at the end of the period		70	48	63
TUSCARORA GAS TRANSMISSION COMPANY
Goodwill
Balance at the beginning of the period		30	23
Balance at the end of the period		$ 33	$ 23	$ 30

GOODWILL - Narrative (Details)

GOODWILL - Narrative (Details) - CAD ($) $ in Millions		1 Months Ended
	Oct. 04, 2023	Mar. 31, 2022
U.S. Natural Gas Pipelines
Goodwill recorded on Company's acquisitions in the U.S.
Impairment loss before tax		$ 571
Goodwill, impairment loss, net of tax		$ 531
Columbia Gas and Columbia Gulf
Goodwill recorded on Company's acquisitions in the U.S.
Equity interest percentage	40%

OTHER LONG-TERM ASSETS - Summar

OTHER LONG-TERM ASSETS - Summary (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Long-term contract assets (Note 6)	$ 608	$ 457
Employee post-retirement benefits (Note 27)	758	518
Deferred income tax assets (Note 19)	428	1,319
Fair value of derivative contracts (Note 28)	122	155
Capital projects in development	164	234
Other	330	198
Total other assets	$ 2,410	$ 2,881

NOTES PAYABLE (Details)

NOTES PAYABLE (Details)	12 Months Ended
	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Notes payable
Outstanding	$ 387,000,000	$ 0
Revolving credit facility
Notes payable
Cost to maintain	18,000,000	16,000,000	$ 14,000,000
Notes payable
Notes payable
Denominated value	0	0		$ 214,000,000	$ 0
Revolving and demand credit facility
Notes payable
Total Facilities	12,200,000,000	12,900,000,000
TCPL | Revolving credit facility | Maturing December 2029
Notes payable
Total Facilities	3,000,000,000	3,000,000,000
Unused capacity	3,000,000,000
TCPL | Notes payable
Notes payable
Outstanding	$ 308,000,000	$ 0
Weighted average interest rate per annum	4.70%	0%		4.70%	0%
USA | Notes payable
Notes payable
Outstanding	$ 79,000,000	$ 0		$ 55,000,000	$ 0
Weighted average interest rate per annum	4.70%	0%		4.70%	0%
TCPL / TCPL USA | TC Energy
Notes payable
Noncontrolling interests ownership		40%			40%
TCPL / TCPL USA | Revolving credit facility
Notes payable
Total Facilities	$ 2,000,000,000	$ 2,000,000,000
Unused capacity	$ 1,100,000,000
TCPL / TCPL USA | Revolving credit facility | Maturing December 2025
Notes payable
Total Facilities				$ 1,000,000,000	$ 2,500,000,000
Unused capacity				700,000,000
TCPL / TCPL USA | Revolving credit facility | Maturing December 2027
Notes payable
Total Facilities				2,500,000,000	2,500,000,000
Unused capacity				2,500,000,000
COLUMBIA PIPELINES HOLDING COMPANY LLC | Revolving credit facility | Maturing December 2027
Notes payable
Total Facilities				1,500,000,000	$ 1,000,000,000
Unused capacity				$ 1,500,000,000

ACCOUNTS PAYABLE AND OTHER (Det

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Payables and Accruals [Abstract]
Trade payables	$ 3,699	$ 3,092
Fair value of derivative contracts (Note 28)	507	415
Regulatory liabilities (Note 13)	353	284
Income tax liabilities	143	76
Operating lease liabilities (Note 10)	60	57
Contract liabilities (Note 6)	30	47
Other	505	334
Accounts payable and other	$ 5,297	$ 4,305

OTHER LONG-TERM LIABILITIES (De

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Deferred Costs, Noncurrent [Abstract]
Operating lease obligations (Note 10)	$ 451	$ 400
Fair value of derivative contracts (Note 28)	209	106
Asset retirement obligations	108	64
Employee post-retirement benefits (Note 27)	94	97
Other	189	324
Other long-term liabilities	$ 1,051	$ 991

INCOME TAXES - Geographic Compo

INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Canada	$ 1,219	$ (344)	$ (2,133)
Foreign	4,687	3,642	2,607
Income (Loss) from Continuing Operations before Income Taxes	$ 5,906	$ 3,298	$ 474

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current
Canada	$ 102	$ 61	$ 41
Foreign	393	803	322
Total	495	864	363
Deferred
Canada	135	8	(459)
Foreign	292	(30)	418
Total	427	(22)	(41)
Income Tax Expense	$ 922	$ 842	$ 322

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income before income taxes	$ 5,906	$ 3,298	$ 474
Federal and provincial statutory tax rate	23%	23%	23%
Expected income tax expense	$ 1,358	$ 759	$ 109
Mexico foreign exchange exposure	(246)	132	9
Income tax differential related to regulated operations	(227)	(260)	(174)
Income from non-controlling interests and equity investments	(224)	(56)	(54)
Foreign income tax rate differentials	167	(84)	(216)
Non-taxable capital (gains) and losses	18	182	173
Impact of Mexico inflationary adjustments	7	1	24
Valuation allowance (release)	4	182	198
Settlement of Mexico prior years' income tax assessments	0	0	196
Non-deductible goodwill impairment	0	0	91
Other	65	(14)	(34)
Income Tax Expense	$ 922	$ 842	$ 322

INCOME TAXES - Deferred Assets

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Deferred Income Tax Assets
Tax loss and credit carryforwards	$ 1,987	$ 1,664
Disallowed interest carryforward	115	0
Regulatory and other deferred amounts	612	583
Unrealized foreign exchange losses on long-term debt	467	206
Other	143	160
Deferred tax assets, gross	3,324	2,613
Less: Valuation allowance	931	690
Deferred tax assets, net of Valuation allowance	2,393	1,923
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment	6,488	5,599
Equity investments	1,280	1,043
Taxes on future revenue requirement	612	496
Financial instruments	168	168
Other	301	270
Deferred tax liabilities, gross	8,849	7,576
Net Deferred Income Tax Liabilities	6,456	5,653
Deferred Income Tax Assets
Other long-term assets (Note 15)	428	1,319
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities	6,884	6,972
Deferred Tax Liabilities, Net	$ 6,456	$ 5,653

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) $ in Millions		12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2019 USD ($)
Net operating loss carryforwards
Valuation allowance	$ 690,000,000	$ 931,000,000	$ 690,000,000
Not recognized tax benefits		22,000,000
Deferred income tax liabilities on the unremitted earnings of foreign investments	1,443,000,000	1,728,000,000	1,443,000,000
Income tax payments, net of refunds		387,000,000	791,000,000	$ 394,000,000
Interest (recovery) expense reflected within net tax expense		(1,000,000)	3,000,000	6,000,000
Accrued interest expense	20,000,000	19,000,000	20,000,000	18,000,000
Income tax penalties expense		0	0	0
Income tax penalties accrued	0	0	0	0
Disallowed interest carryforward	0	115,000,000	0
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards	6,593,000,000	6,740,000,000	6,593,000,000
Capital loss carryforwards unrecognized	478,000,000	599,000,000	478,000,000
Disallowed interest carryforward	0	480,000,000	0
Canada federal and provincial | Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits	140,000,000	$ 161,000,000	140,000,000
Not recognized tax benefits	22,000,000		$ 22,000,000
Foreign Tax Jurisdiction | Mexican Tax Authority (SAT)
Net operating loss carryforwards
Unused net operating loss carryforwards					$ 518	$ 47
Foreign Tax Jurisdiction | Mexican Tax Authority (SAT) | Tax Year 2013
Net operating loss carryforwards
Audit assessment								$ 1
Foreign Tax Jurisdiction | Mexican Tax Authority (SAT) | Tax Years 2014 through 2017
Net operating loss carryforwards
Audit assessment							$ 490
Foreign Tax Jurisdiction | Mexican Tax Authority (SAT) | Tax Years 2013 Through 2021
Net operating loss carryforwards
Audit assessment				$ 196,000,000			$ 153
Coastal GasLink
Net operating loss carryforwards
Decrease in valuation allowance	$ 358,000,000

INCOME TAXES - Reconciliation_2

INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefit at beginning of year	$ 85	$ 91	$ 80
Gross increases – tax positions in prior years	3	9	6
Gross decreases – tax positions in prior years	(2)	(1)	0
Gross increases – tax positions in current year	5	16	7
Gross decrease – tax positions in current year	(2)	0	0
Settlement	(13)	0	0
Lapse of statutes of limitations	(4)	(30)	(2)
Unrecognized Tax Benefit at End of Year	$ 72	$ 85	$ 91

LONG-TERM DEBT - Amounts Outsta

LONG-TERM DEBT - Amounts Outstanding and Principal Repayments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2024 USD ($)	Aug. 15, 2024 USD ($)	Dec. 31, 2023 USD ($)
Debt Instrument [Line Items]
Outstanding	$ 48,172	$ 53,118
Current portion of long-term debt	(2,955)	(2,938)
Unamortized debt discount and issue costs	(252)	(312)
Fair value adjustments	11	108
Noncurrent portion of long-term debt	44,976	49,976
Fair value adjustments of interest rate hedge		11
Derivative Liabilities	(716)	(521)
Repayments of Long-term Debt [Abstract]
2025	2,955
2026	2,810
2027	3,158
2028	6,083
2029	1,333
Fair Value Hedges
Debt Instrument [Line Items]
Derivative Liabilities	(139)	(47)
Columbia Pipeline Group, Inc
Debt Instrument [Line Items]
Fair value adjustments of interest rate hedge	109	119
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	30,126	36,815
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	551	647
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Debt Instrument [Line Items]
Outstanding	1,973	2,621
Medium Term Notes | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	$ 13,141	$ 15,466
Interest rate	4.70%	4.60%	4.70%		4.60%
Senior Unsecured Notes | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	$ 16,985	$ 21,349	$ 11,792		$ 16,167
Interest rate	5.50%	5%	5.50%		5%
Senior Unsecured Notes | COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Outstanding	$ 9,362	$ 8,055	$ 6,500		$ 6,100
Interest rate	6%	6.10%	6%		6.10%
Senior Unsecured Notes | COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Outstanding	$ 2,737	$ 1,320	$ 1,900		$ 1,000
Interest rate	5.90%	6.20%	5.90%		6.20%
Senior Unsecured Notes | ANR PIPELINE COMPANY
Debt Instrument [Line Items]
Outstanding	$ 1,509	$ 1,548	$ 1,047		$ 1,172
Interest rate	3.70%	4.10%	3.70%		4.10%
Senior Unsecured Notes | TC PIPELINES, LP
Debt Instrument [Line Items]
Outstanding	$ 1,224	$ 1,122	$ 850		$ 850
Interest rate	4.20%	4.20%	4.20%		4.20%
Senior Unsecured Notes | GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Outstanding	$ 540	$ 495	$ 375		$ 375
Interest rate	4.40%	4.40%	4.40%		4.40%
Senior Unsecured Notes | Portland Natural Gas Transmission System
Debt Instrument [Line Items]
Outstanding	$ 0	$ 330	$ 0	$ 250	$ 250
Interest rate	0%	2.80%	0%		2.80%
Senior Unsecured Notes | GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Debt Instrument [Line Items]
Outstanding	$ 150	$ 165	$ 104		$ 125
Interest rate	7.60%	7.60%	7.60%		7.60%
Debentures and Notes | NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	$ 0	$ 100
Interest rate	0%	9.90%	0%		9.90%
Medium-Term Notes, Maturity between 2025 and 2030 | NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	$ 504	$ 504
Interest rate	7.40%	7.40%	7.40%		7.40%
Medium-Term Notes, Maturity Date of 2026 | NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	$ 47	$ 43	$ 33		$ 33
Interest rate	7.50%	7.50%	7.50%		7.50%
Senior Unsecured Term Loan | TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Debt Instrument [Line Items]
Outstanding	$ 1,973	$ 2,377	$ 1,370		$ 1,800
Interest rate	7.20%	7.70%	7.20%		7.70%
Unsecured Revolving Credit Facility | TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Debt Instrument [Line Items]
Outstanding	$ 0	$ 244	$ 0		$ 185
Interest rate	0%	7.70%	0%		7.70%

LONG-TERM DEBT - Issued (Detail

LONG-TERM DEBT - Issued (Details) $ in Millions, $ in Millions	1 Months Ended
	Sep. 30, 2024 USD ($)	Aug. 31, 2024 USD ($)	Jan. 31, 2024 USD ($)	Aug. 31, 2023 USD ($)	Jun. 30, 2023 USD ($)	May 31, 2023 USD ($)	Mar. 31, 2023 USD ($)	Mar. 31, 2023 CAD ($)	Jan. 31, 2023 USD ($)	May 31, 2022 USD ($)	May 31, 2022 CAD ($)
Term Loan August 2024 | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount		$ 1,242
Senior Unsecured Term Loan Due May 2026 | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount						$ 1,024
Senior Unsecured Notes Due March 2026 | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount							$ 850
Interest Rate							6.20%	6.20%
Senior Unsecured Notes One Due March 2026 | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount							$ 400
Medium Term Notes Due July 2030 | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount								$ 1,250
Interest Rate							5.28%	5.28%
Medium Term Notes Due March 2026 | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount								$ 600
Interest Rate							5.42%	5.42%
Medium Term Notes One Due March 2026 | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount								$ 400
Medium Term Notes due May 2032 | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount											$ 800
Interest Rate										5.33%	5.33%
Medium Term Notes due May 2026 | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount											$ 400
Interest Rate										4.35%	4.35%
Medium Term Notes due May 2052 | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Amount											$ 300
Interest Rate										5.92%	5.92%
Senior Unsecured Notes Due October 2054 | COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount	$ 400
Interest Rate	5.70%
Senior Unsecured Notes Due November 2033 | COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount				$ 1,500
Interest Rate				6.04%
Senior Unsecured Notes Due November 2053 | COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount				$ 1,250
Interest Rate				6.54%
Senior Unsecured Notes Due August 2030 | COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount				$ 750
Interest Rate				5.93%
Senior Unsecured Notes Due August 2043 | COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount				$ 600
Interest Rate				6.50%
Senior Unsecured Notes Due August 2063 | COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Amount				$ 500
Interest Rate				6.71%
Senior Unsecured Notes due October 2031 | COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Amount	$ 400
Interest Rate	5.10%
Senior Unsecured Notes Due January 2034 | COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Amount			$ 500
Interest Rate			5.68%
Senior Unsecured Notes Due August 2028 | COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Amount				$ 700
Interest Rate				6.04%
Senior Unsecured Notes Due August 2026 | COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Amount				$ 300
Interest Rate				6.06%
Senior Unsecured Notes due June 2030 | GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Amount					$ 50
Interest Rate					4.92%
Senior Unsecured Term Loan Due January 2028 | TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Debt Instrument [Line Items]
Amount									$ 1,800
Senior Unsecured Revolving Credit Facility Due January 2028 | TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Debt Instrument [Line Items]
Amount									$ 500
Senior Unsecured Notes due May 2032 | ANR PIPELINE COMPANY
Debt Instrument [Line Items]
Amount										$ 300
Interest Rate										3.43%	3.43%
Senior Unsecured Notes due May 2034 | ANR PIPELINE COMPANY
Debt Instrument [Line Items]
Amount										$ 200
Interest Rate										3.58%	3.58%
Senior Unsecured Notes due May 2037 | ANR PIPELINE COMPANY
Debt Instrument [Line Items]
Amount										$ 200
Interest Rate										3.73%	3.73%
Senior Unsecured Notes due May 2029 | ANR PIPELINE COMPANY
Debt Instrument [Line Items]
Amount										$ 100
Interest Rate										3.26%	3.26%

LONG-TERM DEBT - Retired_Repaid

LONG-TERM DEBT - Retired/Repaid (Details) $ in Millions, $ in Millions

1 Months Ended

12 Months Ended

Oct. 31, 2024 CAD ($)

Oct. 31, 2024 USD ($)

Oct. 31, 2024 CAD ($)

Aug. 31, 2024 USD ($)

Jun. 30, 2024 CAD ($)

Mar. 31, 2024 CAD ($)

Feb. 29, 2024 USD ($)

Nov. 30, 2023 USD ($)

Oct. 31, 2023 USD ($)

Sep. 30, 2023 USD ($)

Jul. 31, 2023 CAD ($)

Apr. 30, 2023 USD ($)

Dec. 31, 2022 CAD ($)

Aug. 31, 2022 USD ($)

Dec. 31, 2024 USD ($)

Dec. 31, 2023 USD ($)

Mar. 31, 2023

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 1,250

Interest Rate

1%

1%

1%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 850

Interest Rate

6.20%

6.20%

6.20%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 739

Interest Rate

2.50%

2.50%

2.50%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 441

Interest Rate

4.88%

4.88%

4.88%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 400

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 313

Interest Rate

4.75%

4.75%

4.75%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 201

Interest Rate

5%

5%

5%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 180

Interest Rate

5.10%

5.10%

5.10%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 600

Interest Rate

5.42%

5.42%

5.42%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 575

Interest Rate

4.18%

4.18%

4.18%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes Due October 2024

Debt Instrument [Line Items]

Amount

$ 400

TRANSCANADA PIPELINES LIMITED | Term Loan Due August 2024

Debt Instrument [Line Items]

Amount

$ 1,242

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due June 2024

Debt Instrument [Line Items]

Amount

$ 750

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due October 2023

Debt Instrument [Line Items]

Amount

$ 625

Interest Rate

3.75%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes Due September 2030

Debt Instrument [Line Items]

Amount

$ 1,024

TRANSCANADA PIPELINES LIMITED | Medium Term Note Due July 2023

Debt Instrument [Line Items]

Amount

$ 750

Interest Rate

3.69%

TRANSCANADA PIPELINES LIMITED | Medium Term Note due December 2022

Debt Instrument [Line Items]

Amount

$ 25

Interest Rate

9.95%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due August 2022

Debt Instrument [Line Items]

Amount

$ 1,000

Interest Rate

2.50%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes Due March 2026

Debt Instrument [Line Items]

Interest Rate

6.20%

Long-term debt, weighted average discount, percent

7.73%

7.73%

Pre-tax gain on the debt extinguishment

$ 228

NOVA GAS TRANSMISSION LTD. | Debentures Due March 2024

Debt Instrument [Line Items]

Amount

$ 100

Interest Rate

9.90%

NOVA GAS TRANSMISSION LTD. | Debentures Due April 2023

Debt Instrument [Line Items]

Amount

$ 200

Interest Rate

7.88%

ANR PIPELINE COMPANY | Senior Unsecured Notes due November 2021

Debt Instrument [Line Items]

Amount

$ 125

Interest Rate

7.38%

TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. | Senior Unsecured Term Loan Various

Debt Instrument [Line Items]

Amount

$ 430

TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. | Senior Unsecured Revolving Credit Facility Various 2024

Debt Instrument [Line Items]

Amount

$ 185

TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. | Senior Unsecured Revolving Credit Facility Various 2023

Debt Instrument [Line Items]

Amount

$ 315

TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan Due November 2023

Debt Instrument [Line Items]

Amount

$ 32

LONG-TERM DEBT - Interest Expen

LONG-TERM DEBT - Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Interest Expense, Operating and Nonoperating [Abstract]
Capitalized interest	$ (191)	$ (187)	$ (27)
Amortization and other financial charges	158	106	36
Gain on debt extinguishment	(228)	0	0
Interest expense (Note 20)	3,019	2,966	2,300
Interest allocated to discontinued operations	(218)	(297)	(288)
Interest expense after interest allocated to discontinuing operations	3,237	3,263	2,588
Interest payments, net of interest capitalized	3,398	2,931	2,478
Short-term debt
Interest Expense, Operating and Nonoperating [Abstract]
Interest on debt	60	165	153
Long-term debt (excluding junior subordinated notes)
Interest Expense, Operating and Nonoperating [Abstract]
Interest on debt	2,800	2,562	1,883
Junior subordinated notes
Interest Expense, Operating and Nonoperating [Abstract]
Interest on debt	$ 638	$ 617	$ 543

JUNIOR SUBORDINATED NOTES (Deta

JUNIOR SUBORDINATED NOTES (Details) $ in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2022 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2007 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)
Debt Instrument [Line Items]
Outstanding		$ 48,172			$ 53,118
Unamortized debt discount and issue costs		(252)			(312)
Long-term Debt				$ 2,800		$ 2,000
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding		30,126			36,815
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding		11,146			10,385
Unamortized debt discount and issue costs		(98)			(98)
Long-term Debt		$ 11,048			10,287
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067
Debt Instrument [Line Items]
Debt converted			$ 1,000
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067 | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount				$ 1,000
Stated interest rate		6.35%	6.35%	6.35%
Outstanding		$ 1,440			$ 1,320
Effective interest rate		6.20%		6.20%	6.50%	6.50%
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2075 | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount				$ 750
Stated interest rate		5.88%		5.88%
Outstanding		$ 1,080			$ 990
Effective interest rate		7.50%		7.50%	7.80%	7.80%
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2076 | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount				$ 1,200
Stated interest rate		6.13%		6.13%
Outstanding		$ 1,729			$ 1,585
Effective interest rate		8%		8%	8.30%	8.30%
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2077 | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount				$ 1,500
Stated interest rate		5.55%		5.55%
Outstanding		$ 2,161			$ 1,981
Effective interest rate		7.20%		7.20%	7.50%	7.50%
TRANSCANADA PIPELINES LIMITED | Canadian junior subordinated debt, due 2077 | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,500
Stated interest rate		4.90%		4.90%
Outstanding		$ 1,500			$ 1,500
Effective interest rate		6.80%		6.80%	7%	7%
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2079 | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount				$ 1,100
Stated interest rate		5.75%		5.75%
Outstanding		$ 1,584			$ 1,453
Effective interest rate		7.70%		7.70%	8%	8%
Stated interest rate, period of time		10 years
Stated interest rate, period of time after first ten years		5 years
TRANSCANADA PIPELINES LIMITED | $500 notes due 2081 at 4.45% | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 500
Stated interest rate		4.45%		4.45%
Outstanding		$ 500			$ 500
Effective interest rate		5.70%		5.70%	5.70%	5.70%
TRANSCANADA PIPELINES LIMITED | $800 notes due 2082 at 5.85% | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount				$ 800
Stated interest rate		5.85%		5.85%
Outstanding		$ 1,152			$ 1,056
Effective interest rate		7.30%		7.30%	7.10%	7.10%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2022-A | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount	$ 800
Stated interest rate, period of time	5 years
Administrative charge percentage	0.25%
Redemption price as a percentage of principal amount plus accrued and unpaid interest	100%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2022-A | Period one | Junior subordinated notes
Debt Instrument [Line Items]
Stated interest rate	5.85%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2022-A | Period two | Junior subordinated notes
Debt Instrument [Line Items]
Stated interest rate, period of time	5 years
Variable interest rate	4.236%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2022-A | Period two | Junior subordinated notes | Five-Year Government of Canada Yield
Debt Instrument [Line Items]
Stated interest rate, period of time	5 years
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2022-A | Period three | Junior subordinated notes
Debt Instrument [Line Items]
Variable interest rate	4.986%
TransCanada Trust | Trust Notes - Series 2022-A | Notes payable
Debt Instrument [Line Items]
Debt instrument, face amount	$ 800
TransCanada Trust | Trust Notes - Series 2022-A | Period one | Notes payable
Debt Instrument [Line Items]
Stated interest rate	5.60%
Stated interest rate, period of time	10 years
TransCanada Trust | Trust Notes - Series 2022-A | Period two | Notes payable
Debt Instrument [Line Items]
Stated interest rate, period of time	5 years

FOREIGN EXCHANGE (GAINS) LOSS_3

FOREIGN EXCHANGE (GAINS) LOSSES, NET (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Components of OCI related to derivatives
Foreign exchange gains (losses)	$ 147	$ (320)	$ 185
Derivative instrument held-for-trading
Components of OCI related to derivatives
Foreign exchange gains (losses)	418	(401)	151
Other instruments
Components of OCI related to derivatives
Foreign exchange gains (losses)	$ (271)	$ 81	$ 34

NON-CONTROLLING INTERESTS (Deta

NON-CONTROLLING INTERESTS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Jun. 30, 2023
Non-controlling interests
Net income (loss) attributable to non-controlling interests (Note 23)	$ 681	$ 146	$ 37
Non-Controlling Interests	$ 10,768	9,455
Common Class A | Texas Wind Farms
Non-controlling interests
Business acquisition, percentage of voting interests acquired				100%
Common Class B | Texas Wind Farms
Non-controlling interests
Business acquisition, percentage of voting interests acquired				100%
Columbia Gas and Columbia Gulf
Non-controlling interests
Noncontrolling Interests Ownership	40%
Net income (loss) attributable to non-controlling interests (Note 23)	$ 571	143	0
Non-Controlling Interests	$ 9,844	9,167
Portland Natural Gas Transmission System
Non-controlling interests
Noncontrolling Interests Ownership	0%
Net income (loss) attributable to non-controlling interests (Note 23)	$ 30	41	37
Non-Controlling Interests	$ 0	106
Texas Wind Farms
Non-controlling interests
Noncontrolling Interests Ownership	100%
Net income (loss) attributable to non-controlling interests (Note 23)	$ (29)	(38)	0
Non-Controlling Interests	$ 168	182
TGNH
Non-controlling interests
Noncontrolling Interests Ownership	13.01%
Net income (loss) attributable to non-controlling interests (Note 23)	$ 109	0	$ 0
Non-Controlling Interests	$ 756	$ 0

COMMON SHARES - Reconciliation

COMMON SHARES - Reconciliation and Weighted Average Common Shares Outstanding (Details) - CAD ($) shares in Thousands, $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Number of Shares
Outstanding at the beginning of the period (in shares)		1,037,000	1,037,000
Exercise of options (in shares)	1,244	363
Outstanding at the end of the period (in shares)	1,039,000		1,039,000	1,037,000
Amount
Outstanding at the beginning of the period		$ 30,002	$ 30,002
Outstanding at the end of the period	$ 30,101		$ 30,101	$ 30,002
Common shares
Number of Shares
Outstanding at the beginning of the period (in shares)		1,037,488	1,037,488	1,017,962	980,816
Issued under public offering (in shares)					28,400
Dividend reinvestment and share purchase plan (in shares)				19,464	5,916
Exercise of options (in shares)			1,607	62	2,830
Outstanding at the end of the period (in shares)	1,039,095		1,039,095	1,037,488	1,017,962
Amount
Outstanding at the beginning of the period		$ 30,002	$ 30,002	$ 28,995	$ 26,716
Issued under public offering					1,754
Dividend reinvestment and share purchase plan				1,003	342
Exercise of options			99	4	183
Outstanding at the end of the period	$ 30,101		$ 30,101	$ 30,002	$ 28,995

COMMON SHARES - Common Shares (

COMMON SHARES - Common Shares (Details) - CAD ($) $ / shares in Units, $ in Billions	Oct. 01, 2024	Aug. 10, 2022
Public Offering
Class of Stock [Line Items]
Number of shares issued in transaction (in shares)		28,400,000
Price per share (in Canadian dollars per share)		$ 63.50
Consideration received on transaction		$ 1.8
Common shares | TC Energy
Class of Stock [Line Items]
Spinoff of Liquids Pipelines business (in shares)	1
Common shares | South Bow Canadian Infrastructure Holdings Ltd
Class of Stock [Line Items]
Spinoff of Liquids Pipelines business (in shares)	0.2

COMMON SHARES - Dividend Reinve

COMMON SHARES - Dividend Reinvestment and Share Purchase Plan (Details)	1 Months Ended	31 Months Ended
	Aug. 31, 2022	Jul. 31, 2023
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Discount of shares issued from treasury	2%
Price of shares issued from treasury		100%

COMMON SHARES - Weighted Averag

COMMON SHARES - Weighted Average Common Shares Outstanding (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Class of Stock [Line Items]
Basic (in shares)	1,038	1,030	995
Diluted (in shares)	1,038	1,030	996
Common shares
Class of Stock [Line Items]
Basic (in shares)	1,038	1,030	995
Diluted (in shares)	1,038	1,030	996

COMMON SHARES - Options (Detail

COMMON SHARES - Options (Details) - $ / shares	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2024	Sep. 30, 2024	Dec. 31, 2024
Number of Options
Outstanding at the beginning of the period (in shares)	6,475,000	7,436,000	7,436,000
Cancelled (in shares)	(6,475,000)
Issued (in shares)	5,889,000
Exercised (in shares)	(1,244,000)	(363,000)
Options forfeited/expired (in shares)	(171,000)	(598,000)
Outstanding at the end of the period (in shares)	4,474,000	6,475,000	4,474,000
Options Exercisable (in shares)	3,169,000	4,975,000	3,169,000
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share)	$ 62.54	$ 62.36	$ 62.36
Cancelled (in Canadian dollars per share)	62.54
Issued (in Canadian dollars per share)	59.72
Exercised (in Canadian dollars per share)	54.49	56.85
Options forfeited/expired (in Canadian dollars per share)	72.17	63.70
Outstanding at the end of the period (in Canadian dollars per share)	60.69	62.54	60.69
Options Exercisable at December 31, 2020 (in Canadian dollars per share)	$ 62.50	$ 63.54	$ 62.50
Weighted Average Remaining Contractual Life
Options Outstanding at December 31, 2024	3 years 7 months 6 days	3 years 6 months
Options Exercisable at December 31, 2024	3 years 1 month 6 days	3 years
Number of shares available for grant (in shares)	3,621,343		3,621,343
Options expiration term			7 years
Award vesting period			3 years

COMMON SHARES - Stock Options A

COMMON SHARES - Stock Options Assumptions Used (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Weighted average fair value (in Canadian dollars per share)	$ 0	$ 7.88	$ 8.24
Expected life (years)		5 years 1 month 6 days	5 years 4 months 24 days
Interest rate	0%	2.90%	1.60%
Volatility	0%	24%	22%
Dividend yield	0%	6.30%	5.50%
Expense for stock options	$ 6	$ 9	$ 10
Unrecognized compensation costs related to non-vested stock options	$ 1
Expense recognition period	8 months 12 days

COMMON SHARES - Summary of Addi

COMMON SHARES - Summary of Additional Stock Options Information (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Total intrinsic value of options exercised	$ 17	$ 0	$ 33
Total fair value of options that have vested	$ 99	$ 76	$ 89
Total options vested (in shares)	1.5	1.5	1.6
Options, exercisable, intrinsic value	$ 20
Options, outstanding, intrinsic value	$ 34

COMMON SHARES - Shareholder Rig

COMMON SHARES - Shareholder Rights Plan (Details)	Dec. 31, 2024 shares
Shareholder Rights Plan
Number of rights entitled to each common share (in shares)	1

PREFERRED SHARES - Schedule of

PREFERRED SHARES - Schedule of Preferred Shares (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions				1 Months Ended			12 Months Ended
	Dec. 31, 2024	Oct. 31, 2024	Apr. 30, 2024	Dec. 30, 2024	Oct. 30, 2024	Apr. 29, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Class of Stock [Line Items]
Preferred shares	$ 2,499						$ 2,499	$ 2,499	$ 2,499
Series 1
Class of Stock [Line Items]
Number of shares outstanding (in shares)	18,424						18,424
Current yield (as a percent)	4.94%			3.48%			4.94%
Annual dividend ( in Canadian dollars per share)							$ 1.23475
Redemption price per share (in Canadian dollars per share)	$ 25						$ 25
Preferred shares	$ 456						$ 456	360	360
Series 1 | Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	1.92%						1.92%
Series 2
Class of Stock [Line Items]
Number of shares outstanding (in shares)	3,576						3,576
Current yield (as a percent)							5.40%
Redemption price per share (in Canadian dollars per share)	$ 25						$ 25
Preferred shares	$ 83						$ 83	179	179
Series 2 | Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	1.92%						1.92%
Series 3
Class of Stock [Line Items]
Number of shares outstanding (in shares)	9,997						9,997
Current yield (as a percent)							1.69%
Annual dividend ( in Canadian dollars per share)							$ 0.4235
Redemption price per share (in Canadian dollars per share)	$ 25						$ 25
Preferred shares	$ 246						$ 246	246	246
Series 3 | Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	1.28%						1.28%
Series 4
Class of Stock [Line Items]
Number of shares outstanding (in shares)	4,003						4,003
Current yield (as a percent)							4.76%
Redemption price per share (in Canadian dollars per share)	$ 25						$ 25
Preferred shares	$ 97						$ 97	97	97
Series 4 | Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	1.28%						1.28%
Series 5
Class of Stock [Line Items]
Number of shares outstanding (in shares)	12,071						12,071
Current yield (as a percent)							1.95%
Annual dividend ( in Canadian dollars per share)							$ 0.48725
Redemption price per share (in Canadian dollars per share)	$ 25						$ 25
Preferred shares	$ 294						$ 294	294	294
Series 5 | Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	1.54%						1.54%
Series 6
Class of Stock [Line Items]
Number of shares outstanding (in shares)	1,929						1,929
Current yield (as a percent)							5.52%
Redemption price per share (in Canadian dollars per share)	$ 25						$ 25
Preferred shares	$ 48						$ 48	48	48
Series 6 | Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	1.54%						1.54%
Series 7
Class of Stock [Line Items]
Number of shares outstanding (in shares)	24,000						24,000
Current yield (as a percent)			5.99%			3.90%	5.99%
Annual dividend ( in Canadian dollars per share)							$ 1.49625
Redemption price per share (in Canadian dollars per share)	$ 25						$ 25
Preferred shares	$ 589						$ 589	589	589
Series 7 | Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	2.38%						2.38%
Series 9
Class of Stock [Line Items]
Number of shares outstanding (in shares)	16,703						16,703
Current yield (as a percent)		5.08%			3.76%		5.08%
Annual dividend ( in Canadian dollars per share)							$ 1.27
Redemption price per share (in Canadian dollars per share)	$ 25						$ 25
Preferred shares	$ 410						$ 410	442	442
Series 9 | Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	2.35%						2.35%
Series 10
Class of Stock [Line Items]
Number of shares outstanding (in shares)	1,297						1,297
Current yield (as a percent)							6.33%
Redemption price per share (in Canadian dollars per share)	$ 25						$ 25
Preferred shares	$ 32						$ 32	0	0
Series 10 | Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	2.35%						2.35%
Series 11
Class of Stock [Line Items]
Number of shares outstanding (in shares)	10,000						10,000
Current yield (as a percent)							3.35%
Annual dividend ( in Canadian dollars per share)							$ 0.83775
Redemption price per share (in Canadian dollars per share)	$ 25						$ 25
Preferred shares	$ 244						$ 244	$ 244	$ 244
Series 11 | Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	2.96%						2.96%
Even numbered series of preferred shares
Class of Stock [Line Items]
Period of Government of Canada bond or treasury bill considered for calculation of dividend yield per annum							90 days
Series 8 | Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	2.38%						2.38%
Series 12 | Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)	2.96%						2.96%
Odd numbered series of preferred shares
Class of Stock [Line Items]
Period of time preferred stock or bond is considered for dividend yield calculation							5 years

PREFERRED SHARES - Narrative (D

PREFERRED SHARES - Narrative (Details) $ in Millions				3 Months Ended	12 Months Ended
	Dec. 31, 2024 $ / shares shares	Oct. 31, 2024 shares	May 31, 2022 $ / shares shares	Mar. 31, 2022 USD ($) $ / shares	Dec. 31, 2024 $ / shares
Trust Notes - Series 2022-A | Notes payable | TransCanada Trust
Class of Stock [Line Items]
Total committed amount | $				$ 800
Series 2, Series 4, Series 6 and Series 10 Preferred Stock
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)	$ 25.50				$ 25.50
Series 1
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)	$ 25				$ 25
Shares converted (in shares) | shares	42,200
Conversion ratio	1				1
Annual dividend ( in Canadian dollars per share)					$ 1.23475
Series 2
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)	$ 25				$ 25
Shares converted (in shares) | shares	3,889,020
Conversion ratio	1				1
Series 9
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)	$ 25				$ 25
Shares converted (in shares) | shares		1,297,203
Conversion ratio		1
Annual dividend ( in Canadian dollars per share)					$ 1.27
Series Fifteen Cumulative Preferred Stock
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)			$ 25
Stock redeemed during period (in shares) | shares			40,000,000
Annual dividend ( in Canadian dollars per share)				$ 0.30625

OTHER COMPREHENSIVE INCOME(LO_3

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) - Components (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Before Tax Amount
Other Comprehensive Income (Loss)	$ 1,891	$ (1,326)	$ 2,613
Income Tax (Expense) Recovery
Other Comprehensive Income (Loss)	(63)	54	(216)
Net of Tax Amount
Other comprehensive income (loss) (Note 26)	1,828	(1,272)	2,397
Foreign currency translation gains and losses on net investment in foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications	1,582	(1,148)	1,410
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	20	7	84
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	1,602	(1,141)	1,494
Reclassification of foreign currency translation (gains) on net investment on disposal of foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(25)
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	0
Net of Tax Amount
Reclassification from accumulated other comprehensive income (loss)	25
Currency Translation Adjustments
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	692	(231)	1,450
Reclassification from accumulated other comprehensive income (loss)	(15)	0	0
Other comprehensive income (loss) (Note 26)	677	(231)	1,450
Change in fair value of net investment hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(23)	23	(48)
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	5	(6)	12
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(18)	17	(36)
Change in fair value and reclassification of gains and losses of cash flow hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	46		(58)
Reclassification from accumulated other comprehensive Income (loss)	(20)	97	63
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	(11)		19
Reclassification from AOCI	4	(23)	(21)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	35		(39)
Reclassification from accumulated other comprehensive income (loss)	(16)	74	42
Unrealized actuarial gains and losses and reclassification of actuarial gains and losses of pension and other post-retirement benefits
Before Tax Amount
Other comprehensive income (loss), before reclassifications	107	(15)	81
Reclassification from accumulated other comprehensive Income (loss)	(6)		9
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	(24)	4	(18)
Reclassification from AOCI	0		(3)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	83	(11)	63
Reclassification from accumulated other comprehensive income (loss)	(6)		6
Other comprehensive income (loss) on equity investments
Before Tax Amount
Other Comprehensive Income (Loss)	230	(283)	1,156
Income Tax (Expense) Recovery
Other Comprehensive Income (Loss)	(57)	72	(289)
Net of Tax Amount
Other comprehensive income (loss) (Note 26)	$ 173	$ (211)	$ 867

OTHER COMPREHENSIVE INCOME(LO_4

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) - Reconciliation (Details) - CAD ($) $ in Millions			12 Months Ended
	May 29, 2024	Oct. 04, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year			$ 29,553
Other comprehensive income (loss) (Note 26)			1,828	$ (1,272)	$ 2,397
Balance at end of year			27,592	29,553
Cash flow hedge loss reclassified within twelve months			5
Gain (loss) to be reclassified within twelve months			4
Columbia Gas and Columbia Gulf
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Equity interest percentage		40%
Transportadora de Gas Natural de la Huasteca
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Equity interest percentage	13.01%	13.01%
AOCI Attributable to Parent
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year			49	955	(1,434)
Other comprehensive income (loss) before reclassifications			998	(437)	2,344
Amounts reclassified from AOCI			(52)	58	45
Other comprehensive income (loss) (Note 26)			946	(379)	2,389
Impact of non-controlling interest			(21)	(527)
Spinoff of Liquids Pipelines business (Note 4)			(741)
Balance at end of year			233	49	955
Currency Translation Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year			(317)	441	(1,009)
Other comprehensive income (loss) before reclassifications			692	(231)	1,450
Amounts reclassified from AOCI			(15)	0	0
Other comprehensive income (loss) (Note 26)			677	(231)	1,450
Impact of non-controlling interest			(21)	(527)
Spinoff of Liquids Pipelines business (Note 4)			(741)
Balance at end of year			(402)	(317)	441
Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year			(35)	(109)	(112)
Other comprehensive income (loss) before reclassifications			35	0	(39)
Amounts reclassified from AOCI			(16)	74	42
Other comprehensive income (loss) (Note 26)			19	74	3
Impact of non-controlling interest			0	0
Spinoff of Liquids Pipelines business (Note 4)			0
Balance at end of year			(16)	(35)	(109)
Pension and Other Post-Retirement Benefit Plan Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year			(55)	(44)	(113)
Other comprehensive income (loss) before reclassifications			83	(11)	63
Amounts reclassified from AOCI			(6)	0	6
Other comprehensive income (loss) (Note 26)			77	(11)	69
Impact of non-controlling interest			0	0
Spinoff of Liquids Pipelines business (Note 4)			0
Balance at end of year			22	(55)	(44)
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year			456	667	(200)
Other comprehensive income (loss) before reclassifications			188	(195)	870
Amounts reclassified from AOCI			(15)	(16)	(3)
Other comprehensive income (loss) (Note 26)			173	(211)	867
Impact of non-controlling interest			0	0
Spinoff of Liquids Pipelines business (Note 4)			0
Balance at end of year			629	456	667
Accumulated foreign currency adjustment attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive income (loss) before reclassifications			$ 903	$ (366)	$ 8

OTHER COMPREHENSIVE INCOME(LO_5

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) - Reclassifications (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Energy Solutions)	$ 13,771	$ 13,267	$ 12,309
Interest expense	(3,019)	(2,966)	(2,300)
Total before tax	5,906	3,298	474
Income tax (expense) recovery	(922)	(842)	(322)
Net income (loss) attributable to common shares from continuing operations	4,594	2,829	641
Plant operating costs and other	4,413	4,073	4,228
Income (loss) from equity investments	1,558	1,310	999
Net gain (loss) on sale of assets	620	0	0
Amounts reclassified from AOCI | Cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	20	(97)	(63)
Income tax (expense) recovery	(4)	23	21
Net income (loss) attributable to common shares from continuing operations	16	(74)	(42)
Amounts reclassified from AOCI | Cash flow hedges | Interest rate
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(12)	(12)	(16)
Amounts reclassified from AOCI | Pension and other post-retirement benefit plan adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	6	0	(9)
Income tax (expense) recovery	0	0	3
Net income (loss) attributable to common shares from continuing operations	6	0	(6)
Amounts reclassified from AOCI | Amortization of actuarial gains (losses)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other	6	0	(11)
Amounts reclassified from AOCI | Settlement gain (loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other	0	0	2
Amounts reclassified from AOCI | Equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax (expense) recovery	(4)	(6)	(1)
Net income (loss) attributable to common shares from continuing operations	15	16	3
Income (loss) from equity investments	19	22	4
Amounts reclassified from AOCI | Currency Translation Adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax (expense) recovery	0	0	0
Net income (loss) attributable to common shares from continuing operations	15	0	0
Net gain (loss) on sale of assets	15	0	0
Power and Energy Solutions | Amounts reclassified from AOCI | Cash flow hedges | Commodities
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Energy Solutions)	$ 32	$ (85)	$ (47)

EMPLOYEE POST-RETIREMENT BENE_3

EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments, Changes and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized	12 years	12 years	12 years
Expense for savings plan and DC Plans	$ 71	$ 64	$ 64
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Savings and DC Plans	71	64	64
Total cash contributions	79	101	$ 150
Change in Plan Assets
Plan assets at fair value – beginning of year	4,055
Plan assets at fair value – end of year	4,397	4,055
Amounts recognized in the Balance Sheet
Other long-term assets (Note 15)	758	518
Other long-term liabilities (Note 18)	$ (94)	$ (97)
Pension Benefit Plans
Employee post-retirement benefits
Expected average remaining service life of employees over which past service costs are amortized	9 years	9 years	9 years
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans	$ 0	$ 28	$ 78
Total amount outstanding under letters of credit	133	78
Settlement gain (loss), before tax	0	0	(2)
Net benefit cost recognized	20	17	51
Change in Benefit Obligation
Benefit obligation – beginning of year	3,356	3,081
Service cost	108	93	145
Interest cost	160	158	125
Employee contributions	11	7
Benefits paid	(194)	(185)
Actuarial (gain) loss	(39)	219
South Bow - transition of benefit obligation	(118)	0
Foreign exchange rate changes	58	(17)
Benefit obligation – end of year	3,342	3,356	3,081
Change in Plan Assets
Plan assets at fair value – beginning of year	3,697	3,481
Actual return on plan assets	485	385
Employer contributions	0	28
Employee contributions	11	7
Benefits paid	(194)	(185)
South Bow - transition of plan assets	(119)	0
Foreign exchange rate changes	68	(19)
Plan assets at fair value – end of year	3,948	3,697	3,481
Funded Status – Plan Surplus	$ 606	$ 341
Discount rate	4.90%	4.75%
Amounts recognized in the Balance Sheet
Other long-term assets (Note 15)	$ 606	$ 341
Accounts payable and other	0	0
Other long-term liabilities (Note 18)	0	0
Net	606	341
Pension Benefit Plans | South Bow
Change in Plan Assets
Plan assets at fair value – beginning of year	0
Plan assets at fair value – end of year	110	0
Pension Benefit Plans | TC Energy and South Bow
Change in Plan Assets
Plan assets at fair value – beginning of year	3,697
Plan assets at fair value – end of year	$ 4,058	3,697
Pension Benefit Plans | Minimum
Employee post-retirement benefits
Consecutive period of employment for highest average earnings	3 years
Pension Benefit Plans | Maximum
Employee post-retirement benefits
Consecutive period of employment for highest average earnings	5 years
Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans	$ 8	9	8
Settlement gain (loss), before tax	0	0	0
Net benefit cost recognized	(1)	3	6
Change in Benefit Obligation
Benefit obligation – beginning of year	285	310
Service cost	1	3	5
Interest cost	14	16	13
Employee contributions	2	2
Benefits paid	(24)	(44)
Actuarial (gain) loss	(5)	2
South Bow - transition of benefit obligation	(1)	0
Foreign exchange rate changes	16	(4)
Benefit obligation – end of year	288	285	310
Change in Plan Assets
Plan assets at fair value – beginning of year	358	354
Actual return on plan assets	17	24
Employer contributions	(41)	9
Employee contributions	2	2
Benefits paid	(25)	(23)
South Bow - transition of plan assets	0	0
Foreign exchange rate changes	28	(8)
Plan assets at fair value – end of year	339	358	354
Funded Status – Plan Surplus	$ 51	$ 73
Discount rate	5.45%	5.10%
OPEB surplus transferred to pay future active employee medical expenses		$ 49
Amounts recognized in the Balance Sheet
Other long-term assets (Note 15)	$ 152	177
Accounts payable and other	(7)	(7)
Other long-term liabilities (Note 18)	(94)	(97)
Net	51	73
Canadian | Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Total amount outstanding under letters of credit	$ 111	$ 244	322
United States | Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Settlement gain (loss), before tax			$ 2

EMPLOYEE POST-RETIREMENT BENE_4

EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Benefit obligation and fair value of plan assets for plans that are not fully funded
Plan assets at fair value	$ 4,397	$ 4,055
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100%	100%
Pension Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	$ (3,342)	$ (3,356)	$ (3,081)
Plan assets at fair value	3,948	3,697	3,481
Funded Status – Plan Surplus	606	341
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(3,097)	(3,090)
Funded Status – Plan Surplus	$ 961	$ 607
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100%	100%
Pension Benefit Plans | TC Energy and South Bow
Benefit obligation and fair value of plan assets for plans that are not fully funded
Plan assets at fair value	$ 4,058	$ 3,697
Pension Benefit Plans | Fixed income securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	37%	41%
Company debt or common shares included in plan assets, amount	$ 44	$ 7
Company debt or common shares included in plan assets, percentage	1.10%	0.20%
Pension Benefit Plans | Fixed income securities | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	25%
Pension Benefit Plans | Fixed income securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	50%
Pension Benefit Plans | Equity securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	49%	44%
Company debt or common shares included in plan assets, amount	$ 3	$ 2
Company debt or common shares included in plan assets, percentage	0.10%	0.10%
Pension Benefit Plans | Equity securities | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	25%
Pension Benefit Plans | Equity securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	55%
Pension Benefit Plans | Other investments
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	14%	15%
Pension Benefit Plans | Other investments | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	10%
Pension Benefit Plans | Other investments | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	35%
Pension Benefit Plans | Not fully funded
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	$ 0	$ 0
Plan assets at fair value	0	0
Funded Status – Plan Surplus	0	0
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	(288)	(285)	(310)
Plan assets at fair value	339	358	$ 354
Funded Status – Plan Surplus	51	73
Other Post-Retirement Benefit Plans | Not fully funded
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	(101)	(104)
Plan assets at fair value	0	0
Funded Status – Plan Surplus	$ (101)	$ (104)

EMPLOYEE POST-RETIREMENT BENE_5

EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Employee post-retirement benefits
Fair value of plan assets	$ 4,397	$ 4,055
Percentage of Plan Assets	100%	100%
Pension Benefit Plans
Employee post-retirement benefits
Fair value of plan assets	$ 3,948	$ 3,697	$ 3,481
Percentage of Plan Assets	100%	100%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 2,324	$ 2,057
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1,483	1,436
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	590	562	$ 632
Cash and Cash Equivalents
Employee post-retirement benefits
Fair value of plan assets	$ 138	$ 69
Percentage of Plan Assets	3%	2%
Cash and Cash Equivalents | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 138	$ 68
Cash and Cash Equivalents | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	1
Cash and Cash Equivalents | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, Canadian
Employee post-retirement benefits
Fair value of plan assets	$ 128	$ 121
Percentage of Plan Assets	3%	3%
Equity Securities, Canadian | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 128	$ 121
Equity Securities, Canadian | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, Canadian | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, U.S.
Employee post-retirement benefits
Fair value of plan assets	$ 1,234	$ 965
Percentage of Plan Assets	28%	24%
Equity Securities, U.S. | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 1,234	$ 965
Equity Securities, U.S. | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, U.S. | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, International
Employee post-retirement benefits
Fair value of plan assets	$ 391	$ 354
Percentage of Plan Assets	9%	9%
Equity Securities, International | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 182	$ 167
Equity Securities, International | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	209	187
Equity Securities, International | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, Global
Employee post-retirement benefits
Fair value of plan assets	$ 100	$ 74
Percentage of Plan Assets	2%	2%
Equity Securities, Global | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Equity Securities, Global | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	100	74
Equity Securities, Global | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Equity Securities, Emerging
Employee post-retirement benefits
Fair value of plan assets	$ 216	$ 194
Percentage of Plan Assets	5%	5%
Equity Securities, Emerging | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 66	$ 54
Equity Securities, Emerging | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	150	140
Equity Securities, Emerging | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Federal
Employee post-retirement benefits
Fair value of plan assets	$ 55	$ 266
Percentage of Plan Assets	1%	7%
Fixed Income Securities, Canadian Bonds, Federal | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Federal | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	55	266
Fixed Income Securities, Canadian Bonds, Federal | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Provincial
Employee post-retirement benefits
Fair value of plan assets	$ 312	$ 314
Percentage of Plan Assets	7%	8%
Fixed Income Securities, Canadian Bonds, Provincial | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Provincial | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	312	314
Fixed Income Securities, Canadian Bonds, Provincial | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Municipal
Employee post-retirement benefits
Fair value of plan assets	$ 14	$ 16
Percentage of Plan Assets	0%	0%
Fixed Income Securities, Canadian Bonds, Municipal | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Municipal | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	14	16
Fixed Income Securities, Canadian Bonds, Municipal | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Corporate
Employee post-retirement benefits
Fair value of plan assets	$ 323	$ 143
Percentage of Plan Assets	7%	4%
Fixed Income Securities, Canadian Bonds, Corporate | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Corporate | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	323	143
Fixed Income Securities, Canadian Bonds, Corporate | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, U.S. Bonds, Federal
Employee post-retirement benefits
Fair value of plan assets	$ 406	$ 425
Percentage of Plan Assets	9%	10%
Fixed Income Securities, U.S. Bonds, Federal | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 151	$ 185
Fixed Income Securities, U.S. Bonds, Federal | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	255	240
Fixed Income Securities, U.S. Bonds, Federal | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, U.S. Bonds, Municipal
Employee post-retirement benefits
Fair value of plan assets	$ 1	$ 1
Percentage of Plan Assets	0%	0%
Fixed Income Securities, U.S. Bonds, Municipal | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, U.S. Bonds, Municipal | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1	1
Fixed Income Securities, U.S. Bonds, Municipal | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, U.S. Bonds, Corporate
Employee post-retirement benefits
Fair value of plan assets	$ 404	$ 386
Percentage of Plan Assets	9%	10%
Fixed Income Securities, U.S. Bonds, Corporate | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 246	$ 312
Fixed Income Securities, U.S. Bonds, Corporate | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	158	74
Fixed Income Securities, U.S. Bonds, Corporate | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, International, Government
Employee post-retirement benefits
Fair value of plan assets	$ 21	$ 15
Percentage of Plan Assets	1%	0%
Fixed Income Securities, International, Government | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 4	$ 4
Fixed Income Securities, International, Government | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	17	11
Fixed Income Securities, International, Government | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, International, Corporate
Employee post-retirement benefits
Fair value of plan assets	$ 66	$ 83
Percentage of Plan Assets	2%	2%
Fixed Income Securities, International, Corporate | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, International, Corporate | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	66	83
Fixed Income Securities, International, Corporate | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, International, Mortgage-backed
Employee post-retirement benefits
Fair value of plan assets	$ 60	$ 60
Percentage of Plan Assets	1%	1%
Fixed Income Securities, International, Mortgage-backed | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 37	$ 43
Fixed Income Securities, International, Mortgage-backed | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	23	17
Fixed Income Securities, International, Mortgage-backed | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Net Forward Contract, International
Employee post-retirement benefits
Fair value of plan assets	$ (201)	$ (131)
Percentage of Plan Assets	4%	4%
Net Forward Contract, International | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Net Forward Contract, International | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	(201)	(131)
Net Forward Contract, International | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Real estate
Employee post-retirement benefits
Fair value of plan assets	$ 276	$ 283
Percentage of Plan Assets	6%	7%
Real estate | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Real estate | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Real estate | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	276	283
Infrastructure
Employee post-retirement benefits
Fair value of plan assets	$ 282	$ 269
Percentage of Plan Assets	7%	7%
Infrastructure | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Infrastructure | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Infrastructure | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	282	269
Private equity funds
Employee post-retirement benefits
Fair value of plan assets	$ 32	$ 10
Percentage of Plan Assets	1%	0%
Private equity funds | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Private equity funds | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Private equity funds | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	32	10
Funds held on deposit
Employee post-retirement benefits
Fair value of plan assets	$ 138	$ 138
Percentage of Plan Assets	3%	3%
Funds held on deposit | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 138	$ 138
Funds held on deposit | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Funds held on deposit | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Derivatives
Employee post-retirement benefits
Fair value of plan assets	$ 1	$ 0
Percentage of Plan Assets	0%	0%
Derivatives | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Derivatives | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1	0
Derivatives | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0

EMPLOYEE POST-RETIREMENT BENE_6

EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	$ 4,055
Plan assets at fair value – end of year	4,397	$ 4,055
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	562	632
Purchases and sales	(15)	(76)
Realized and unrealized gains (losses)	43	6
Plan assets at fair value – end of year	$ 590	$ 562

EMPLOYEE POST-RETIREMENT BENE_7

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for savings plan and DC Plans	$ 71
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits	6.15%
Percentage level to which average annual rate was assumed to decrease	4.85%
Pension Benefit Plans
DB Plans
Company's expected funding contributions	$ 0
Estimated future benefit payments, which reflect expected future service
2025	209
2026	212
2027	216
2028	218
2029	221
2030 to 2034	$ 1,139
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	4.90%	4.75%
Rate of compensation increase	3.05%	3.20%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	4.75%	5.15%	3.05%
Expected long-term rate of return on plan assets	6.60%	6.45%	6.10%
Rate of compensation increase	3.15%	3.25%	3%
Net benefit cost
Service cost	$ 108	$ 93	$ 145
Other components of net benefit cost
Interest cost	160	158	125
Expected return on plan assets	(248)	(234)	(239)
Amortization of actuarial loss	0	0	10
Amortization of regulatory asset	0	0	12
Settlement gain – AOCI	0	0	(2)
Other components of net benefit cost	(88)	(76)	(94)
Net Benefit Cost Recognized	20	17	51
Pre-tax amounts recognized in AOCI
Net loss (gain)	(24)	71	38
Pre-tax amounts recognized in OCI
Amortization of net gain (loss) from AOCI to net income	6	0	(10)
Settlement	0	0	2
Funded status adjustment	(101)	33	(101)
Total pre-tax amounts recognized in OCI	(95)	$ 33	(109)
Pension Benefit Plans | United States
Pre-tax amounts recognized in OCI
Settlement			$ (2)
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	6
Estimated future benefit payments, which reflect expected future service
2025	24
2026	24
2027	24
2028	24
2029	23
2030 to 2034	$ 110
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	5.45%	5.10%
Rate of compensation increase	0%	0%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	5.15%	5.45%	3.10%
Expected long-term rate of return on plan assets	4.50%	4.50%	3.25%
Rate of compensation increase	0%	0%	0%
Net benefit cost
Service cost	$ 1	$ 3	$ 5
Other components of net benefit cost
Interest cost	14	16	13
Expected return on plan assets	(14)	(16)	(14)
Amortization of actuarial loss	0	0	1
Amortization of regulatory asset	(2)	0	1
Settlement gain – AOCI	0	0	0
Other components of net benefit cost	(2)	0	1
Net Benefit Cost Recognized	(1)	3	6
Pre-tax amounts recognized in AOCI
Net loss (gain)	0	6	24
Pre-tax amounts recognized in OCI
Amortization of net gain (loss) from AOCI to net income	0	0	(1)
Settlement	0	0	0
Funded status adjustment	(6)	(18)	20
Total pre-tax amounts recognized in OCI	$ (6)	$ (18)	$ 19

RISK MANAGEMENT AND FINANCIAL_3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Derivative [Line Items]
Fair Value	$ (247)	$ 223
Designated as a net investment hedge
Derivative [Line Items]
Fair Value	(11)	10
Designated as a net investment hedge | US$ denominated
Derivative [Line Items]
Notional Amount			$ 100	$ 1,200
U.S. dollar cross-currency interest rate swaps (maturing 2025) | Designated as a net investment hedge
Derivative [Line Items]
Fair Value	(11)	2
U.S. dollar cross-currency interest rate swaps (maturing 2025) | Designated as a net investment hedge | US$ denominated
Derivative [Line Items]
Notional Amount			100	200
Net realized gains related to the interest component	1	1
U.S. dollar foreign exchange options | Designated as a net investment hedge
Derivative [Line Items]
Fair Value	$ 0	$ 8
U.S. dollar foreign exchange options | Designated as a net investment hedge | US$ denominated
Derivative [Line Items]
Notional Amount			$ 0	$ 1,000

RISK MANAGEMENT AND FINANCIAL_4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - U.S. Dollar-Denominated Debt Designated as Net Investment Hedges (Details) - Designated as a net investment hedge $ in Millions, $ in Millions	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)
Derivative [Line Items]
Notional amount	$ 26,000		$ 27,800
Fair value	$ 25,700		$ 26,600
US$ denominated
Derivative [Line Items]
Notional amount		$ 18,000		$ 21,100
Fair value		$ 17,800		$ 20,200

RISK MANAGEMENT AND FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Expected credit loss provision (Note 28)	$ (22,000,000)	$ (83,000,000)	$ 163,000,000
Provision for other credit losses	0	0
Financing receivable, recorded investment, past due	0	0
Past due or impaired	0	0
TGNH
Derivative [Line Items]
Expected credit loss provision (Note 28)	(23,000,000)	(73,000,000)	149,000,000
Mexico Natural Gas Pipelines
Derivative [Line Items]
Expected credit loss provision (Note 28)	$ 1,000,000	$ (10,000,000)	$ 14,000,000

RISK MANAGEMENT AND FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) $ in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2024 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	$ (48,172)	$ (53,118)
Junior subordinated notes (Note 21)	(11,048)	(10,287)
Long-term debt			$ 2.8	$ 2
Interest rate swap agreements
Carrying and fair values of non-derivative financial instruments
Hedged items	128	(53)
Level II | Carrying Amount
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	(47,931)	(52,914)
Junior subordinated notes (Note 21)	(11,048)	(10,287)
Total liabilities	(58,979)	(63,201)
Level II | Fair Value
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	(48,318)	(52,815)
Junior subordinated notes (Note 21)	(10,824)	(9,217)
Total liabilities	$ (59,142)	$ (62,032)

RISK MANAGEMENT AND FINANCIAL_7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Total Derivatives
Derivative Assets	$ 469	$ 744
Derivative Liabilities	(716)	(521)
Total Derivatives	(247)	223
Total trading activity
Total Derivatives
Derivative Assets	442	686
Derivative Liabilities	(564)	(473)
Total Derivatives	(122)	213
Cash Flow Hedges
Total Derivatives
Derivative Assets	27	12
Derivative Liabilities	(2)	(1)
Total Derivatives	25	11
Net Investment Hedges
Total Derivatives
Derivative Assets	0	10
Derivative Liabilities	(11)	0
Total Derivatives	(11)	10
Fair Value Hedges
Total Derivatives
Derivative Assets	0	36
Derivative Liabilities	(139)	(47)
Total Derivatives	(139)	(11)
Other current assets
Total Derivatives
Derivative Assets	347	589
Other current assets | Total trading activity
Total Derivatives
Derivative Assets	329	570
Other current assets | Cash Flow Hedges
Total Derivatives
Derivative Assets	18	9
Other current assets | Net Investment Hedges
Total Derivatives
Derivative Assets	0	10
Other current assets | Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets | Commodities
Total Derivatives
Derivative Assets	305	508
Other current assets | Commodities | Commodities
Total Derivatives
Derivative Assets	287	499
Other current assets | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Assets	18	9
Other current assets | Commodities | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets | Commodities | Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets | Foreign exchange
Total Derivatives
Derivative Assets	42	81
Other current assets | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Assets	42	71
Other current assets | Foreign exchange | Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets | Foreign exchange | Net Investment Hedges
Total Derivatives
Derivative Assets	0	10
Other current assets | Foreign exchange | Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets
Total Derivatives
Derivative Assets	122	155
Other long-term assets | Total trading activity
Total Derivatives
Derivative Assets	113	116
Other long-term assets | Cash Flow Hedges
Total Derivatives
Derivative Assets	9	3
Other long-term assets | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets | Fair Value Hedges
Total Derivatives
Derivative Assets	0	36
Other long-term assets | Commodities
Total Derivatives
Derivative Assets	113	89
Other long-term assets | Commodities | Commodities
Total Derivatives
Derivative Assets	104	86
Other long-term assets | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Assets	9	3
Other long-term assets | Commodities | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets | Commodities | Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets | Foreign exchange
Total Derivatives
Derivative Assets	9	30
Other long-term assets | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Assets	9	30
Other long-term assets | Foreign exchange | Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets | Foreign exchange | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets | Foreign exchange | Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets | Interest rate
Total Derivatives
Derivative Assets		36
Other long-term assets | Interest rate | Interest rate
Total Derivatives
Derivative Assets		0
Other long-term assets | Interest rate | Cash Flow Hedges
Total Derivatives
Derivative Assets		0
Other long-term assets | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Assets		0
Other long-term assets | Interest rate | Fair Value Hedges
Total Derivatives
Derivative Assets		36
Accounts payable and other
Total Derivatives
Derivative Liabilities	(507)	(415)
Accounts payable and other | Total trading activity
Total Derivatives
Derivative Liabilities	(474)	(396)
Accounts payable and other | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(1)	(1)
Accounts payable and other | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(11)	0
Accounts payable and other | Fair Value Hedges
Total Derivatives
Derivative Liabilities	(21)	(18)
Accounts payable and other | Commodities
Total Derivatives
Derivative Liabilities	(292)	(383)
Accounts payable and other | Commodities | Commodities
Total Derivatives
Derivative Liabilities	(291)	(382)
Accounts payable and other | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(1)	(1)
Accounts payable and other | Commodities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other | Commodities | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other | Foreign exchange
Total Derivatives
Derivative Liabilities	(194)	(14)
Accounts payable and other | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Liabilities	(183)	(14)
Accounts payable and other | Foreign exchange | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other | Foreign exchange | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(11)	0
Accounts payable and other | Foreign exchange | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other | Interest rate
Total Derivatives
Derivative Liabilities	(21)	(18)
Accounts payable and other | Interest rate | Interest rate
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other | Interest rate | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other | Interest rate | Fair Value Hedges
Total Derivatives
Derivative Liabilities	(21)	(18)
Other long-term liabilities
Total Derivatives
Derivative Liabilities	(209)	(106)
Other long-term liabilities | Total trading activity
Total Derivatives
Derivative Liabilities	(90)	(77)
Other long-term liabilities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(1)	0
Other long-term liabilities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Fair Value Hedges
Total Derivatives
Derivative Liabilities	(118)	(29)
Other long-term liabilities | Commodities
Total Derivatives
Derivative Liabilities	(47)	(75)
Other long-term liabilities | Commodities | Commodities
Total Derivatives
Derivative Liabilities	(46)	(75)
Other long-term liabilities | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(1)	0
Other long-term liabilities | Commodities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Commodities | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Foreign exchange
Total Derivatives
Derivative Liabilities	(44)	(2)
Other long-term liabilities | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Liabilities	(44)	(2)
Other long-term liabilities | Foreign exchange | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Foreign exchange | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Foreign exchange | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Interest rate
Total Derivatives
Derivative Liabilities	(118)	(29)
Other long-term liabilities | Interest rate | Interest rate
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Interest rate | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Interest rate | Fair Value Hedges
Total Derivatives
Derivative Liabilities	(118)	(29)
LMCI Restricted Investments
Fair value
Fair value of equity securities	1,070	883
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains (losses)	218	179	$ (223)
Net realized (losses)/ gains	3	(28)	(28)
Other Restricted Investments
Fair value
Fair value of equity securities	64	50
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains (losses)	9	13	(7)
Net realized (losses)/ gains	2	0	$ 0
Fixed income securities | LMCI Restricted Investments
Fair value
Maturing within 1 year	0	0
Maturing within 1-5 years	3	8
Maturing within 5-10 years	1,578	1,340
Fair value of securities	2,651	2,231
Fixed income securities | Other Restricted Investments
Fair value
Maturing within 1 year	33	35
Maturing within 1-5 years	256	241
Maturing within 5-10 years	0	0
Fair value of securities	$ 353	$ 326

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Fair Value Hedging Relationships (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value hedging adjustments, discontinued hedges	$ 41	$ 0
Long-term debt | Carrying Amount
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Long-term debt	(3,935)	(2,630)
Long-term debt | Fair Value
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Adjustments	$ 98	$ 11

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional and Maturity Summary (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($) GWh MWh Bcf	Dec. 31, 2023 USD ($) GWh Bcf	Dec. 31, 2024 MXN ($)	Dec. 31, 2023 MXN ($)
Foreign exchange
Derivative [Line Items]
Notional amount	$ 5,648	$ 4,978	$ 16,750	$ 20,000
Interest rate
Derivative [Line Items]
Notional amount | $	$ 2,800	$ 2,000
Power
Derivative [Line Items]
Notional amount, energy (gwh) | MWh	50
Power | Commodities | Sales
Derivative [Line Items]
Notional amount, energy (gwh) | GWh	10,192	9,209
Natural Gas | Commodities | Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | Bcf	53	50

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses) / Gains on Derivative Instruments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Gain (loss) on cash flow hedge	$ 6	$ 0	$ 0
Commodities
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	(71)	132	(11)
Realized gains (losses) in the year	199	192	46
Commodities | Derivative instruments in hedging relationships
Derivative [Line Items]
Realized gains (losses) in the year	33	(2)	(73)
Foreign exchange
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	(266)	246	(149)
Realized gains (losses) in the year	(152)	155	(2)
Interest rate
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	(71)	0	0
Realized gains (losses) in the year	29	0	0
Interest rate | Derivative instruments in hedging relationships
Derivative [Line Items]
Realized gains (losses) in the year	$ (52)	$ (43)	$ (3)

RISK MANAGEMENT AND FINANCIA_11

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ 46	$ 0	$ (58)
Commodities
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	46	0	(94)
Interest rate
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ 0	$ 0	$ 36

RISK MANAGEMENT AND FINANCIA_12

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Effect of Fair Value and Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) on cash flow hedge	$ 6	$ 0	$ 0
Interest rate contracts | Interest Expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged items	(126)	(98)	(30)
Derivatives designated as hedging instruments	(52)	(43)	(1)
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	(12)	(12)	(16)
Commodity contracts | Revenue
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	$ 32	$ (85)	$ (47)

RISK MANAGEMENT AND FINANCIA_13

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Derivative Instrument Assets
Gross Derivative Instruments	$ 469	$ 744
Amounts Available for Offset	(339)	(439)
Net Amounts	130	305
Derivative Instrument Liabilities
Gross Derivative Instruments	(716)	(521)
Amounts Available for Offset	339	439
Net Amounts	(377)	(82)
Cash collateral provided by the Company	133	57
Letters of credit provided by the Company	59	83
Cash collateral received by the Company (less than)	1	1
Letters of credit received by the Company	75	12
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	10	3
Foreign exchange
Derivative Instrument Assets
Gross Derivative Instruments	51	111
Amounts Available for Offset	(49)	(16)
Net Amounts	2	95
Derivative Instrument Liabilities
Gross Derivative Instruments	(238)	(16)
Amounts Available for Offset	49	16
Net Amounts	(189)	0
Interest rate
Derivative Instrument Assets
Gross Derivative Instruments		36
Amounts Available for Offset		(5)
Net Amounts		31
Derivative Instrument Liabilities
Gross Derivative Instruments	(139)	(47)
Amounts Available for Offset	0	5
Net Amounts	(139)	(42)
Power | Commodities
Derivative Instrument Assets
Gross Derivative Instruments	418	597
Amounts Available for Offset	(290)	(418)
Net Amounts	128	179
Derivative Instrument Liabilities
Gross Derivative Instruments	(339)	(458)
Amounts Available for Offset	290	418
Net Amounts	$ (49)	$ (40)

RISK MANAGEMENT AND FINANCIA_14

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 CAD ($) MWh	Dec. 31, 2023 CAD ($)
Fair Value Hierarchy
Derivative Instrument Assets	$ 469	$ 744
Derivative Instrument Liabilities	(716)	(521)
Fair Value	$ (247)	223
Power
Fair Value Hierarchy
Notional amount, energy (mwh) | MWh	50
Power | Minimum
Fair Value Hierarchy
Notional amount, life (in years)	15 years
Power | Maximum
Fair Value Hierarchy
Notional amount, life (in years)	20 years
Wind Generation
Fair Value Hierarchy
Source allocation percentage	80%
Solar Generation
Fair Value Hierarchy
Source allocation percentage	10%
Market
Fair Value Hierarchy
Source allocation percentage	10%
Recurring basis
Fair Value Hierarchy
Assets and (liabilities), net	$ (247)	223
Recurring basis | Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	10	80
Recurring basis | Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Assets and (liabilities), net	(329)	154
Recurring basis | Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	72	(11)
Commodities | Recurring basis | Power
Fair Value Hierarchy
Derivative Instrument Assets	418	597
Derivative Instrument Liabilities	(339)	(458)
Commodities | Recurring basis | Quoted Prices in Active Markets (Level I) | Power
Fair Value Hierarchy
Derivative Instrument Assets	126	387
Derivative Instrument Liabilities	(116)	(307)
Commodities | Recurring basis | Significant Other Observable Inputs (Level II) | Power
Fair Value Hierarchy
Derivative Instrument Assets	214	200
Derivative Instrument Liabilities	(217)	(130)
Commodities | Recurring basis | Significant Unobservable Inputs (Level III) | Power
Fair Value Hierarchy
Derivative Instrument Assets	78	10
Derivative Instrument Liabilities	(6)	(21)
Foreign exchange | Recurring basis
Fair Value Hierarchy
Derivative Instrument Assets	51	111
Derivative Instrument Liabilities	(238)	(16)
Foreign exchange | Recurring basis | Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Derivative Instrument Liabilities	0	0
Foreign exchange | Recurring basis | Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Derivative Instrument Assets	51	111
Derivative Instrument Liabilities	(238)	(16)
Foreign exchange | Recurring basis | Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Derivative Instrument Liabilities	0	0
Interest rate | Recurring basis
Fair Value Hierarchy
Derivative Instrument Assets		36
Derivative Instrument Liabilities	(139)	(47)
Interest rate | Recurring basis | Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Derivative Instrument Assets		0
Derivative Instrument Liabilities	0	0
Interest rate | Recurring basis | Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Derivative Instrument Assets		36
Derivative Instrument Liabilities	(139)	(47)
Interest rate | Recurring basis | Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Derivative Instrument Assets		0
Derivative Instrument Liabilities	$ 0	$ 0

RISK MANAGEMENT AND FINANCIA_15

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Net change in the Level III fair value category
Fair Value, Liability, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues	Revenues
Unrealized gains (losses) attributed to derivatives in the Level III category	$ 54	$ 2
Commodity contracts | Power
Net change in the Level III fair value category
Balance at beginning of year	(11)	(11)
Net gains (losses) included in Net income (loss)	54	(2)
Transfers to Level II	29	2
Balance at end of year	$ 72	$ (11)

CHANGES IN OPERATING WORKING _3

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
CHANGES IN OPERATING WORKING CAPITAL
(Increase) decrease in Accounts receivable	$ (13)	$ (394)	$ (575)
(Increase) decrease in Inventories	(16)	(56)	(190)
(Increase) decrease in Other current assets	(97)	618	118
Increase (decrease) in Accounts payable and other	365	(206)	(83)
Increase (decrease) in Accrued interest	(40)	245	91
(Increase) Decrease in Operating Working Capital	$ 199	$ 207	$ (639)

STRATEGIC ALLIANCE, ACQUISITI_2

STRATEGIC ALLIANCE, ACQUISITIONS AND DISPOSITIONS (Details) $ in Millions, $ in Millions			1 Months Ended						3 Months Ended		6 Months Ended		12 Months Ended
	Oct. 04, 2023 CAD ($)	Oct. 04, 2023 USD ($)	Aug. 31, 2024 CAD ($)	Aug. 31, 2024 USD ($)	Jun. 30, 2023 CAD ($)	Jun. 30, 2023 USD ($)	Mar. 31, 2023 CAD ($)	Mar. 31, 2023 USD ($)	Jun. 30, 2024 CAD ($)	Jun. 30, 2024 USD ($)	Jun. 30, 2023 CAD ($)	Jun. 30, 2023 USD ($)	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Business Acquisition [Line Items]
Foreign currency translation gains and losses on net investment in foreign operations													$ 1,602		$ (1,141)	$ 1,494
Sale of equity, noncontrolling interest	$ 9,500	$ 6,900
Contributions to equity investments, net of distributions													1,546
Non-Controlling Interests (Note 23)													10,768		9,455
Comprehensive income (loss) attributable to non-controlling interests													1,584		(220)	$ 45
Acquisitions, net of cash acquired (Note 30)											$ 222	$ 167
Transportadora de Gas Natural de la Huasteca | Equity Attributable to Non-Controlling Interests
Business Acquisition [Line Items]
Proceeds from sale of equity									$ 561	$ 411
Reduction to additional paid-in capital									27
Non-Controlling Interests (Note 23)									588
Comprehensive income (loss) attributable to non-controlling interests									$ 21
Columbia Gas and Columbia Gulf
Business Acquisition [Line Items]
Reduction to additional paid-in capital	3,500	3,000
Texas Wind Farms | Common Class A
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired					100%	100%					100%	100%
Texas Wind Farms | Common Class B
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired					100%	100%					100%	100%
Fluvanna Wind Farm
Business Acquisition [Line Items]
Noncontrolling interest acquired							$ 106	$ 80
Blue Cloud Wind Farm
Business Acquisition [Line Items]
Noncontrolling interest acquired					$ 116	$ 87
Portland Natural Gas Transmission System
Business Acquisition [Line Items]
Proceeds from sale of equity			$ 1,600	$ 1,100
Proceeds from sale of interest in partnership unit			743	546
Gain on sale, before tax			572	408
Gain on sale, after tax			456	323
Foreign currency translation gains and losses on net investment in foreign operations			$ 15
Non-Controlling Interests (Note 23)													0		106
Portland Natural Gas Transmission System | Senior notes
Business Acquisition [Line Items]
Proceeds from sale of equity				$ 250
TC Energy
Business Acquisition [Line Items]
Equity interest percentage			61.70%	61.70%
Energir L.P
Business Acquisition [Line Items]
Equity interest percentage			38.30%	38.30%
Columbia Gas and Columbia Gulf
Business Acquisition [Line Items]
Proceeds from sale of equity	$ 5,300	$ 3,900
Equity interest percentage	40%	40%
Consideration received as a reduction to additional paid in capital													24	$ 17
Contributions to equity investments, net of distributions													33	$ 23
Non-Controlling Interests (Note 23)													$ 9,844		$ 9,167

COMMITMENTS, CONTINGENCIES AN_3

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Narrative (Details) $ in Millions, $ in Millions					1 Months Ended	12 Months Ended
	Jun. 14, 2024 CAD ($) claim	Jun. 14, 2024 USD ($) claim	May 15, 2024 CAD ($)	May 15, 2024 USD ($)	Dec. 31, 2024 CAD ($) Megawatt	Dec. 31, 2024 CAD ($) Megawatt	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Other Commitments
Purchase commitment						$ 347		$ 335	$ 314
Capital expenditure commitment					$ 1,100	1,100
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites					8	8		$ 19
Damages sought	$ 84		$ 199
Damages awarded				$ 398
Litigation settlement interest		$ 64		$ 153
Loss contingency, pending claims, number | claim	2	2
TC Energy
Contingencies
Sales process, damage, percentage			50%	50%
Third Party Entity
Contingencies
Sales process, damage, percentage			50%	50%
Coastal GasLink | Coastal GasLink | Letter of credit | Irrevocable Standby Letter of Credit
Contingencies
Vendor standby letter of credit					117	117
Coastal GasLink | Pacific Pipeline Construction Ltd
Contingencies
Damages sought					$ 460
Coastal GasLink | Bonatti S.P.A
Contingencies
Damages sought						1,300
Damages awarded						220
Coastal GasLink LP | Coastal GasLink LP
Contingencies
Damages sought						560
Damages awarded						$ 480
Columbia Pipeline Group shareholders | Columbia Pipelines Group
Contingencies
Damages sought							$ 380
Capital expenditures
Other Commitments
Power purchase agreement, planned capacity (in megawatts) | Megawatt					750	750
Capital expenditures | U.S. Natural Gas Pipelines
Other Commitments
Purchase commitment						$ 400
Capital expenditures | Canadian Natural Gas Pipelines
Other Commitments
Purchase commitment						$ 300

COMMITMENTS, CONTINGENCIES AN_4

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - Contingent financial obligation - CAD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Guarantees
Potential Exposure	$ 240	$ 209
Carrying Value	1	1
Sur de Texas
Guarantees
Potential Exposure	93	97
Carrying Value	0	0
Bruce Power
Guarantees
Potential Exposure	88	88
Carrying Value	0	0
Other jointly-owned entities
Guarantees
Potential Exposure	59	24
Carrying Value	$ 1	$ 1

VARIABLE INTEREST ENTITIES - Na

VARIABLE INTEREST ENTITIES - Narrative (Details)		12 Months Ended
	Oct. 04, 2023	Dec. 31, 2024
Variable Interest Entity [Line Items]
Variable interest entity ownership percentage		100%
Columbia Gas and Columbia Gulf
Variable Interest Entity [Line Items]
Equity interest percentage	40%

VARIABLE INTEREST ENTITIES - As

VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) $ in Millions, $ in Millions	Dec. 31, 2024 CAD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)
Current Assets
Cash and cash equivalents	$ 801		$ 3,678
Accounts receivable	2,611		2,427
Inventories	747		771
Other current assets	1,339		1,419
Current assets of discontinued operations (Note 4)	235		3,077
Total current assets	5,733		11,372
Property, plant and equipment, net	77,501		69,451
Equity Investments	10,636		9,240
Goodwill	13,670	$ 9,490	12,532	$ 9,490
Regulatory Assets (Note 13)	2,682		2,330
Other Long-Term Assets (Note 15)	2,410		2,881
Long-Term Assets of Discontinued Operations (Note 4)	136		12,433
Total assets	118,243		125,034
Current Liabilities
Accounts payable and other	5,297		4,305
Accrued interest	828		913
Current portion of long-term debt	2,955		2,938
Current liabilities of discontinued operations (Note 4)	170		2,682
Total current liabilities	10,511		11,817
Regulatory Liabilities	5,303		4,703
Deferred Income Tax Liabilities	6,884		6,972
Long-Term Liabilities of Discontinued Operations (Note 4)	110		1,280
Total liabilities	79,883		86,026
VIE, Primary Beneficiary
Current Assets
Cash and cash equivalents	311		188
Accounts receivable	839		473
Inventories	205		90
Other current assets	121		49
Current assets of discontinued operations (Note 4)	0		5
Total current assets	1,476		805
Property, plant and equipment, net	49,904		27,477
Equity Investments	865		823
Restricted Investments	950		0
Goodwill	479		439
Regulatory Assets (Note 13)	53		12
Other Long-Term Assets (Note 15)	59		0
Long-Term Assets of Discontinued Operations (Note 4)	0		172
Total assets	53,786		29,728
Current Liabilities
Accounts payable and other	1,866		1,092
Accrued interest	202		210
Current portion of long-term debt	2,062		28
Current liabilities of discontinued operations (Note 4)	0		43
Total current liabilities	4,130		1,373
Regulatory Liabilities	1,232		280
Other Long-Term Liabilities	70		46
Deferred Income Tax Liabilities	7		22
Long-Term Debt	12,387		11,388
Long-Term Liabilities of Discontinued Operations (Note 4)	0		10
Total liabilities	$ 17,826		$ 13,119

VARIABLE INTEREST ENTITIES - Ca

VARIABLE INTEREST ENTITIES - Carrying Value of Non-consolidated VIEs and Maximum Exposure (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 17, 2024
Balance Sheet Exposure
Equity Investments	$ 10,636	$ 9,240
Long-Term Assets of Discontinued Operations (Note 4)	136	12,433
Off-balance sheet
Maximum exposure to loss	10,353	10,103
Payment to reduce company's funding commitment	4,683	4,149	$ 3,433
Subordinated Loan Agreement | Subordinated debt
Off-balance sheet
Funding commitment	228
Bruce Power
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	1,877	1,538
Bruce Power | VIE, not primary beneficiary
Balance Sheet Exposure
Equity Investments	7,043	6,241
Coastal GasLink
Balance Sheet Exposure
Equity Investments	1,006	294
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	265	855
Coastal GasLink | Subordinated Loan Agreement | Subordinated debt | Coastal GasLink
Off-balance sheet
Payment to reduce company's funding commitment	3,137
Line of credit facility, outstanding amount	0	2,520		$ 3,147
Revolving credit facility, borrowing capacity	3,375
Coastal GasLink | Equity Contribution Agreement | Subordinated debt | Coastal GasLink
Off-balance sheet
Revolving credit facility, borrowing capacity	37
Coastal GasLink | VIE, not primary beneficiary
Balance Sheet Exposure
Equity Investments	1,006	294
Pipeline Equity Investments And Other | VIE, not primary beneficiary
Balance Sheet Exposure
Equity Investments	160	166
Long-Term Assets of Discontinued Operations (Note 4)	0	951
Pipeline equity investments
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	2	2
Pipeline equity investments | Discontinued Operations
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	$ 0	$ 56