TC Energy (TRP) 40-F 16 Feb 24 2023 FY Annual report (Canada) Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2023 shares
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
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	1,037,487,829
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	2023
Document Fiscal Period Focus	FY
TRANSCANADA PIPELINES LIMITED
Entity Information [Line Items]
Current Fiscal Year End Date	--12-31
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	2023
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, 2023
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues	$ 15,934	$ 14,977	$ 13,387
Income (Loss) from Equity Investments (Note 12)	1,377	1,054	898
Impairment of equity investment (Notes 8 and 12)	(2,100)	(3,048)	0
Operating and Other Expenses
Plant operating costs and other	4,887	4,932	4,098
Commodity purchases resold	517	534	87
Property taxes	897	848	774
Depreciation and amortization	2,778	2,584	2,522
Goodwill and asset impairment charges and other (Notes 7 and 15)	(4)	453	2,775
Total operating and other expenses	9,075	9,351	10,256
Net Gain (Loss) on Sale of Assets	0	0	30
Financial Charges
Interest expense (Note 21)	3,263	2,588	2,360
Allowance for funds used during construction	(575)	(369)	(267)
Foreign exchange losses on loan receivable from affiliate (Note 13)	(320)	185	(10)
Interest income and other	(242)	(146)	(190)
Total financial charges	2,126	2,258	1,893
Income (Loss) before Income Taxes	4,010	1,374	2,166
Income Tax Expense (Recovery) (Note 20)
Current	931	415	305
Deferred	11	174	(185)
Income Tax Expense	942	589	120
Net Income (Loss)	3,068	785	2,046
Net income (loss) attributable to non-controlling interests (Note 24)	146	37	91
Net Income (Loss) Attributable to Controlling Interests	2,922	748	1,955
Preferred share dividends	93	107	140
Net Income (Loss) Attributable to Common Shares	$ 2,829	$ 641	$ 1,815
Net Income (Loss) per Common Share (Note 25)
Basic (in dollars per share)	$ 2.75	$ 0.64	$ 1.87
Diluted (in dollars per share)	2.75	0.64	1.86
Dividends Declared per Common Share (in dollars per share)	$ 3.72	$ 3.60	$ 3.48
Weighted Average Number of Common Shares (millions) (Note 25)
Basic (in shares)	1,030	995	973
Diluted (in shares)	1,030	996	974
Canadian Natural Gas Pipelines
Revenues	$ 5,173	$ 4,764	$ 4,519
U.S. Natural Gas Pipelines
Revenues	6,229	5,933	5,233
Mexico Natural Gas Pipelines
Revenues	846	688	605
Liquids Pipelines
Revenues	2,667	2,668	2,306
Power and Energy Solutions
Revenues	$ 1,019	$ 924	$ 724

Consolidated statement of compr

Consolidated statement of comprehensive income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 3,068	$ 785	$ 2,046
Other Comprehensive Income (Loss), Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations	(1,141)	1,494	(108)
Change in fair value of net investment hedges	17	(36)	(2)
Change in fair value of cash flow hedges	0	(39)	(10)
Reclassification to net income of (gains) losses on cash flow hedges	74	42	55
Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans	(11)	63	158
Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans	0	6	14
Other comprehensive income (loss) on equity investments	(211)	867	535
Other comprehensive income (loss) (Note 27)	(1,272)	2,397	642
Comprehensive Income (Loss)	1,796	3,182	2,688
Comprehensive income (loss) attributable to non-controlling interests	(220)	45	81
Comprehensive Income (Loss) Attributable to Controlling Interests	2,016	3,137	2,607
Preferred share dividends	93	107	140
Comprehensive Income (Loss) Attributable to Common Shares	$ 1,923	$ 3,030	$ 2,467

Consolidated statement of cash

Consolidated statement of cash flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash Generated from Operations
Net income (loss)	$ 3,068	$ 785	$ 2,046
Depreciation and amortization	2,778	2,584	2,522
Goodwill and asset impairment charges and other (Notes 7 and 15)	(4)	453	2,775
Deferred income taxes (Note 20)	11	174	(185)
(Income) loss from equity investments (Note 12)	(1,377)	(1,054)	(898)
Impairment of equity investment (Notes 8 and 12)	2,100	3,048	0
Distributions received from operating activities of equity investments (Note 12)	1,254	1,025	975
Employee post-retirement benefits funding, net of expense (Note 28)	(17)	(29)	(5)
Net (gain) loss on sale of assets	0	0	(30)
Equity allowance for funds used during construction	(367)	(248)	(191)
Unrealized (gains) losses on financial instruments (Note 29)	(342)	135	194
Expected credit loss provision (Note 29)	(83)	163	0
Foreign exchange losses on loan receivable from affiliate (Note 13)	0	28	41
Other	40	(50)	(67)
(Increase) decrease in operating working capital (Note 30)	207	(639)	(287)
Net cash provided by operations	7,268	6,375	6,890
Investing Activities
Capital expenditures (Note 5)	(8,007)	(6,678)	(5,924)
Capital projects in development (Note 5)	(142)	(49)	0
Contributions to equity investments (Notes 5, 8 and 12)	(4,149)	(3,433)	(1,210)
Acquisitions, net of cash acquired (Note 31)	(307)	0	0
Loans to affiliate (issued) repaid, net (Notes 8 and 13)	250	(11)	(239)
Keystone XL contractual recoveries (Note 7)	10	571	0
Proceeds from sales of assets, net of transaction costs	33	0	35
Other distributions from equity investments (Note 12)	23	2,632	73
Deferred amounts and other	2	(41)	(447)
Net cash (used in) provided by investing activities	(12,287)	(7,009)	(7,712)
Financing Activities
Notes payable issued (repaid), net	(6,299)	766	1,003
Long-term debt issued, net of issue costs	15,884	2,508	10,730
Long-term debt repaid	(3,772)	(1,338)	(7,758)
Disposition of equity interest, net of transaction costs (Notes 24 and 31)	5,328	0	0
Junior subordinated notes issued, net of issue costs	0	1,008	495
Redeemable non-controlling interest repurchased (Note 7)	0	0	(633)
Dividends on common shares	(2,787)	(3,192)	(3,317)
Dividends on preferred shares	(92)	(106)	(141)
Distributions to non-controlling interests	(124)	(44)	(74)
Distributions on Class C Interests (Note 7)	(49)	(43)	(16)
Common shares issued, net of issue costs	4	1,905	148
Preferred shares redeemed (Note 26)	0	(1,000)	(500)
Gains (losses) on settlement of financial instruments	0	23	(10)
Acquisition of TC PipeLines, LP transaction costs (Note 24)	0	0	(15)
Net cash (used in) provided by financing activities	8,093	487	(88)
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(16)	94	53
Increase (Decrease) in Cash and Cash Equivalents	3,058	(53)	(857)
Cash and Cash Equivalents, Beginning of year	620	673	1,530
Cash and Cash Equivalents, End of year	$ 3,678	$ 620	$ 673

Consolidated balance sheet

Consolidated balance sheet $ in Millions, $ in Millions	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Current Assets
Cash and cash equivalents	$ 3,678	$ 620
Accounts receivable	4,209	3,624
Inventories	982	936
Other current assets (Note 9)	2,503	2,152
Total current assets	11,372	7,332
Plant, Property and Equipment (Note 10)	80,569	75,940
Net Investment in Leases (Note 11)	2,263	1,895
Equity investments	10,314	9,535
Restricted Investments	2,636	2,108
Regulatory Assets (Note 14)	2,330	1,910
Goodwill (Note 15)	12,532	12,843
Other Long-Term Assets (Note 16)	3,018	2,785
Total assets	125,034	114,348
Current Liabilities
Notes payable (Note 17)	0	6,262
Accounts payable and other (Note 18)	6,987	7,149
Dividends payable	979	930
Accrued interest	913	668
Current portion of long-term debt (Note 21)	2,938	1,898
Total current liabilities	11,817	16,907
Regulatory Liabilities (Note 14)	4,806	4,520
Other Long-Term Liabilities (Note 19)	1,015	1,017
Deferred Income Tax Liabilities (Note 20)	8,125	7,648
Long-Term Debt (Note 21)	49,976	39,645
Junior Subordinated Notes (Note 22)	10,287	10,495
Total liabilities	86,026	80,232
EQUITY
Common shares, no par value (Note 25)	30,002	28,995
Preferred shares (Note 26)	2,499	2,499
Additional paid-in capital	0	722
Retained earnings (Accumulated deficit)	(2,997)	819
Accumulated other comprehensive income (loss) (Note 27)	49	955
Controlling Interests	29,553	33,990
Non-controlling interests (Note 24)	9,455	126
Total Equity	39,008	34,116
Total Liabilities and Equity	$ 125,034	$ 114,348

Consolidated balance sheet (Par

Consolidated balance sheet (Parenthetical) - shares shares in Millions	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common shares issued (in shares)	1,037	1,018
Common shares outstanding (in shares)	1,037	1,018

Consolidated statement of equit

Consolidated statement of equity - CAD ($) $ in Thousands	Total	Equity Attributable to Controlling Interests	Common shares	Preferred Shares (Note 26)	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, 2020			$ 24,488,000	$ 3,980,000	$ 2,000	$ 5,367,000	$ (2,439,000)	$ 1,682,000
Shares issued:
Exercise of stock options			165,000
Acquisition of TC PipeLines, LP, net of transaction costs (Note 24)	$ 2,063,000		2,063,000		(398,000)		353,000	(1,563,000)
Issuance of stock options, net of exercises					(6,000)
Keystone XL project-level credit facility retirement and issuance of Class C Interests (Note 7)	737,000				737,000
Repurchase of redeemable non-controlling interest (Note 7)					394,000
Net income (loss) attributable to controlling interests	1,955,000					1,955,000
Common share dividends						(3,409,000)
Preferred share dividends						(133,000)
Redemption of shares				(493,000)		(7,000)
Other comprehensive income (loss) attributable to controlling interests	642,000						652,000
Net income (loss) attributable to non-controlling interests	(91,000)							90,000
Other comprehensive income (loss) attributable to non-controlling interests								(10,000)
Distributions declared to non-controlling interests								(74,000)
Balance at end of year at Dec. 31, 2021	33,396,000	$ 33,271,000	26,716,000	3,487,000	729,000	3,773,000	(1,434,000)	125,000
Shares issued:
Dividend reinvestment and share purchase plan			342,000
Exercise of stock options			183,000
Under public offering, net of issue costs			1,754,000
Issuance of stock options, net of exercises					(7,000)
Net income (loss) attributable to controlling interests	748,000					748,000
Common share dividends						(3,595,000)
Preferred share dividends						(95,000)
Redemption of shares				(988,000)		(12,000)
Other comprehensive income (loss) attributable to controlling interests	2,397,000						2,389,000
Net income (loss) attributable to non-controlling interests	(37,000)							37,000
Other comprehensive income (loss) attributable to non-controlling interests								8,000
Distributions declared to non-controlling interests								(44,000)
Balance at end of year at Dec. 31, 2022	34,116,000	33,990,000	28,995,000	2,499,000	722,000	819,000	955,000	126,000
Shares issued:
Dividend reinvestment and share purchase plan			1,003,000
Exercise of stock options			4,000
Issuance of stock options, net of exercises					9,000
Disposition/impact of equity interest, net of transaction costs					(3,537,000)			9,451,000
Reclassification of additional paid-in capital deficit to retained earnings (accumulated deficit)					2,806,000	(2,806,000)
Net income (loss) attributable to controlling interests	2,922,000					2,922,000
Common share dividends						(3,839,000)
Preferred share dividends						(93,000)
Other comprehensive income (loss) attributable to controlling interests	(1,272,000)						(379,000)
Impact of non-controlling interest (Note 24)							(527,000)
Non-controlling interests on acquisition of Texas Wind Farms (Note 24)								222,000
Net income (loss) attributable to non-controlling interests	(146,000)							146,000
Other comprehensive income (loss) attributable to non-controlling interests								(366,000)
Distributions declared to non-controlling interests								(124,000)
Balance at end of year at Dec. 31, 2023	$ 39,008,000	$ 29,553,000	$ 30,002,000	$ 2,499,000	$ 0	$ (2,997,000)	$ 49,000	$ 9,455,000

DESCRIPTION OF TC ENERGY'S BUSI

DESCRIPTION OF TC ENERGY'S BUSINESS	12 Months Ended
	Dec. 31, 2023
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 five business segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Power and Energy Solutions. These segments offer different products and services, including certain natural gas, crude oil 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 40,596 km (25,226 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 50,088 km (31,123 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 2,895 km (1,798 miles) of regulated natural gas pipelines currently in operation. Liquids Pipelines The Liquids Pipelines segment primarily consists of the Company's investments in 4,865 km (3,024 miles) of crude oil pipeline systems currently in operation which connect Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas. Power and Energy Solutions The Power and Energy Solutions segment primarily consists of the Company's investments in approximately 4,600 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.

ACCOUNTING POLICIES

ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2023
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. 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 the estimate or judgment is made or are subjective. These estimates and judgments include, but are not limited to: • fair value of TC Energy’s equity investment in Coastal GasLink LP (Note 8) • assessment of goodwill impairment indicators and fair value of reporting units that contain goodwill (Note 15) • estimates and judgments used in measuring the fair value of Columbia Gas Transmission, LLC (Columbia Gas) and Columbia Gulf Transmission, LLC (Columbia Gulf) (Note 15). 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: • valuation of Keystone XL assets and Class C Interests (Note 7) • recoverability and depreciation rates of plant, property and equipment (Note 10) • allocation of consideration to lease and non-lease components in a contract that contains a lease (Note 11) • assumptions used to measure the carrying amount of and expected credit losses on net investment in leases and certain contract assets (Notes 11 and 29) • fair value of equity investments not otherwise noted above (Note 12) • carrying value of regulatory assets and liabilities (Note 14) • assumptions used to measure the environmental remediation liability from the Keystone pipeline rupture (Note 18) • recognition of asset retirement obligations (Note 19) • 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 20) • assumptions used to measure retirement and other post-retirement benefit obligations (Note 28) • fair value of financial instruments (Note 29) • fair value of Fluvanna Wind Farm and Blue Cloud Wind Farm (Texas Wind Farms) assets (Note 31) • commitments and provisions for contingencies and guarantees (Note 32). TC Energy continues to assess the impact of climate change 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 and liquids 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 liquids pipelines as well as 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. RRA is not applicable to the Company's liquids pipelines as the regulators' decisions regarding operations and tolls on those systems generally do not have an impact on timing of recognition of revenues and expenses. 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 and liquids 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 crude oil, 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 The Company is contracted to provide pipeline construction services to a partially-owned entity for a development fee. The development fee is considered variable consideration due to refund provisions in the contract. The Company recognizes its estimate of the most likely amount of the variable consideration to which it will be entitled. The development fee is recognized over time as the services are 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. 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 certain leased pipelines. Revenues earned from these services are recognized ratably over the term of the contract. Liquids Pipelines Capacity Arrangements and Transportation Revenues from the Company's liquids pipelines are generated mainly from providing customers with firm capacity arrangements to transport crude oil. The performance obligation in these contracts is the reservation of a specified amount of capacity together with the transportation of crude oil on a monthly basis. Revenues earned from these arrangements are recognized ratably over the term of the contract regardless of the amount of crude oil that is transported. Revenues for interruptible or volumetric-based services are recognized when the service is performed. Liquids pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the crude oil that it transports for customers. 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 crude oil in transit, 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. Liquids Pipelines Plant, property and equipment for liquids pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent and other plant and equipment are depreciated at various rates reflecting their estimated useful lives. The cost of these assets includes interest capitalized during construction. When liquids pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. 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 and liquids tank terminals 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 t

ACCOUNTING CHANGES

ACCOUNTING CHANGES	12 Months Ended
	Dec. 31, 2023
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES 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 the annual period 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 does not expect this guidance to have a material impact on the Company's consolidated financial statements. Segment Reporting In November 2023, the 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 is effective for annual periods beginning January 1, 2024 and interim periods beginning January 1, 2025. Early adoption is permitted and the guidance is applied retrospectively. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Leases In March 2023, the FASB issued new guidance that clarified the accounting for leasehold improvements associated with common control leases. The guidance requires all lessees to amortize leasehold improvements associated with common control leases over their useful life to the common control group and account for them as a transfer of assets between entities under common control at the end of the lease. Additional disclosures are required when the useful life of leasehold improvements to the common control group exceeds the related lease term. This new guidance is effective January 1, 2024 and can be applied either prospectively or retrospectively, with early application permitted. The Company will adopt the guidance on a prospective basis starting January 1, 2024, and it is not expected to have a material impact on the Company's consolidated financial statements.

SPINOFF OF LIQUIDS PIPELINES BU

SPINOFF OF LIQUIDS PIPELINES BUSINESS	12 Months Ended
	Dec. 31, 2023
Spin off Transactions [Abstract]
SPINOFF OF LIQUIDS PIPELINES BUSINESS	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 proposed spinoff of its Liquids Pipelines business (the spinoff Transaction) and on November 8, 2023 the Company communicated that the name of the new Liquids Pipelines business would be South Bow Corporation (South Bow). In addition to TC Energy shareholder and court approvals, the spinoff Transaction is subject to receipt of favourable tax rulings from Canadian and U.S. tax authorities, receipt of necessary regulatory approvals, and satisfaction of other customary closing conditions. TC Energy expects that the spinoff Transaction will be completed in the second half of 2024. Under the spinoff Transaction, TC Energy shareholders will retain their current ownership in TC Energy’s common shares and receive a pro-rata allocation of common shares in South Bow. The determination of the number of common shares in South Bow to be distributed to TC Energy shareholders will be determined prior to the closing of the spinoff Transaction. The spinoff Transaction is expected to be tax free to TC Energy’s Canadian and U.S. shareholders. For the year ended December 31, 2023, the Company incurred pre-tax Liquids Pipelines business separation costs of $40 million ($34 million after tax) with respect to the spinoff Transaction, which included internal costs related to separation activities, legal, tax, audit and other consulting fees recorded in Plant operating costs and other in the Consolidated statement of income.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION year ended December 31, 2023 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 5,173 6,229 846 2,667 1,019 — 15,934 Intersegment revenues — 101 — — 22 (123) 2 — 5,173 6,330 846 2,667 1,041 (123) 15,934 Income (loss) from equity investments 220 324 78 67 688 — 1,377 Impairment of equity investment (2,100) — — — — — (2,100) Plant operating costs and other (1,756) (1,660) (39) (836) (603) 7 2 (4,887) Commodity purchases resold — (56) — (437) (24) — (517) Property taxes (302) (473) — (116) (6) — (897) Depreciation and amortization (1,325) (934) (89) (338) (92) — (2,778) Goodwill and asset impairment charges and other — — — 4 — — 4 Segmented Earnings (Losses) (90) 3,531 796 1,011 1,004 (116) 6,136 Interest expense (3,263) Allowance for funds used during construction 575 Foreign exchange gains (losses), net 320 Interest income and other 242 Income (Loss) before Income Taxes 4,010 Income tax (expense) recovery (942) 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 3 Capital expenditures 2,953 2,536 2,292 49 144 33 8,007 Capital projects in development — — — — 142 — 142 Contributions to equity investments 3,231 124 — — 794 — 4,149 6,184 2,660 2,292 49 1,080 33 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 Plant operating costs and other 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 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 Liquids Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 4,764 5,933 688 2,668 924 — 14,977 Intersegment revenues — 132 — — 12 (144) 2 — 4,764 6,065 688 2,668 936 (144) 14,977 Income (loss) from equity investments 18 292 122 55 539 28 3 1,054 Impairment of Equity Investment (3,048) — — — — — (3,048) Plant operating costs and other (1,679) (1,856) (221) (756) (544) 124 2 (4,932) Commodity purchases resold — — — (512) (22) — (534) Property taxes (297) (426) — (121) (4) — (848) Depreciation and amortization (1,198) (887) (98) (329) (72) — (2,584) Goodwill and asset impairment charges and other — (571) — 118 — — (453) Segmented Earnings (Losses) (1,440) 2,617 491 1,123 833 8 3,632 Interest expense (2,588) Allowance for funds used during construction 369 Foreign exchange gains (losses), net 3 (185) Interest income and other 146 Income (Loss) before Income Taxes 1,374 Income tax (expense) recovery (589) 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 4 Capital expenditures 3,274 2,137 1,027 106 93 41 6,678 Capital projects in development — — — — 49 — 49 Contributions to equity investments 5 1,445 — — 37 752 — 2,234 4,719 2,137 1,027 143 894 41 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 Plant operating costs and other 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 13, Loans receivable from affiliates, for additional information. 4 Included in Investing activities in the Consolidated statement of cash flows. 5 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 13, Loans receivable from affiliates, for additional information. year ended December 31, 2021 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 4,519 5,233 605 2,306 724 — 13,387 Intersegment revenues — 145 — — 14 (159) 2 — 4,519 5,378 605 2,306 738 (159) 13,387 Income (loss) from equity investments 12 244 119 71 411 41 3 898 Plant operating costs and other (1,567) (1,393) (55) (700) (455) 72 2 (4,098) Commodity purchases resold — — (3) (84) — — (87) Property taxes (289) (367) — (113) (5) — (774) Depreciation and amortization (1,226) (791) (109) (318) (78) — (2,522) Goodwill and asset impairment charges and other — — — (2,775) — — (2,775) Net gain (loss) on sale of assets — — — 13 17 — 30 Segmented Earnings (Losses) 1,449 3,071 557 (1,600) 628 (46) 4,059 Interest expense (2,360) Allowance for funds used during construction 267 Foreign exchange gains (losses), net 3 10 Interest income and other 190 Income (Loss) before Income Taxes 2,166 Income tax (expense) recovery (120) Net Income (Loss) 2,046 Net (income) loss attributable to non-controlling interests (91) Net Income (Loss) Attributable to Controlling Interests 1,955 Preferred share dividends (140) Net Income (Loss) Attributable to Common Shares 1,815 Capital Spending 4 Capital expenditures 2,629 2,611 129 488 32 35 5,924 Contributions to equity investments 108 209 — 83 810 — 1,210 2,737 2,820 129 571 842 35 7,134 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 Plant operating costs and other 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. Refer to Note 13, Loans receivable from affiliates, for additional information. 4 Included in Investing activities in the Consolidated statement of cash flows. at December 31 2023 2022 (millions of Canadian $) Total Assets by Segment Canadian Natural Gas Pipelines 29,782 27,456 U.S. Natural Gas Pipelines 50,499 50,038 Mexico Natural Gas Pipelines 12,003 9,231 Liquids Pipelines 15,490 15,587 Power and Energy Solutions 9,525 8,272 Corporate 7,735 3,764 125,034 114,348 Geographic Information year ended December 31 2023 2022 2021 (millions of Canadian $) Revenues Canada – domestic 5,360 4,942 4,603 Canada – export 1,403 1,322 1,226 United States 8,325 8,025 6,953 Mexico 846 688 605 15,934 14,977 13,387 at December 31 2023 2022 (millions of Canadian $) Plant, Property and Equipment Canada 28,583 27,232 United States 44,609 43,505 Mexico 7,377 5,203 80,569 75,940

REVENUES

REVENUES	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
REVENUES	REVENUES Disaggregation of Revenues year ended December 31, 2023 Canadian U.S. Mexico Liquids Pipelines Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 5,141 5,107 442 2,115 — 12,805 Power generation — — — — 427 427 Natural gas storage and other 1,2 32 874 125 3 363 1,397 5,173 5,981 567 2,118 790 14,629 Sales-type lease income 3 — — 279 — — 279 Other revenues 4 — 248 — 549 229 1,026 5,173 6,229 846 2,667 1,019 15,934 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 11, Leases, for additional information. 3 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 11, Leases, for additional information. 4 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 11, Leases, and Note 29, Risk management and financial instruments, for additional information. year ended December 31, 2022 Canadian U.S. Mexico Liquids Pipelines Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,696 4,621 507 1,983 — 11,807 Power generation — — — — 490 490 Natural gas storage and other 1,2 68 1,298 54 4 391 1,815 4,764 5,919 561 1,987 881 14,112 Sales-type lease income 3 — — 127 — — 127 Other revenues 4,5 — 14 — 681 43 738 4,764 5,933 688 2,668 924 14,977 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 11, Leases, for additional information. 3 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 11, Leases, for additional information. 4 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 11, Leases, and Note 29, Risk management and financial instruments, for additional information. 5 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 14, Rate-regulated businesses, for additional information. year ended December 31, 2021 Canadian U.S. Mexico Liquids Pipelines Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,432 4,139 576 2,025 — 11,172 Power generation — — — — 324 324 Natural gas storage and other 1 87 1,057 29 5 278 1,456 4,519 5,196 605 2,030 602 12,952 Other revenues 2,3 — 37 — 276 122 435 4,519 5,233 605 2,306 724 13,387 1 Includes $87 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 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 11, Leases, and Note 29, Risk management and financial instruments, for additional information. 3 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 14, Rate-regulated businesses, for additional information. Contract Balances at December 31 2023 2022 Affected line item on the (millions of Canadian $) Receivables from contracts with customers 1,832 1,907 Accounts receivable Contract assets (Note 9) 151 155 Other current assets Long-term contract assets (Note 16) 457 355 Other long-term assets Contract liabilities 1 (Note 18) 69 62 Accounts payable and other Long-term contract liabilities 1 (Note 19) 12 32 Other long-term liabilities 1 During the year ended December 31, 2023, $64 million (2022 – $51 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 TGNH pipelines 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, 2023, future revenues from long-term pipeline capacity arrangements and transportation as well as natural gas storage and other contracts extending through 2055 are approximately $22.9 billion, of which approximately $4.9 billion is expected to be recognized in 2024. A significant portion of the Company's revenues are considered constrained and therefore not included in the future revenue amounts above as the Company uses the following practical expedients: • right to invoice practical expedient – applied to all U.S. and certain Mexico rate-regulated natural gas pipeline capacity arrangements and flow-through revenues • variable consideration practical expedient – applied to the following variable revenues: ◦ interruptible transportation service revenues as volumes cannot be estimated ◦ liquids pipelines capacity revenues based on volumes transported ◦ power generation revenues related to market prices that are subject to factors outside the Company's influence • contracts for a duration of one year or less. In addition, future revenues from the Company's Canadian natural gas pipelines' regulated firm capacity contracts include fixed revenues only for the time periods that approved tolls under current rate settlements are in effect and certain. Future revenues exclude lease income from the Company's Mexico natural gas pipelines on projects that have not been placed into service.

KEYSTONE XL

KEYSTONE XL	12 Months Ended
	Dec. 31, 2023
Investments, All Other Investments [Abstract]
KEYSTONE XL	KEYSTONE XL Asset Impairment Charge and Other Following the revocation of the Presidential Permit for the Keystone XL pipeline project on January 20, 2021, the Company terminated the Keystone XL pipeline project and evaluated the Keystone XL investment for impairment in 2021. As a result, the Company determined that the carrying amount of these assets within the Liquids Pipelines segment was no longer fully recoverable and recognized an asset impairment charge, net of expected contractual recoveries and other contractual and legal obligations related to termination activities, of $2,775 million ($2,134 million after tax) for the year ended December 31, 2021. The asset impairment charge was based on the excess of the carrying value of $3,301 million over the estimated fair value of $175 million. year ended December 31, 2021 Estimated Fair Value Asset impairment charge and other (millions of Canadian $) Pre tax After tax Asset impairment charge Plant and equipment 175 412 312 Related capital projects in development — 230 175 Other capitalized costs — 2,158 1,642 Capitalized interest — 326 248 175 3,126 2,377 Other Contractual recoveries n/a (693) (525) Contractual and legal obligations related to termination activities n/a 342 282 175 2,775 2,134 The estimated fair value of $175 million at December 31, 2021 related to plant and equipment was based on the price that was expected to be received from selling these assets in their current condition and is updated as required. The initial key assumptions used in the determination of selling price included an estimated two-year disposal period and current energy market demand. The valuation considered a variety of potential selling prices based on various markets that could be used to dispose of these assets and required the use of unobservable inputs. As a result, the fair value is classified in Level III of the fair value hierarchy. In 2023, the Company received $10 million (2022 – $571 million) towards its contractual recoveries, resulting in a remaining balance of $117 million at December 31, 2023 (December 31, 2022 – $130 million). In 2022, the Company revised its estimate of contractual and legal obligations related to termination activities based on a review of costs and commitments incurred, which resulted in a $54 million reduction to the asset impairment charge. No revision to the estimate was made in 2023. The Company paid $2 million in 2023 (2022 – $24 million; 2021 – $192 million) towards contractual and legal obligations related to termination activities. At December 31, 2023, the remaining balance accrued was $45 million (December 31, 2022 – $48 million). In 2023, the Company sold plant and equipment with a carrying value of approximately $63 million (2022 – $25 million; 2021 – $16 million), resulting in a gain of $36 million (2022 – $64 million; 2021 – nil) recorded in Goodwill and asset impairment charges and other in the Consolidated statement of income. As part of the Keystone XL impairment charge and other, the Company recorded a $14 million income tax recovery in 2023 (2022 – $96 million expense) in relation to the termination of the Keystone XL pipeline project. Redeemable Non-Controlling Interest and Long-Term Debt In March 2020, the Company announced that it would proceed with construction of the Keystone XL pipeline. As part of the funding plan, the Government of Alberta invested $1,033 million in the form of Class A Interests in the year ended December 31, 2020. On January 4, 2021, the Company put in place a US$4.1 billion project-level credit facility to support construction of the Keystone XL pipeline, that was fully guaranteed by the Government of Alberta and non-recourse to the Company. On January 8, 2021, the Company exercised its call right with the Government of Alberta in accordance with contractual terms and paid $633 million (US$497 million) to repurchase the Government of Alberta Class A Interests in certain Keystone XL subsidiaries. This transaction was funded by draws on the project-level credit facility. For the year ended December 31, 2021, the Company made draws under the Keystone XL project-level credit facility totaling $1,028 million (US$849 million). Following the cancellation of the Keystone XL pipeline project, the Government of Alberta repaid the full outstanding balance in June 2021 in accordance with the terms of the guarantee, and the credit facility was subsequently terminated. Additionally, in June 2021, the Company repurchased the remaining Government of Alberta Class A Interests for a nominal amount, which was accounted for as an equity transaction and resulted in $394 million recognized in Additional paid-in capital. As part of this arrangement, TC Energy issued $91 million of Class C Interests in the Keystone XL subsidiaries which entitled the Government of Alberta to future liquidation proceeds from specified Keystone XL project assets. The entire $91 million was recorded (net of distributions) in Accounts payable and other on the Consolidated balance sheet. During 2023, it was determined that the Company would exceed the $91 million of Class C distributions and the Company increased the Class C Interests carrying value by $32 million with a corresponding amount recorded in Goodwill and asset impairment charges and other in the Consolidated statement of income. Termination of the project-level credit facility, net of the issuance of Class C Interests, resulted in $937 million ($737 million after tax) recorded to Additional paid-in capital in 2021. For the year ended December 31, 2023, the Company made Class C distributions to the Government of Alberta of $49 million (2022 – $43 million; 2021 – $16 million).

COASTAL GASLINK

COASTAL GASLINK	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
COASTAL GASLINK	COASTAL GASLINK Impairment of Equity Investment in Coastal GasLink LP In July 2022, amended agreements were executed between Coastal GasLink LP, LNG Canada, TC Energy and its Coastal GasLink LP partners (collectively, the July 2022 agreements). These amendments revised the commercial terms between LNG Canada and Coastal GasLink LP, as well as funding provisions between the partners of Coastal GasLink LP. With the expectation that additional equity contributions under a subordinated loan agreement between TC Energy and the Coastal GasLink LP partners will be predominantly funded by TC Energy as limited partner of Coastal GasLink LP, in accordance with the July 2022 agreements, the Company completed valuation assessments during the first three quarters of 2023 and concluded that, for each period an assessment was performed, the fair value of its investment in Coastal GasLink LP was below its carrying value and that these were other-than-temporary impairments. As a result, a pre-tax impairment charge of $2,100 million ($1,943 million after tax) was recognized during the year ended December 31, 2023 in Impairment of equity investment in the Consolidated statement of income in the Canadian Natural Gas Pipelines segment (2022 – $3,048 million; $2,643 million after tax). The carrying value of the investment in Coastal GasLink LP was $294 million at December 31, 2023 (2022 – nil), which reflects the balance of amounts, net of impairments, drawn on the subordinated loan to date at December 31, 2023 and other changes to TC Energy's equity investment. The impairment charge reflected the net impact of $2,020 million drawn on and a $250 million repayment of the subordinated loan for the nine months ended September 30, 2023, along with TC Energy’s proportionate share of unrealized gains and losses on interest rate derivatives in Coastal GasLink LP and other changes to the equity investment. The cumulative pre-tax impairment charge recognized at December 31, 2023 is $5,148 million ($4,586 million after tax). A deferred income tax recovery was recognized on the pre-tax impairment charge, net of certain unrealized tax losses not recognized. The impairment of the subordinated loan resulted in unrealized non-taxable capital losses that are not recognized. Refer to Note 20, Income taxes, for additional information. At December 31, 2023, TC Energy expects to fund an additional $0.9 billion related to the capital cost estimates to complete the Coastal GasLink pipeline, which is consistent with the capital cost profile that was included in the September 30, 2023 impairment calculation. At December 31, 2023, there were no events or changes in circumstances since September 30, 2023 indicating a significant adverse impact on the estimated fair value of the Company’s investment in Coastal GasLink LP. The fair value of TC Energy’s investment in Coastal GasLink LP at September 30, 2023 and December 31, 2022 was estimated using a 40-year discounted cash flow model and is classified as a Level III fair value measurement. The discounted cash flow is most sensitive to assumptions related to the capital cost estimates for the Coastal GasLink pipeline of approximately $14.5 billion (2022 – $14.5 billion), discount rate and long-term financing plans. Other assumptions included in the discounted cash flow model include contractually agreed upon terms and extension provisions in the TSAs between Coastal GasLink LP and the LNG Canada participants, potential expansion projects and estimated completion date. Subordinated Loan Agreement In 2021, TC Energy entered into a subordinated loan agreement with Coastal GasLink LP. This loan agreement was amended as part of the July 2022 agreements, and subsequent draws on this loan by Coastal GasLink LP will be provided through an interest-bearing loan, subject to a floating market-based interest rate to fund the capital cost to complete the Coastal GasLink pipeline. Committed capacity under the subordinated loan agreement between TC Energy and Coastal GasLink LP was $3.4 billion, with $2.5 billion drawn on the loan at December 31, 2023. Any amounts outstanding on the loan will be repaid by Coastal GasLink LP to TC Energy once final project costs are known, which will be determined after the pipeline is placed into service. Coastal GasLink LP partners, including TC Energy, will contribute equity to Coastal GasLink LP to ultimately fund Coastal GasLink LP’s repayment of this subordinated loan to TC Energy. The Company expects that these additional equity contributions will be predominantly funded by TC Energy. Amounts drawn on this loan subsequent to amended agreements executed in July 2022 are accounted for as in-substance equity contributions and are presented as Contributions to equity investments on the Company’s Consolidated statement of cash flows. Interest and principal repayments on this loan, which are expected to be predominantly funded by TC Energy, will be accounted for as an equity investment distribution to the Company once received. The table below reflects the changes in this loan receivable balance. at December 31 (millions of Canadian $) 2023 2022 Outstanding balance at beginning of year 250 238 Issuances 2,520 112 Repayments (250) (100) Outstanding balance at end of year 2,520 250 Impairment during the year (2,020) (250) Carrying value at end of year 500 — (millions of Canadian $) Ownership Interest at December 31, 2023 Income (Loss) from Equity Investments Equity year ended December 31 at December 31 2023 2022 2021 2023 2022 Canadian Natural Gas Pipelines TQM 1 50.0 % 17 17 12 166 165 Coastal GasLink 1 35.0 % 203 1 — 294 — U.S. Natural Gas Pipelines Northern Border 50.0 % 101 92 80 599 516 Millennium 47.5 % 109 103 91 476 500 Iroquois 50.0 % 98 77 55 227 237 Other Various 16 20 18 120 122 Mexico Natural Gas Pipelines Sur de Texas 60.0 % 78 150 160 1,078 1,050 Liquids Pipelines Grand Rapids 1 50.0 % 53 54 54 932 964 Port Neches Link LLC 2,3 74.9 % 13 — — 124 149 HoustonLink Pipeline 1 50.0 % 1 1 1 18 19 Northern Courier 1,4 nil — — 16 — — Power and Energy Solutions Bruce Power 1 48.3 % 690 537 411 6,242 5,783 Other Various (2) 2 — 38 30 1,377 1,054 898 10,314 9,535 1 Classified as a VIE. Refer to Note 33, Variable interest entities, for additional information. 2 Classified as a VIE in 2021. 3 In December 2023, TC Energy sold a 20.1 per cent equity interest in Port Neches Link LLC. 4 In November 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 31, Acquisitions and dispositions, 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 LNG Canada facility by the end of 2023. These milestones entitle Coastal GasLink LP to receive a $200 million incentive payment from LNG Canada. In accordance with the contractual terms between the Coastal GasLink LP partners, the amount accrues in full to TC Energy as the project developer and was settled through a cash distribution on February 12, 2024. The Company recognized the incentive payment as Income (loss) from equity investments in the Consolidated statement of income for the year ended December 31, 2023 and recorded a corresponding amount in Accounts receivable on the Consolidated balance sheet. Impairment of Equity Investment In the fourth quarter of 2022, the Company announced that a material increase in the Coastal GasLink pipeline project costs was expected. On February 1, 2023, Coastal GasLink LP announced an increase in the revised capital cost of the Coastal GasLink pipeline project. The increase in project costs and the Company's corresponding funding requirements were indicators that a decrease in the value of the Company's equity investment had occurred. As a result, the Company completed a valuation assessment and concluded that the fair value of TC Energy's investment was below its carrying value at December 31, 2022. The Company completed valuation assessments at each of the first three quarters of 2023 and concluded that an other-than-temporary impairment of its investment had occurred. This resulted in a pre-tax impairment charge of $2,100 million ($1,943 million after tax) and $3,048 million ($2,643 million after tax) recorded in the year ended December 31, 2023 and 2022, respectively. Refer to Note 8, Coastal GasLink, for additional information. Distributions and Contributions Distributions received from equity investments and contributions made to equity investments for the years ended December 31, 2023, 2022 and 2021 were as follows: year ended December 31 2023 2022 2021 (millions of Canadian $) Distributions Distributions received from operating activities of equity investments 1,254 1,025 975 Sur de Texas debt repayments 1,2 — 2,404 73 Other 1 23 228 — 1,277 3,657 1,048 Contributions 1 Contributions to Coastal GasLink 3,231 1,414 92 Sur de Texas debt financing 2 — 1,199 — Contributions made to other equity investments 918 820 1,118 4,149 3,433 1,210 1 Included in Investing activities in the Consolidated statement of cash flows. 2 Represents TC Energy's proportionate share of the Sur de Texas debt financing requirements and subsequent repayments. Refer to Note 13, Loans receivable from affiliates, for additional information. Summarized Financial Information of Equity Investments year ended December 31 2023 2022 2021 (millions of Canadian $) Income Revenues 6,425 5,891 5,447 Operating and other expenses (3,450) (3,390) (3,293) Net income 2,584 2,147 1,859 Net income attributable to TC Energy 1,377 1,054 898 at December 31 2023 2022 (millions of Canadian $) Balance Sheet Current assets 3,526 3,414 Non-current assets 42,933 37,713 Current liabilities (2,431) (2,856) Non-current liabilities (21,895) (17,690)

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2023
Other Assets [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS at December 31 2023 2022 (millions of Canadian $) Fair value of derivative contracts (Note 29) 1,285 614 Current portion of net investment in leases (Note 11) 306 291 Contract assets (Note 6) 151 155 Current portion of Keystone environmental provision recovery (Note 18) 150 410 Cash provided as collateral 120 106 Emissions credits 94 36 Prepaid expenses 92 118 Keystone XL contractual recoveries (Note 7) 83 86 Regulatory assets (Note 14) 76 67 Keystone XL assets held for sale 58 122 Other 88 147 2,503 2,152

PLANT, PROPERTY AND EQUIPMENT

PLANT, PROPERTY AND EQUIPMENT	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
PLANT, PROPERTY AND EQUIPMENT	PLANT, PROPERTY AND EQUIPMENT at December 31 2023 2022 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 20,232 6,855 13,377 18,119 6,285 11,834 Compression 6,603 2,349 4,254 6,265 2,224 4,041 Metering and other 1,589 830 759 1,518 769 749 28,424 10,034 18,390 25,902 9,278 16,624 Under construction 787 — 787 1,552 — 1,552 29,211 10,034 19,177 27,454 9,278 18,176 Canadian Mainline Pipeline 10,729 7,996 2,733 10,472 7,852 2,620 Compression 4,437 3,354 1,083 4,328 3,247 1,081 Metering and other 729 308 421 692 285 407 15,895 11,658 4,237 15,492 11,384 4,108 Under construction 147 — 147 269 — 269 16,042 11,658 4,384 15,761 11,384 4,377 Other Canadian Natural Gas Pipelines 1 Other 2,846 1,682 1,164 1,984 1,624 360 Under construction 23 — 23 455 — 455 2,869 1,682 1,187 2,439 1,624 815 48,122 23,374 24,748 45,654 22,286 23,368 U.S. Natural Gas Pipelines Columbia Gas Pipeline 12,952 1,247 11,705 12,471 1,069 11,402 Compression 5,310 559 4,751 5,190 495 4,695 Metering and other 4,074 372 3,702 4,026 346 3,680 22,336 2,178 20,158 21,687 1,910 19,777 Under construction 771 — 771 659 — 659 23,107 2,178 20,929 22,346 1,910 20,436 ANR Pipeline 2,117 657 1,460 2,066 641 1,425 Compression 3,928 773 3,155 3,785 734 3,051 Metering and other 1,625 458 1,167 1,666 440 1,226 7,670 1,888 5,782 7,517 1,815 5,702 Under construction 404 — 404 328 — 328 8,074 1,888 6,186 7,845 1,815 6,030 at December 31 2023 2022 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Other U.S. Natural Gas Pipelines Columbia Gulf 3,600 256 3,344 3,511 224 3,287 GTN 2,992 1,295 1,697 2,964 1,239 1,725 Great Lakes 2,359 1,401 958 2,367 1,387 980 Other 2 2,071 800 1,271 1,928 760 1,168 11,022 3,752 7,270 10,770 3,610 7,160 Under construction 584 — 584 328 — 328 11,606 3,752 7,854 11,098 3,610 7,488 42,787 7,818 34,969 41,289 7,335 33,954 Mexico Natural Gas Pipelines 3 Pipeline 2,280 387 1,893 2,299 348 1,951 Compression 370 79 291 374 59 315 Metering and other 482 123 359 487 113 374 3,132 589 2,543 3,160 520 2,640 Under construction 4,823 — 4,823 2,547 — 2,547 7,955 589 7,366 5,707 520 5,187 Liquids Pipelines Keystone Pipeline System Pipeline 9,569 2,212 7,357 9,777 2,056 7,721 Pumping equipment 1,096 312 784 1,064 288 776 Tanks and other 3,658 913 2,745 3,723 859 2,864 14,323 3,437 10,886 14,564 3,203 11,361 Under construction 54 — 54 96 — 96 14,377 3,437 10,940 14,660 3,203 11,457 Intra-Alberta Pipelines 203 25 178 199 19 180 14,580 3,462 11,118 14,859 3,222 11,637 Power and Energy Solutions Natural Gas Power Generation 1,239 637 602 1,260 642 618 Natural Gas Storage and Other 845 256 589 820 238 582 Renewable Power Generation 581 19 562 — — — 2,665 912 1,753 2,080 880 1,200 Under construction 153 — 153 80 — 80 2,818 912 1,906 2,160 880 1,280 Corporate 909 447 462 900 386 514 117,171 36,602 80,569 110,569 34,629 75,940 1 Includes Foothills, Ventures LP and Great Lakes Canada. 2 Includes Portland, North Baja, Tuscarora, Crossroads and mineral rights business. 3 During the year ended December 31, 2023, the Company derecognized $407 million (2022 – $2,319 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 11, Leases, for additional information.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2023
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 $) 2023 2022 Operating lease cost 1 118 106 Sublease income (4) (5) Net operating lease cost 114 101 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 $) 2023 2022 Cash paid for amounts included in the measurement of operating lease liabilities 72 67 ROU assets obtained in exchange for new operating lease liabilities 84 49 at December 31 2023 2022 Weighted average remaining lease term 13 years 8 years Weighted average discount rate 3.3 % 3.5 % Maturities of operating lease liabilities are as follows: at December 31 (millions of Canadian $) 2023 2022 Less than one year 72 68 One to two years 68 65 Two to three years 66 62 Three to four years 59 60 Four to five years 58 54 More than five years 225 187 Total operating lease payments 548 496 Imputed interest (89) (63) Operating lease liabilities 459 433 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2023 2022 Accounts payable and other 58 54 Other long-term liabilities (Note 19) 401 379 459 433 As at December 31, 2023, the carrying value of the ROU assets recorded under operating leases was $437 million (2022 – $415 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 2024 and 2026. 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 Company also leases liquids tanks which are accounted for as operating leases. The fixed portion of the operating lease income recorded by the Company for the year ended December 31, 2023 was $116 million (2022 – $118 million; 2021 – $126 million). Future lease payments to be received under operating leases are as follows: at December 31 (millions of Canadian $) 2023 2022 Less than one year 113 113 One to two years 94 111 Two to three years 70 94 Three to four years — 70 277 388 The cost and accumulated depreciation for facilities accounted for as operating leases was $796 million and $370 million, respectively, at December 31, 2023 (2022 – $802 million and $360 million, respectively). Sales-Type Leases On August 4, 2022, TC Energy announced a strategic alliance with Mexico’s state-owned electric utility, the Comisión Federal de Electricidad (CFE), for the development of new natural gas infrastructure in central and southeast Mexico. This alliance consolidates previous TSAs executed between TC Energy’s Mexico-based subsidiary TGNH and the CFE in connection with the Company's natural gas pipeline assets in central Mexico (including the Tamazunchale, Villa de Reyes and Tula pipelines) under a single, U.S. dollar-denominated take-or-pay TSA that extends through 2055. The consolidated TSA contains a lease with multiple lease and non-lease components. The lease components represent the capacity available to the CFE provided by the in-service pipelines which, at December 31, 2023, included the Tamazunchale pipeline, the north and lateral sections of the Villa de Reyes pipeline and the east section of the Tula pipeline. The non-lease components represent the Company’s services with respect to operation and maintenance of the TGNH pipelines in service. The consolidated TSA provides the CFE with substantially all of the economic benefits from the use of each identified in-service asset, therefore, the lease arrangements in the consolidated TSA are classified as sales-type leases. 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 2023, the Company recognized an additional $407 million in net investment in leases (2022 – $2,319 million) to reflect sales type-leases placed into service. At the inception of the lease term, the Company applied judgment to determine that the fair value of the underlying assets approximated the carrying value and residual value of the lease based on the rate-regulated nature of the assets within the TGNH system. 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 $) 2023 2022 Net Investment in Leases Minimum lease payments 9,627 9,457 Unearned lease income (7,006) (7,132) Lease receivable 2,621 2,325 Expected credit loss provision 1 (76) (150) Present value of unguaranteed residual value 24 11 2,569 2,186 Current portion included in Other current assets (Note 9) (306) (291) 2,263 1,895 1 Includes nil (2022 – $1 million) of foreign currency translation losses. Future lease payments to be received under the existing sales-type leases are as follows: at December 31 (millions of Canadian $) 2023 2022 Less than one year 305 291 One to two years 305 291 Two to three years 305 291 Three to four years 305 291 Four to five years 305 291 More than five years 8,102 8,002 9,627 9,457 Future lease payments will increase as assets associated with sales-type leases come into service. For the year ended December 31, 2023, the Company recorded $279 million (2022 – $127 million) of sales-type lease income in Mexico Natural Gas Pipelines revenues. For the year ended December 31, 2023, the Company recorded a $73 million ECL recovery (2022 – an expense of $149 million; 2021 – nil) in Plant operating costs and other relating to net investment in leases. Refer to Note 29, 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 $) 2023 2022 Operating lease cost 1 118 106 Sublease income (4) (5) Net operating lease cost 114 101 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 $) 2023 2022 Cash paid for amounts included in the measurement of operating lease liabilities 72 67 ROU assets obtained in exchange for new operating lease liabilities 84 49 at December 31 2023 2022 Weighted average remaining lease term 13 years 8 years Weighted average discount rate 3.3 % 3.5 % Maturities of operating lease liabilities are as follows: at December 31 (millions of Canadian $) 2023 2022 Less than one year 72 68 One to two years 68 65 Two to three years 66 62 Three to four years 59 60 Four to five years 58 54 More than five years 225 187 Total operating lease payments 548 496 Imputed interest (89) (63) Operating lease liabilities 459 433 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2023 2022 Accounts payable and other 58 54 Other long-term liabilities (Note 19) 401 379 459 433 As at December 31, 2023, the carrying value of the ROU assets recorded under operating leases was $437 million (2022 – $415 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 2024 and 2026. 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 Company also leases liquids tanks which are accounted for as operating leases. The fixed portion of the operating lease income recorded by the Company for the year ended December 31, 2023 was $116 million (2022 – $118 million; 2021 – $126 million). Future lease payments to be received under operating leases are as follows: at December 31 (millions of Canadian $) 2023 2022 Less than one year 113 113 One to two years 94 111 Two to three years 70 94 Three to four years — 70 277 388 The cost and accumulated depreciation for facilities accounted for as operating leases was $796 million and $370 million, respectively, at December 31, 2023 (2022 – $802 million and $360 million, respectively). Sales-Type Leases On August 4, 2022, TC Energy announced a strategic alliance with Mexico’s state-owned electric utility, the Comisión Federal de Electricidad (CFE), for the development of new natural gas infrastructure in central and southeast Mexico. This alliance consolidates previous TSAs executed between TC Energy’s Mexico-based subsidiary TGNH and the CFE in connection with the Company's natural gas pipeline assets in central Mexico (including the Tamazunchale, Villa de Reyes and Tula pipelines) under a single, U.S. dollar-denominated take-or-pay TSA that extends through 2055. The consolidated TSA contains a lease with multiple lease and non-lease components. The lease components represent the capacity available to the CFE provided by the in-service pipelines which, at December 31, 2023, included the Tamazunchale pipeline, the north and lateral sections of the Villa de Reyes pipeline and the east section of the Tula pipeline. The non-lease components represent the Company’s services with respect to operation and maintenance of the TGNH pipelines in service. The consolidated TSA provides the CFE with substantially all of the economic benefits from the use of each identified in-service asset, therefore, the lease arrangements in the consolidated TSA are classified as sales-type leases. 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 2023, the Company recognized an additional $407 million in net investment in leases (2022 – $2,319 million) to reflect sales type-leases placed into service. At the inception of the lease term, the Company applied judgment to determine that the fair value of the underlying assets approximated the carrying value and residual value of the lease based on the rate-regulated nature of the assets within the TGNH system. 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 $) 2023 2022 Net Investment in Leases Minimum lease payments 9,627 9,457 Unearned lease income (7,006) (7,132) Lease receivable 2,621 2,325 Expected credit loss provision 1 (76) (150) Present value of unguaranteed residual value 24 11 2,569 2,186 Current portion included in Other current assets (Note 9) (306) (291) 2,263 1,895 1 Includes nil (2022 – $1 million) of foreign currency translation losses. Future lease payments to be received under the existing sales-type leases are as follows: at December 31 (millions of Canadian $) 2023 2022 Less than one year 305 291 One to two years 305 291 Two to three years 305 291 Three to four years 305 291 Four to five years 305 291 More than five years 8,102 8,002 9,627 9,457 Future lease payments will increase as assets associated with sales-type leases come into service. For the year ended December 31, 2023, the Company recorded $279 million (2022 – $127 million) of sales-type lease income in Mexico Natural Gas Pipelines revenues. For the year ended December 31, 2023, the Company recorded a $73 million ECL recovery (2022 – an expense of $149 million; 2021 – nil) in Plant operating costs and other relating to net investment in leases. Refer to Note 29, 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 $) 2023 2022 Operating lease cost 1 118 106 Sublease income (4) (5) Net operating lease cost 114 101 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 $) 2023 2022 Cash paid for amounts included in the measurement of operating lease liabilities 72 67 ROU assets obtained in exchange for new operating lease liabilities 84 49 at December 31 2023 2022 Weighted average remaining lease term 13 years 8 years Weighted average discount rate 3.3 % 3.5 % Maturities of operating lease liabilities are as follows: at December 31 (millions of Canadian $) 2023 2022 Less than one year 72 68 One to two years 68 65 Two to three years 66 62 Three to four years 59 60 Four to five years 58 54 More than five years 225 187 Total operating lease payments 548 496 Imputed interest (89) (63) Operating lease liabilities 459 433 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2023 2022 Accounts payable and other 58 54 Other long-term liabilities (Note 19) 401 379 459 433 As at December 31, 2023, the carrying value of the ROU assets recorded under operating leases was $437 million (2022 – $415 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 2024 and 2026. 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 Company also leases liquids tanks which are accounted for as operating leases. The fixed portion of the operating lease income recorded by the Company for the year ended December 31, 2023 was $116 million (2022 – $118 million; 2021 – $126 million). Future lease payments to be received under operating leases are as follows: at December 31 (millions of Canadian $) 2023 2022 Less than one year 113 113 One to two years 94 111 Two to three years 70 94 Three to four years — 70 277 388 The cost and accumulated depreciation for facilities accounted for as operating leases was $796 million and $370 million, respectively, at December 31, 2023 (2022 – $802 million and $360 million, respectively). Sales-Type Leases On August 4, 2022, TC Energy announced a strategic alliance with Mexico’s state-owned electric utility, the Comisión Federal de Electricidad (CFE), for the development of new natural gas infrastructure in central and southeast Mexico. This alliance consolidates previous TSAs executed between TC Energy’s Mexico-based subsidiary TGNH and the CFE in connection with the Company's natural gas pipeline assets in central Mexico (including the Tamazunchale, Villa de Reyes and Tula pipelines) under a single, U.S. dollar-denominated take-or-pay TSA that extends through 2055. The consolidated TSA contains a lease with multiple lease and non-lease components. The lease components represent the capacity available to the CFE provided by the in-service pipelines which, at December 31, 2023, included the Tamazunchale pipeline, the north and lateral sections of the Villa de Reyes pipeline and the east section of the Tula pipeline. The non-lease components represent the Company’s services with respect to operation and maintenance of the TGNH pipelines in service. The consolidated TSA provides the CFE with substantially all of the economic benefits from the use of each identified in-service asset, therefore, the lease arrangements in the consolidated TSA are classified as sales-type leases. 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 2023, the Company recognized an additional $407 million in net investment in leases (2022 – $2,319 million) to reflect sales type-leases placed into service. At the inception of the lease term, the Company applied judgment to determine that the fair value of the underlying assets approximated the carrying value and residual value of the lease based on the rate-regulated nature of the assets within the TGNH system. 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 $) 2023 2022 Net Investment in Leases Minimum lease payments 9,627 9,457 Unearned lease income (7,006) (7,132) Lease receivable 2,621 2,325 Expected credit loss provision 1 (76) (150) Present value of unguaranteed residual value 24 11 2,569 2,186 Current portion included in Other current assets (Note 9) (306) (291) 2,263 1,895 1 Includes nil (2022 – $1 million) of foreign currency translation losses. Future lease payments to be received under the existing sales-type leases are as follows: at December 31 (millions of Canadian $) 2023 2022 Less than one year 305 291 One to two years 305 291 Two to three years 305 291 Three to four years 305 291 Four to five years 305 291 More than five years 8,102 8,002 9,627 9,457 Future lease payments will increase as assets associated with sales-type leases come into service. For the year ended December 31, 2023, the Company recorded $279 million (2022 – $127 million) of sales-type lease income in Mexico Natural Gas Pipelines revenues. For the year ended December 31, 2023, the Company recorded a $73 million ECL recovery (2022 – an expense of $149 million; 2021 – nil) in Plant operating costs and other relating to net investment in leases. Refer to Note 29, Risk management and financial instruments, for additional information.

EQUITY INVESTMENTS

EQUITY INVESTMENTS	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	COASTAL GASLINK Impairment of Equity Investment in Coastal GasLink LP In July 2022, amended agreements were executed between Coastal GasLink LP, LNG Canada, TC Energy and its Coastal GasLink LP partners (collectively, the July 2022 agreements). These amendments revised the commercial terms between LNG Canada and Coastal GasLink LP, as well as funding provisions between the partners of Coastal GasLink LP. With the expectation that additional equity contributions under a subordinated loan agreement between TC Energy and the Coastal GasLink LP partners will be predominantly funded by TC Energy as limited partner of Coastal GasLink LP, in accordance with the July 2022 agreements, the Company completed valuation assessments during the first three quarters of 2023 and concluded that, for each period an assessment was performed, the fair value of its investment in Coastal GasLink LP was below its carrying value and that these were other-than-temporary impairments. As a result, a pre-tax impairment charge of $2,100 million ($1,943 million after tax) was recognized during the year ended December 31, 2023 in Impairment of equity investment in the Consolidated statement of income in the Canadian Natural Gas Pipelines segment (2022 – $3,048 million; $2,643 million after tax). The carrying value of the investment in Coastal GasLink LP was $294 million at December 31, 2023 (2022 – nil), which reflects the balance of amounts, net of impairments, drawn on the subordinated loan to date at December 31, 2023 and other changes to TC Energy's equity investment. The impairment charge reflected the net impact of $2,020 million drawn on and a $250 million repayment of the subordinated loan for the nine months ended September 30, 2023, along with TC Energy’s proportionate share of unrealized gains and losses on interest rate derivatives in Coastal GasLink LP and other changes to the equity investment. The cumulative pre-tax impairment charge recognized at December 31, 2023 is $5,148 million ($4,586 million after tax). A deferred income tax recovery was recognized on the pre-tax impairment charge, net of certain unrealized tax losses not recognized. The impairment of the subordinated loan resulted in unrealized non-taxable capital losses that are not recognized. Refer to Note 20, Income taxes, for additional information. At December 31, 2023, TC Energy expects to fund an additional $0.9 billion related to the capital cost estimates to complete the Coastal GasLink pipeline, which is consistent with the capital cost profile that was included in the September 30, 2023 impairment calculation. At December 31, 2023, there were no events or changes in circumstances since September 30, 2023 indicating a significant adverse impact on the estimated fair value of the Company’s investment in Coastal GasLink LP. The fair value of TC Energy’s investment in Coastal GasLink LP at September 30, 2023 and December 31, 2022 was estimated using a 40-year discounted cash flow model and is classified as a Level III fair value measurement. The discounted cash flow is most sensitive to assumptions related to the capital cost estimates for the Coastal GasLink pipeline of approximately $14.5 billion (2022 – $14.5 billion), discount rate and long-term financing plans. Other assumptions included in the discounted cash flow model include contractually agreed upon terms and extension provisions in the TSAs between Coastal GasLink LP and the LNG Canada participants, potential expansion projects and estimated completion date. Subordinated Loan Agreement In 2021, TC Energy entered into a subordinated loan agreement with Coastal GasLink LP. This loan agreement was amended as part of the July 2022 agreements, and subsequent draws on this loan by Coastal GasLink LP will be provided through an interest-bearing loan, subject to a floating market-based interest rate to fund the capital cost to complete the Coastal GasLink pipeline. Committed capacity under the subordinated loan agreement between TC Energy and Coastal GasLink LP was $3.4 billion, with $2.5 billion drawn on the loan at December 31, 2023. Any amounts outstanding on the loan will be repaid by Coastal GasLink LP to TC Energy once final project costs are known, which will be determined after the pipeline is placed into service. Coastal GasLink LP partners, including TC Energy, will contribute equity to Coastal GasLink LP to ultimately fund Coastal GasLink LP’s repayment of this subordinated loan to TC Energy. The Company expects that these additional equity contributions will be predominantly funded by TC Energy. Amounts drawn on this loan subsequent to amended agreements executed in July 2022 are accounted for as in-substance equity contributions and are presented as Contributions to equity investments on the Company’s Consolidated statement of cash flows. Interest and principal repayments on this loan, which are expected to be predominantly funded by TC Energy, will be accounted for as an equity investment distribution to the Company once received. The table below reflects the changes in this loan receivable balance. at December 31 (millions of Canadian $) 2023 2022 Outstanding balance at beginning of year 250 238 Issuances 2,520 112 Repayments (250) (100) Outstanding balance at end of year 2,520 250 Impairment during the year (2,020) (250) Carrying value at end of year 500 — (millions of Canadian $) Ownership Interest at December 31, 2023 Income (Loss) from Equity Investments Equity year ended December 31 at December 31 2023 2022 2021 2023 2022 Canadian Natural Gas Pipelines TQM 1 50.0 % 17 17 12 166 165 Coastal GasLink 1 35.0 % 203 1 — 294 — U.S. Natural Gas Pipelines Northern Border 50.0 % 101 92 80 599 516 Millennium 47.5 % 109 103 91 476 500 Iroquois 50.0 % 98 77 55 227 237 Other Various 16 20 18 120 122 Mexico Natural Gas Pipelines Sur de Texas 60.0 % 78 150 160 1,078 1,050 Liquids Pipelines Grand Rapids 1 50.0 % 53 54 54 932 964 Port Neches Link LLC 2,3 74.9 % 13 — — 124 149 HoustonLink Pipeline 1 50.0 % 1 1 1 18 19 Northern Courier 1,4 nil — — 16 — — Power and Energy Solutions Bruce Power 1 48.3 % 690 537 411 6,242 5,783 Other Various (2) 2 — 38 30 1,377 1,054 898 10,314 9,535 1 Classified as a VIE. Refer to Note 33, Variable interest entities, for additional information. 2 Classified as a VIE in 2021. 3 In December 2023, TC Energy sold a 20.1 per cent equity interest in Port Neches Link LLC. 4 In November 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 31, Acquisitions and dispositions, 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 LNG Canada facility by the end of 2023. These milestones entitle Coastal GasLink LP to receive a $200 million incentive payment from LNG Canada. In accordance with the contractual terms between the Coastal GasLink LP partners, the amount accrues in full to TC Energy as the project developer and was settled through a cash distribution on February 12, 2024. The Company recognized the incentive payment as Income (loss) from equity investments in the Consolidated statement of income for the year ended December 31, 2023 and recorded a corresponding amount in Accounts receivable on the Consolidated balance sheet. Impairment of Equity Investment In the fourth quarter of 2022, the Company announced that a material increase in the Coastal GasLink pipeline project costs was expected. On February 1, 2023, Coastal GasLink LP announced an increase in the revised capital cost of the Coastal GasLink pipeline project. The increase in project costs and the Company's corresponding funding requirements were indicators that a decrease in the value of the Company's equity investment had occurred. As a result, the Company completed a valuation assessment and concluded that the fair value of TC Energy's investment was below its carrying value at December 31, 2022. The Company completed valuation assessments at each of the first three quarters of 2023 and concluded that an other-than-temporary impairment of its investment had occurred. This resulted in a pre-tax impairment charge of $2,100 million ($1,943 million after tax) and $3,048 million ($2,643 million after tax) recorded in the year ended December 31, 2023 and 2022, respectively. Refer to Note 8, Coastal GasLink, for additional information. Distributions and Contributions Distributions received from equity investments and contributions made to equity investments for the years ended December 31, 2023, 2022 and 2021 were as follows: year ended December 31 2023 2022 2021 (millions of Canadian $) Distributions Distributions received from operating activities of equity investments 1,254 1,025 975 Sur de Texas debt repayments 1,2 — 2,404 73 Other 1 23 228 — 1,277 3,657 1,048 Contributions 1 Contributions to Coastal GasLink 3,231 1,414 92 Sur de Texas debt financing 2 — 1,199 — Contributions made to other equity investments 918 820 1,118 4,149 3,433 1,210 1 Included in Investing activities in the Consolidated statement of cash flows. 2 Represents TC Energy's proportionate share of the Sur de Texas debt financing requirements and subsequent repayments. Refer to Note 13, Loans receivable from affiliates, for additional information. Summarized Financial Information of Equity Investments year ended December 31 2023 2022 2021 (millions of Canadian $) Income Revenues 6,425 5,891 5,447 Operating and other expenses (3,450) (3,390) (3,293) Net income 2,584 2,147 1,859 Net income attributable to TC Energy 1,377 1,054 898 at December 31 2023 2022 (millions of Canadian $) Balance Sheet Current assets 3,526 3,414 Non-current assets 42,933 37,713 Current liabilities (2,431) (2,856) Non-current liabilities (21,895) (17,690)

LOANS RECEIVABLE FROM AFFILIATE

LOANS RECEIVABLE FROM AFFILIATES	12 Months Ended
	Dec. 31, 2023
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 and operate the Coastal GasLink pipeline. Subordinated Demand Revolving Credit Facility The Company has a subordinated demand revolving credit facility with Coastal GasLink LP to provide additional short-term liquidity and funding flexibility to the project. The facility bears interest at a floating market-based rate and has a capacity of $100 million (2022 – $100 million) with no outstanding balance at December 31, 2023 and 2022. This revolver was not impacted by the impairment charges recognized to date. Subordinated Loan Agreement In 2021, TC Energy entered into a subordinated loan agreement with Coastal GasLink LP, which was amended on July 28, 2022. At December 31, 2023, the total capacity committed by TC Energy under this subordinated loan agreement was $3.4 billion (2022 – $1.3 billion) with an outstanding balance of $2,520 million (2022 – $250 million). In the year ended December 31, 2023, $2,020 million (2022 – $250 million) was impaired. Refer to Note 8, 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 $) 2023 2022 2021 Interest income 1 — 19 87 Interest income and other Interest expense 2 — (19) (87) Income (loss) from equity investments Foreign exchange losses 1 — (28) (41) Foreign exchange (gains) losses, net Foreign exchange gains 1 — 28 41 Income 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 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, 2023
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 (CER Act). The Impact Assessment Agency of Canada continues to assess designated projects. 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. 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 The NGTL System is operating under the 2020-2024 Revenue Requirement Settlement which includes an approved ROE of 10.1 per cent on 40 per cent deemed common equity. This settlement provides the NGTL System the opportunity to increase depreciation rates if tolls fall below specified levels and an incentive mechanism for certain operating costs where variances from projected amounts are shared with its customers. 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 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 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 reached a settlement with its customers effective February 2021 and received FERC approval in February 2022. As part of the settlement, there is a moratorium on any further rate changes until April 1, 2025. Columbia Gas must file for new rates with an effective date no later than April 1, 2026. Previously accrued rate refund liabilities were refunded to customers, including interest, in second quarter 2022. 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. ANR Pipeline ANR Pipeline operated under rates established through a 2016 FERC-approved rate settlement until July 31, 2022. To meet terms of the 2016 settlement, in January 2022, ANR Pipeline filed a Section 4 Rate Case with FERC requesting an increase to maximum transportation rates. In December 2022 ANR Pipeline filed a Stipulation and Agreement of Settlement (2022 ANR Settlement) with FERC. 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. In second quarter 2023, previously accrued rate refund liabilities, including interest, were refunded to customers. Columbia Gulf Columbia Gulf operates under a settlement approved by FERC in December 2019 (2019 Columbia Gulf Settlement), which requires Columbia Gulf to file a general rate case under Section 4 of the NGA no later than January 31, 2027. The 2019 Columbia Gulf Settlement included a moratorium that expired in August 2022. In July 2023 Columbia Gulf, in advance of its obligation to file a general rate case from the 2019 Columbia Gulf Settlement, reached a settlement with its customers effective March 1, 2024 and received FERC approval in August 2023 (2023 Columbia Gulf Settlement). As part of the 2023 Columbia Gulf Settlement, there is a moratorium on any 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 settlement approved by FERC in February 2018, which does not include a moratorium; however, Great Lakes was required to file for new rates no later than March 31, 2022. In March 2022, Great Lakes filed a rate settlement (2022 Great Lakes Settlement) with FERC that satisfies the obligations from the 2017 settlement that Great Lakes file for rates to become effective no later than October 2022. The 2022 Great Lakes Settlement, approved by FERC in April 2022, 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 effective August 2019. Under the terms of this settlement, Tuscarora was required to file for new rates to be effective no later than February 1, 2023. Tuscarora filed a general NGA Section 4 Rate Case with FERC in July 2022, requesting an increase to its maximum rates effective February 1, 2023, subject to refund. On March 24, 2023, Tuscarora filed a Stipulation and Agreement of Settlement with FERC, which was approved on September 6, 2023. Gas Transmission Northwest Gas Transmission Northwest (GTN) operates under rates established as part of the FERC-approved rate settlement effective November 18, 2021 (2021 GTN Settlement). The 2021 GTN Settlement satisfies the obligations from the 2015 and 2018 rate settlements that GTN file for rates to become effective no later than January 1, 2022 and extends existing maximum transportation rates at their current levels. GTN’s annual depreciation rates remain unchanged. The 2021 GTN Settlement contains a moratorium until December 31, 2023. Additionally, the 2021 GTN Settlement authorizes GTN to recover payments that it incurs in the states of Oregon and Washington for carbon/greenhouse gas-related taxes. GTN is required to file for new rates to become effective no later than April 1, 2024. Accordingly, GTN filed a general NGA Section 4 Rate Case with FERC on September 29, 2023, requesting an increase to GTN's maximum rates to become effective April 1, 2024, and subject to refund. 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 are in compliance with CRE economic regulations that provide for cost recovery, including a return of and on invested capital. Regulatory Assets and Liabilities at December 31 Remaining Recovery/ Settlement Period (years) 2023 2022 (millions of Canadian $) Regulatory Assets Deferred income taxes 1 n/a 2,204 1,817 Operating and debt-service regulatory assets 2 1 29 2 Pensions and other post-retirement benefits 1,3 n/a 54 28 Foreign exchange on long-term debt 1,4 1-6 11 19 Other n/a 108 111 2,406 1,977 Less: Current portion included in Other current assets (Note 9) 76 67 2,330 1,910 Regulatory Liabilities Pipeline abandonment trust balances 5 n/a 2,355 2,014 Deferred income taxes – U.S. Tax Reform 6 n/a 1,137 1,197 Canadian Mainline short-term adjustment and toll-stabilization accounts 7,8 n/a 437 284 Canadian Mainline bridging amortization account 7 7 376 429 Cost of removal 9 n/a 351 337 Deferred income taxes 1 n/a 198 181 Canadian Mainline long-term adjustment account 7,10 3 111 149 ANR post-employment and retirement benefits other than pension 11 n/a 42 43 Operating and debt-service regulatory liabilities 2 1 23 50 Pensions and other post-retirement benefits 3 n/a 6 10 Other n/a 54 99 5,090 4,793 Less: Current portion included in Accounts payable and other (Note 18) 284 273 4,806 4,520 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 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, 2023
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 2023 2022 (millions) Canadian U.S. dollars Canadian dollars U.S. dollars Columbia Pipeline Group, Inc. 9,708 7,351 9,948 7,351 ANR 2,570 1,946 2,634 1,946 Great Lakes 161 122 165 122 North Baja 63 48 65 48 Tuscarora 30 23 31 23 12,532 9,490 12,843 9,490 Changes in Goodwill were as follows: (millions of Canadian $) U.S. Natural Balance at January 1, 2022 12,582 Great Lakes impairment charge (571) Foreign exchange rate changes 832 Balance at December 31, 2022 12,843 Foreign exchange rate changes (311) Balance at December 31, 2023 12,532 As part of the annual goodwill impairment assessment at December 31, 2023, the Company evaluated qualitative factors impacting the fair value of the underlying reporting units for all reporting units other than for the Tuscarora and North Baja reporting units. It was determined that it was more likely than not that the fair value of these 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. The Company evaluated qualitative factors impacting the fair value of the Columbia reporting unit from June 30, 2023 to December 31, 2023 and determined that it was more likely than not that the fair value remains higher than the carrying amount, including goodwill. North Baja and Tuscarora The Company elected to proceed directly to a quantitative annual impairment test at December 31, 2023 for the $63 million of goodwill related to the North Baja reporting unit due to the passage of time from the previous quantitative test at December 31, 2018. The Company also elected to proceed directly to a quantitative annual impairment test for the $30 million of goodwill related to the Tuscarora reporting unit due to the passage of time from the previous quantitative test at December 31, 2018, and subsequent to the Tuscarora Section 4 rate case settlement in 2023. It was determined that the fair values of North Baja and Tuscarora exceeded their carrying values, including goodwill, at December 31, 2023. Great Lakes In March 2022, Great Lakes reached a pre-filing settlement with its customers and filed an unopposed rate case settlement with FERC by which Great Lakes and the settling parties agreed to maintain existing recourse rates through October 31, 2025. Management performed a quantitative impairment test which evaluated a range of assumptions through a discounted cash flow model analysis using a risk-adjusted discount rate. It was determined that the estimated fair value of the Great Lakes reporting unit no longer exceeded its carrying value, including goodwill, and that an impairment charge was necessary. As a result, the Company recorded a pre-tax goodwill impairment charge of $571 million ($531 million after tax) for the year ended December 31, 2022 within the U.S. Natural Gas Pipelines segment that is included in Goodwill and asset impairment charges and other in the Company's Consolidated statement of income. The remaining goodwill balance related to Great Lakes was US$122 million at December 31, 2022. There is a risk that continued reductions in future cash flow forecasts and adverse changes in other key assumptions could result in a future impairment of the goodwill balance relating to Great Lakes. The majority of the Great Lakes goodwill impairment charge was allocated to non-deductible goodwill and the income tax recovery of $40 million was attributable to the portion of the goodwill that was deductible for income tax purposes. The estimated fair value measurements used in the Company's goodwill impairment analysis is classified as Level III of the fair value hierarchy. In the determination of the fair value utilized in the quantitative goodwill impairment test for each reporting unit, the Company used its projections of future cash flows and applied a risk-adjusted discount rate which involved significant estimates and judgments. Asset Divestiture Program

OTHER LONG-TERM ASSETS

OTHER LONG-TERM ASSETS	12 Months Ended
	Dec. 31, 2023
Intangible Assets, Net (Excluding Goodwill) [Abstract]
OTHER LONG-TERM ASSETS	OTHER LONG-TERM ASSETS at December 31 2023 2022 (millions of Canadian $) Deferred income tax assets (Note 20) 1,332 1,070 Employee post-retirement benefits (Note 28) 518 563 Long-term contract assets (Note 6) 457 355 Capital projects in development 237 99 Fair value of derivative contracts (Note 29) 155 91 Keystone XL contractual recoveries (Note 7) 34 44 Keystone environmental provision recovery (Note 18) 33 240 Other 252 323 3,018 2,785

NOTES PAYABLE

NOTES PAYABLE	12 Months Ended
	Dec. 31, 2023
Short-Term Debt [Abstract]
NOTES PAYABLE	NOTES PAYABLE at December 31 2023 2022 (millions of Canadian $, unless otherwise noted) Outstanding Weighted Average Interest Rate per Annum Outstanding Weighted Average Interest Rate per Annum Canada 1 — — 5,971 4.9 % Mexico (2023 – nil; 2022 – US$215) 2 — — 291 6.0 % — 6,262 1 At December 31, 2023, Notes payable consisted of Canadian dollar-denominated notes of nil (2022 – $2,810 million) and U.S. dollar-denominated notes of nil (2022 – US$2,336 million). 2 In January 2023, the Company's Mexico subsidiary fully repaid the outstanding balance and terminated its MXN$5.0 billion demand senior unsecured revolving credit facility. On August 25, 2023, TransCanada PipeLines Limited (TCPL) fully repaid and retired its 364-day $1.5 billion senior unsecured term loan bearing interest at a floating rate entered into on November 22, 2022. At December 31, 2022, Notes payable reflects short-term borrowings in Canada by TCPL and in Mexico by a wholly-owned Mexican subsidiary. At December 31, 2023, total committed revolving and demand credit facilities were $11.6 billion (2022 – $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) 2023 2022 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 2028 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 2024 US 2.5 US 2.5 US 3.0 TCPL / TCPL USA Supports commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL December 2026 US 2.5 US 2.5 US 2.5 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 3 1.0 2.1 3 Mexico subsidiary For Mexico general corporate purposes, guaranteed by TCPL Demand — — MXN 5.0 3 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, 2023, the Company was in compliance with all financial covenants. 3 Or the U.S. dollar equivalent. For the year ended December 31, 2023, the cost to maintain the above facilities was $14 million (2022 – $14 million; 2021 – $17 million).

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2023
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER at December 31 2023 2022 (millions of Canadian $) Trade payables 4,832 4,330 Fair value of derivative contracts (Note 29) 1,143 871 Regulatory liabilities (Note 14) 284 273 Keystone environmental provision 122 650 Contract liabilities (Note 6) 69 62 Class C Interests (Note 7) 19 37 Coastal GasLink contractual contribution (Notes 8, 12 and 33) — 537 Other 518 389 6,987 7,149 Keystone Environmental Provision In December 2022, a pipeline incident occurred in Washington County, Kansas on the Keystone Pipeline System. At December 31, 2022, the Company accrued an environmental liability of $650 million, before expected insurance recoveries and not including potential fines and penalties which continue to be indeterminable. At June 30, 2023, the cost estimate for the incident was adjusted to $794 million based on a review of costs and commitments incurred and, at December 31, 2023, remains unchanged. Amounts paid for the environmental remediation liability were $676 million at December 31, 2023 (December 31, 2022 – nil). The remaining balance reflected in Accounts payable and other and Other long-term liabilities on the Company’s Consolidated balance sheet was $122 million and $9 million, respectively at December 31, 2023 (December 31, 2022 – $650 million and nil, respectively). The expected recovery of the remaining estimated environmental remediation costs recorded in Other current assets and Other long-term assets were $150 million and $33 million, respectively at December 31, 2023 (December 31, 2022 – $410 million and $240 million, respectively). An additional $36 million was accrued during the year, which is expected to be recoverable from TC Energy's wholly-owned captive insurance subsidiary. This amount was recorded as an expense in Interest income and other in the Consolidated statement of income. During the year, the Company received $575 million (2022 – nil) from its insurance policies related to the costs for environmental remediation. Restoration activities are ongoing and expected to continue into 2024.

OTHER LONG-TERM LIABILITIES

OTHER LONG-TERM LIABILITIES	12 Months Ended
	Dec. 31, 2023
Deferred Costs, Noncurrent [Abstract]
OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES at December 31 2023 2022 (millions of Canadian $) Operating lease obligations (Note 11) 401 379 Fair value of derivative contracts (Note 29) 106 151 Employee post-retirement benefits (Note 28) 97 111 Asset retirement obligations 64 79 Long-term contract liabilities (Note 6) 12 32 Other 335 265 1,015 1,017

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Geographic Components of Income before Income Taxes year ended December 31 2023 2022 2021 (millions of Canadian $) Canada (446) (2,154) (292) Foreign 4,456 3,528 2,458 Income before Income Taxes 4,010 1,374 2,166 Provision for Income Taxes year ended December 31 2023 2022 2021 (millions of Canadian $) Current Canada 73 43 29 Foreign 858 372 276 931 415 305 Deferred Canada (39) (467) (327) Foreign 50 641 142 11 174 (185) Income Tax Expense 942 589 120 Reconciliation of Income Tax Expense year ended December 31 2023 2022 2021 (millions of Canadian $) Income before income taxes 4,010 1,374 2,166 Federal and provincial statutory tax rate 23.0 % 23.0 % 23.0 % Expected income tax expense 922 316 498 Income tax differential related to regulated operations (260) (174) (139) Foreign income tax rate differentials (174) (271) (230) Income from non-controlling interests and equity investments (56) (54) (70) Valuation allowance (release) 197 199 (8) Non-taxable capital (gains) and losses 196 173 — Mexico foreign exchange exposure 132 9 10 Impact of Mexico inflationary adjustments 1 24 32 Settlement of Mexico prior years' income tax assessments — 196 — U.S. minimum tax (14) 96 — Non-deductible goodwill impairment — 91 — Other (2) (16) 27 Income Tax Expense 942 589 120 Deferred Income Tax Assets and Liabilities at December 31 2023 2022 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,833 1,519 Regulatory and other deferred amounts 569 571 Unrealized foreign exchange losses on long-term debt 206 333 Other 73 193 2,681 2,616 Less: Valuation allowance 730 640 1,951 1,976 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment 6,816 6,686 Equity investments 1,115 1,152 Taxes on future revenue requirement 493 397 Financial instruments 160 126 Other 160 193 8,744 8,554 Net Deferred Income Tax Liabilities 6,793 6,578 The above deferred tax amounts have been classified on the Consolidated balance sheet as follows: at December 31 2023 2022 (millions of Canadian $) Deferred Income Tax Assets Other long-term assets (Note 16) 1,332 1,070 Deferred Income Tax Liabilities Deferred income tax liabilities 8,125 7,648 Net Deferred Income Tax Liabilities 6,793 6,578 At December 31, 2023, the Company has recognized the benefit of non-capital loss carryforwards of $6,593 million (2022 – $5,429 million) for federal and provincial purposes in Canada, which expire from 2030 to 2043. The Company has not yet recognized the benefit of capital loss carryforwards of $478 million (2022 – $251 million) for federal and provincial purposes in Canada which have no expiry date. The Company also has Ontario corporate minimum tax (CMT) credits of $140 million (2022 – $126 million), which expire from 2026 to 2043. As of December 31, 2023, the Company has not recognized the benefit of CMT credits of $22 million (2022 – $22 million). At December 31, 2023, the Company has recognized the benefit of net operating loss carryforwards of US$47 million (2022 – US$69 million) in Mexico, which expire from 2024 to 2033. TC Energy recorded an income tax valuation allowance of $730 million and $640 million against the deferred income tax asset balances at December 31, 2023 and 2022, respectively. The increase in the valuation allowance is primarily a result of the foreign exchange movement on unrecognized capital losses and the unrealized non-taxable capital losses on the Coastal GasLink equity investment. At December 31, 2023, the Company recorded a total of $358 million (2022 – $173 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, 2023. 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. As at December 31, 2023, 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. 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, 2023 by approximately $1,629 million (2022 – $1,216 million) if there had been a provision for these taxes. Income Tax Payments Income tax payments of $836 million, net of refunds, were made in 2023 (2022 – payments, net of refunds, of $394 million; 2021 – payments, net of refunds, of $371 million). Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2023 2022 2021 (millions of Canadian $) Unrecognized tax benefit at beginning of year 91 80 52 Gross increases – tax positions in prior years 9 6 5 Gross decreases – tax positions in prior years (1) — (1) Gross increases – tax positions in current year 16 7 26 Lapse of statutes of limitations (30) (2) (2) Unrecognized Tax Benefit at End of Year 85 91 80 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, 2023 reflects $3 million interest expense (2022 – $6 million; 2021 – $1 million). At December 31, 2023, the Company had accrued $21 million in interest expense (2022 – $18 million; 2021 – $12 million). The Company incurred no penalties associated with income tax uncertainties related to income tax expense for the years ended December 31, 2023, 2022 and 2021 and no penalties were accrued as at December 31, 2023, 2022 and 2021. 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 2015. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2015. Substantially all material Mexico income tax matters have been concluded for years through 2017. 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, 2023
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT at December 31 2023 2022 Maturity Dates Outstanding Interest Rate 1 Outstanding Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Medium Term Notes Canadian 2024 to 2052 15,466 4.6 % 13,966 4.5 % Senior Unsecured Notes U.S. (2023 – US$16,167; 2022 – US$15,542) 2024 to 2049 21,349 5.0 % 21,032 4.9 % 36,815 34,998 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2023 – nil; 2022 – US$200) — — 271 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2023 and 2022 – US$33) 2026 43 7.5 % 44 7.5 % 647 919 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes 2 U.S. (2023 – nil; 2022 – US$1,500) — — 2,030 4.9 % COLUMBIA PIPELINES OPERATING COMPANY LLC Senior Unsecured Notes 2 U.S. (2023 – US$6,100; 2022 – nil) 2025 to 2063 8,055 6.1 % — — COLUMBIA PIPELINES HOLDING COMPANY LLC Senior Unsecured Notes 2 U.S. (2023 – US$1,000; 2022 – nil) 2026 to 2028 1,320 6.2 % — — ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2023 and 2022 – US$1,172) 2024 to 2037 1,548 4.1 % 1,587 4.1 % TC PIPELINES, LP Senior Unsecured Notes U.S. (2023 and 2022 – US$850) 2025 to 2027 1,122 4.2 % 1,150 4.2 % at December 31 2023 2022 Maturity Dates Outstanding Interest Rate 1 Outstanding Interest Rate 1 (millions of Canadian $, unless otherwise noted) GAS TRANSMISSION NORTHWEST LLC Senior Unsecured Notes U.S. (2023 – US$375; 2022 – US$325) 2030 to 2035 495 4.4 % 440 4.3 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Unsecured Notes U.S. (2023 and 2022 – US$250) 2030 to 2031 330 2.8 % 338 2.8 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2023 – US$125; 2022 – US$146) 2028 to 2030 165 7.6 % 198 7.6 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2023 – nil; 2022 – US$34) — — 46 6.5 % TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. Senior Unsecured Term Loan U.S. (2023 – US$1,800; 2022 – nil) 2028 2,377 7.7 % — — Senior Unsecured Revolving Credit Facility U.S. (2023 – US$185; 2022 – nil) 2028 244 7.7 % — — 2,621 — 53,118 41,706 Current portion of long-term debt (2,938) (1,898) Unamortized debt discount and issue costs (312) (239) Fair value adjustments 3 108 76 49,976 39,645 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 8, 2023, US$1.5 billion senior unsecured notes were assigned from Columbia Pipelines Group, Inc. to Columbia Pipelines Operating Company LLC in advance of the October 4, 2023 sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf. Preceding this sale, US$5.6 billion of senior unsecured notes were issued. Refer to Note 24, Non-controlling interests, for additional information. 3 The fair value adjustments include $119 million (2022 – $140 million) related to the acquisition of Columbia Pipeline Group, Inc. These adjustments also include a decrease of $11 million (2022 – $64 million) related to hedged interest rate risk. Refer to Note 29, Risk management and financial instruments, for additional information. Principal Repayments At December 31, 2023, principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2024 2025 2026 2027 2028 Principal repayments on long-term debt 2,938 2,779 5,287 3,096 6,232 Long-Term Debt Issued The Company issued long-term debt over the three years ended December 31, 2023 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED May 2023 Senior Unsecured Term Loan 1 May 2026 US 1,024 Floating March 2023 Senior Unsecured Notes March 2026 2 US 850 6.20 % March 2023 Senior Unsecured Notes March 2026 2 US 400 Floating March 2023 Medium Term Notes July 2030 1,250 5.28 % March 2023 Medium Term Notes March 2026 2 600 5.42 % March 2023 Medium Term Notes March 2026 2 400 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 % October 2021 Senior Unsecured Notes October 2024 US 1,250 1.00 % October 2021 Senior Unsecured Notes October 2031 US 1,000 2.50 % June 2021 Medium Term Notes June 2024 750 Floating June 2021 Medium Term Notes June 2031 500 2.97 % June 2021 Medium Term Notes September 2047 250 4.33 % 3 COLUMBIA PIPELINES OPERATING COMPANY LLC 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 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 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM October 2021 Senior Unsecured Notes October 2031 US 125 2.68 % (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TUSCARORA GAS TRANSMISSION COMPANY August 2021 Unsecured Term Loan August 2024 US 13 Floating KEYSTONE XL SUBSIDIARIES 4 Various Project-Level Credit Facility June 2021 US 849 Floating COLUMBIA PIPELINE GROUP, INC. 5 January 2021 Unsecured Term Loan June 2022 US 4,040 Floating 1 This loan was fully repaid and retired in September 2023. Related unamortized debt issue costs of $3 million were included in Interest expense in the Consolidated statement of income. 2 Callable at par in March 2024 or at any time thereafter. 3 Reflects coupon rate on re-opening of a pre-existing Medium Term Notes (MTN) issue. The MTNs were issued at a premium to par, resulting in a re-issuance yield of 4.19 per cent. 4 In January 2021, the Company established a US$4.1 billion project-level credit facility to support the construction of the Keystone XL pipeline, which was fully guaranteed by the Government of Alberta and non-recourse to TC Energy. The availability of this credit facility was subsequently reduced to US$1.6 billion and all amounts outstanding were fully repaid by the Government of Alberta in June 2021. Refer to Note 7, Keystone XL, for additional information. 5 In December 2020, Columbia entered into a US$4.2 billion Unsecured Term Loan agreement. In January 2021, US$4.0 billion was drawn on the Unsecured Term Loan and the total availability under the loan agreement was reduced accordingly. The loan was fully repaid and retired in December 2021. On January 9, 2024, Columbia Pipelines Holding Company LLC issued US$500 million senior unsecured notes due January 2034, bearing interest at a fixed rate of 5.68 per cent. Long-Term Debt Retired/Repaid The Company retired/repaid long-term debt over the three years ended December 31, 2023 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED October 2023 Senior Unsecured Notes US 625 3.75 % September 2023 Senior Unsecured Notes 1 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 % November 2021 Medium Term Notes 500 3.65 % January 2021 Debentures US 400 9.88 % TUSCARORA GAS TRANSMISSION COMPANY November 2023 Unsecured Term Loan US 32 Floating NOVA GAS TRANSMISSION LTD. April 2023 Debentures US 200 7.88 % TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. Various Senior Unsecured Revolving Credit Facility US 315 Floating COLUMBIA PIPELINE GROUP, INC. December 2021 Unsecured Term Loan 2 US 4,040 Floating NORTH BAJA PIPELINE, LLC December 2021 Unsecured Term Loan US 50 Floating TC PIPELINES, LP November 2021 Unsecured Term Loan US 450 Floating March 2021 Senior Unsecured Notes US 350 4.65 % ANR PIPELINE COMPANY November 2021 Senior Unsecured Notes US 300 9.63 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP November 2021 Senior Unsecured Notes US 10 9.09 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM October 2021 Unsecured Loan Facility US 93 Floating KEYSTONE XL SUBSIDIARIES 3 June 2021 Project-Level Credit Facility US 849 Floating 1 In May 2023, the Company entered into a US$1,024 million senior unsecured term loan and the full amount was drawn. The loan was fully repaid and retired in September 2023. Related unamortized debt issue costs of $3 million were included in Interest expense in the Consolidated statement of income. 2 In December 2020, Columbia entered into a US$4.2 billion Unsecured Term Loan agreement. In January 2021, US$4.0 billion was drawn on the Unsecured Term Loan and the total availability under the loan agreement was reduced accordingly. The loan was fully repaid and retired in December 2021. Related unamortized debt issue costs of $5 million were included in Interest expense in the Consolidated statement of income for the year ended December 31, 2021. 3 In June 2021, in accordance with the terms of the guarantee, the Government of Alberta repaid the US$849 million outstanding balance under the Keystone XL project-level credit facility bearing interest at a floating rate, subsequent to which it was terminated, resulting in no cash impact to TC Energy. Refer to Note 7, Keystone XL, for additional information. In March 2021, the Company's subsidiary, TC PipeLines, LP, terminated its US$500 million Unsecured Loan Facility bearing interest at a floating rate on which no amount was outstanding. Interest Expense year ended December 31 2023 2022 2021 (millions of Canadian $) Interest on long-term debt 2,562 1,883 1,841 Interest on junior subordinated notes 617 543 453 Interest on short-term debt 165 153 10 Capitalized interest (187) (27) (22) Amortization and other financial charges 1 106 36 78 3,263 2,588 2,360 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 $2,931 million in 2023 (2022 – $2,478 million; 2021 – $2,299 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, 2023
Junior Subordinated Notes [Abstract]
JUNIOR SUBORDINATED NOTES	JUNIOR SUBORDINATED NOTES at December 31 2023 2022 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 1,320 6.5 % 1,353 6.2 % US$750 issued 2015 at 5.88% 3,4 2075 990 7.8 % 1,015 7.4 % US$1,200 issued 2016 at 6.13% 3,4 2076 1,585 8.3 % 1,624 8.0 % US$1,500 issued 2017 at 5.55% 3,4 2077 1,981 7.5 % 2,030 7.1 % $1,500 issued 2017 at 4.90% 3,4 2077 1,500 7.0 % 1,500 6.8 % US$1,100 issued 2019 at 5.75% 3,4 2079 1,453 8.0 % 1,488 7.6 % $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 1,056 7.1 % 1,083 7.2 % 10,385 10,593 Unamortized debt discount and issue costs (98) (98) 10,287 10,495 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. In March 2021, the Trust issued $500 million of Trust Notes – Series 2021-A to investors with a fixed interest rate of 4.20 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 $500 million of junior subordinated notes of TCPL at an initial fixed rate of 4.45 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 2031 until March 2051 to the then Five-Year Government of Canada Yield, as defined in the document governing the subordinated notes, plus 3.316 per cent per annum; from March 2051 until March 2081, the interest rate will reset every five years to the then Five-Year Government of Canada Yield plus 4.066 per cent per annum. The junior subordinated notes are callable at TCPL's option at any time from December 4, 2030 to March 4, 2031 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, 2023
Foreign Currency [Abstract]
FOREIGN EXCHANGE (GAINS) LOSSES, NET	FOREIGN EXCHANGE (GAINS) LOSSES, NET year ended December 31 2023 2022 2021 (millions of Canadian $) Derivative instruments held for trading (Note 29) (401) 151 (37) Other 81 34 27 (320) 185 (10)

NON-CONTROLLING INTERESTS

NON-CONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2023
Noncontrolling Interest [Abstract]
NON-CONTROLLING INTERESTS	NON-CONTROLLING INTERESTS Disposition of Equity Interest Columbia Gas and Columbia Gulf On October 4, 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. Preceding the close of the equity sale, on August 8, 2023, Columbia Pipelines Operating Company LLC and Columbia Pipelines Holding Company LLC issued US$4.6 billion and US$1.0 billion of long-term, senior unsecured debt, respectively, with all proceeds paid to TC Energy. The net proceeds from the offerings and equity sale were used to repay existing intercompany and third-party debt. Refer to Note 21, Long-term debt, for additional information. Acquisitions Texas Wind Farms On March 15, 2023 and June 14, 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. TC PipeLines, LP On March 3, 2021, the Company acquired all the outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy or its affiliates in exchange for TC Energy common shares. Under this transaction, TC PipeLines, LP common unitholders received 0.70 TC Energy common shares for each issued and outstanding publicly-held TC PipeLines, LP common unit representing, in aggregate, 37,955,093 TC Energy common shares. As a result, TC PipeLines, LP became an indirect, wholly-owned subsidiary of TC Energy. As the Company controlled TC PipeLines, LP, this acquisition was accounted for as an equity transaction with the following impact reflected on the Consolidated balance sheet: (millions of Canadian $) March 3, 2021 Common shares 2,063 Additional paid-in-capital (398) Accumulated other comprehensive income (loss) 353 Non-controlling interests (1,563) Deferred income tax liabilities (443) Other (12) 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, 2023 Income (Loss) Attributable to Non-Controlling Interests year ended December 31 at December 31 2023 2022 2021 2023 2022 Columbia Gas and Columbia Gulf 40.0 % 143 — — 9,167 — Portland Natural Gas Transmission System 38.3 % 41 37 30 106 126 Texas Wind Farms 100% 1 (38) — — 182 — TC PipeLines, LP nil 2 — — 60 — — Redeemable non-controlling interest (Note 7) nil — — 1 — — 146 37 91 9,455 126 1 Non-controlling interests in the Texas Wind Farms comprises Class A Membership Interests.

COMMON SHARES

COMMON SHARES	12 Months Ended
	Dec. 31, 2023
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, 2021 940,064 24,488 Acquisition of TC PipeLines, LP, net of transaction costs (Note 24) 37,955 2,063 Exercise of options 2,797 165 Outstanding at December 31, 2021 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 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 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. Acquisition of TC PipeLines, LP On March 3, 2021, TC Energy issued 37,955,093 common shares to acquire all the outstanding publicly-held common units of TC PipeLines, LP. Refer to Note 24, Non-controlling interests, for additional information. Basic and Diluted Net Income (Loss) per Common Share Net income (loss) per common share is calculated by dividing Net income (loss) attributable to common shares 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 (millions) 2023 2022 2021 Basic 1,030 995 973 Diluted 1,030 996 974 Stock Options Number of Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (thousands) (years) Options outstanding at January 1, 2023 6,109 $63.86 Options granted 1,933 $56.66 Options exercised (62) $48.44 Options forfeited/expired (544) $60.60 Options Outstanding at December 31, 2023 7,436 $62.36 4.1 Options Exercisable at December 31, 2023 4,375 $64.47 3.0 At December 31, 2023, an additional 2,267,871 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. 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 2023 2022 2021 Weighted average fair value $7.88 $8.24 $7.39 Expected life (years) 1 5.1 5.4 5.4 Interest rate 2.9 % 1.6 % 0.5 % Volatility 2 24 % 22 % 25 % Dividend yield 6.3 % 5.5 % 6.0 % 1 Expected life is based on historical exercise activity. 2 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 $9 million in 2023 (2022 – $10 million; 2021 – $12 million). At December 31, 2023, unrecognized compensation costs related to non-vested stock options were $12 million. The cost is expected to be fully recognized over a weighted average period of two years. The following table summarizes additional stock option information: year ended December 31 2023 2022 2021 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised — 33 28 Total fair value of options that have vested 76 89 110 Total options vested 1.5 million 1.6 million 1.9 million As at December 31, 2023, the aggregate intrinsic values of the total options exercisable and the total options outstanding were nil. Shareholder Rights Plan TC Energy's Shareholder Rights Plan is designed to provide the Board of Directors (Board) 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, 2023
Preferred Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
PREFERRED SHARES	PREFERRED SHARES at December 31, 2023 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 2023 2022 2021 (thousands) (millions of Canadian $) Cumulative First Preferred Shares Series 1 14,577 3.48 % $0.86975 $25.00 December 31, 2024 Series 2 360 360 360 Series 2 7,423 Floating 4 Floating $25.00 December 31, 2024 Series 1 179 179 179 Series 3 9,997 1.69 % $0.4235 $25.00 June 30, 2025 Series 4 246 246 246 Series 4 4,003 Floating 4 Floating $25.00 June 30, 2025 Series 3 97 97 97 Series 5 12,071 1.95 % 5 $0.48725 $25.00 January 30, 2026 Series 6 294 294 294 Series 6 1,929 Floating 4 Floating $25.00 January 30, 2026 Series 5 48 48 48 Series 7 24,000 3.90 % $0.97575 $25.00 April 30, 2024 Series 8 589 589 589 Series 9 18,000 3.76 % $0.9405 $25.00 October 30, 2024 Series 10 442 442 442 Series 11 10,000 3.35 % $0.83775 $25.00 November 28, 2025 Series 12 244 244 244 Series 15 — — — — — — — — 988 2,499 2,499 3,487 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 floating quarterly dividend rate for the Series 2 preferred shares is 6.96 per cent for the period starting December 29, 2023 to, but excluding, March 28, 2024. The floating quarterly dividend rate for the Series 4 preferred shares is 6.32 per cent for the period starting December 29, 2023 to, but excluding, March 28, 2024. The floating quarterly dividend rate for the Series 6 preferred shares is 6.69 per cent for the period starting October 30, 2023 to, but excluding, January 30, 2024. These rates will reset each quarter going forward. 5 The fixed rate dividend for Series 5 preferred shares decreased from 2.26 per cent to 1.95 per cent on January 30, 2021 and is due to reset on every fifth anniversary thereafter. 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 and Series 6 preferred shares. The holders of Series 2, Series 4 and Series 6 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 and Series 6 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 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. In May 2021, TC Energy redeemed all 20,000,000 issued and outstanding Series 13 preferred shares at a redemption price of $25.00 per share and paid the final quarterly dividend of $0.34375 per Series 13 preferred share for the period up to but excluding May 31, 2021. The Company used the proceeds from the March 2021 issuance of $500 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, 2023
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, 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 year ended December 31, 2021 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 (100) (8) (108) Change in fair value of net investment hedges (3) 1 (2) Change in fair value of cash flow hedges (13) 3 (10) Reclassification to net income of (gains) losses on cash flow hedges 68 (13) 55 Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans 208 (50) 158 Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans 20 (6) 14 Other comprehensive income (loss) on equity investments 714 (179) 535 Other Comprehensive Income (Loss) 894 (252) 642 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, 2021 (1,273) (143) (285) (738) (2,439) Other comprehensive income (loss) before reclassifications 1 (98) (11) 158 506 555 Amounts reclassified from AOCI — 55 14 28 97 Net current period other comprehensive income (loss) (98) 44 172 534 652 Acquisition of TC PipeLines, LP 2 362 (13) — 4 353 AOCI balance at December 31, 2021 (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 3 — 74 — (16) 58 Net current period other comprehensive income (loss) (231) 74 (11) (211) (379) Impact of non-controlling interest 4 (527) — — — (527) AOCI balance at December 31, 2023 (317) (35) (55) 456 49 1 Other comprehensive income(loss) before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling 2 Represents the AOCI attributable to non-controlling interests of TC PipeLines, LP which was reclassified to AOCI on the Consolidated balance sheet upon completion of the acquisition of all the outstanding publicly-held common units of TC PipeLines, LP on March 3, 2021. Refer to Note 24, Non-controlling interests, for additional information. 3 Losses 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 $4 million ($3 million, net of tax) at December 31, 2023. 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 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 24, Non-controlling interests, 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 Affected Line Item in the Consolidated Statement of Income 1 2023 2022 2021 (millions of Canadian $) Cash flow hedges Commodities (85) (47) (22) Revenues (Power and Energy Solutions) Interest rate (12) (16) (46) Interest expense (97) (63) (68) Total before tax 23 21 13 Income tax (expense) recovery (74) (42) (55) Net of tax Pension and other post-retirement benefit plan adjustments Amortization of actuarial gains (losses) — (11) (22) Plant operating costs and other 2 Settlement gain (loss) — 2 2 Plant operating costs and other 2 — (9) (20) Total before tax — 3 6 Income tax (expense) recovery — (6) (14) Net of tax Equity investments Equity income (loss) 22 4 (37) Income (loss) from equity investments (6) (1) 9 Income tax (expense) recovery 16 3 (28) 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 28, Employee post-retirement benefits, for additional information.

EMPLOYEE POST-RETIREMENT BENEFI

EMPLOYEE POST-RETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2023
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, 2023 (2022 – nine years; 2021 – 10 years). The Company also provides its employees with savings plans in Canada and 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, 2023 (2022 – 12 years and 2021 – 11 years). In 2023, the Company expensed $64 million (2022 – $64 million and 2021 – $58 million) for the savings and DC Plans. Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2023 2022 2021 (millions of Canadian $) DB Plans 28 78 105 Other post-retirement benefit plans 9 8 8 Savings and DC Plans 64 64 58 101 150 171 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, 2023 was $244 million (2022 – $322 million; 2021 – $322 million). The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2023 and the next required valuation is at January 1, 2024. 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. In mid-2021, the Company offered a one-time Voluntary Retirement Program (VRP) to eligible employees. Participants in the program retired by December 31, 2021 and received a transition payment along with existing retirement benefits. In 2021, the Company expensed $81 million mainly related to VRP transition payments which were included in Plant operating costs and other. In addition, $18 million was recorded in Revenues related to costs that are recoverable through regulatory and tolling structures on a flow-through basis. As a result of employee participation in the VRP in 2021, a settlement and curtailment occurred for the U.S. DB Plan and a curtailment occurred in the U.S. OPEB Plan. The impact of these amounts was determined using actuarial assumptions consistent with those employed at December 31, 2021. The settlement gain decreased the U.S. DB Plan's unrealized actuarial gain by $2 million which was included in OCI, while the curtailment gain decreased the U.S. DB Plan's benefit obligation by $5 million, both of which were recorded in net benefit cost in 2021. The curtailment loss decreased the OPEB Plan's unrealized actuarial gain by $3 million which was included in OCI and increased the OPEB Plan obligation by $3 million, resulting in no adjustment to net benefit cost in 2021. The Company's funded status was comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2023 2022 2023 2022 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,081 4,027 310 419 Service cost 93 145 3 5 Interest cost 158 125 16 13 Employee contributions 7 6 2 2 Benefits paid (185) (324) (44) (24) Actuarial (gain) loss 219 (949) 2 (120) Foreign exchange rate changes (17) 51 (4) 15 Benefit obligation – end of year 3,356 3,081 285 310 Change in Plan Assets Plan assets at fair value – beginning of year 3,481 4,145 354 431 Actual return on plan assets 385 (483) 24 (89) Employer contributions 2 28 78 9 8 Employee contributions 7 6 2 2 Benefits paid (185) (324) (23) (24) Foreign exchange rate changes (19) 59 (8) 26 Plan assets at fair value – end of year 3,697 3,481 358 354 Funded Status – Plan Surplus 341 400 73 44 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 The Company reduced letters of credit by $78 million in the Canadian DB Plan (2022 – nil) for funding purposes. The actuarial loss realized on the defined benefit plan obligation is primarily attributable to a decrease in the weighted average discount rate from 5.15 per cent in 2022 to 4.75 per cent in 2023. The actuarial loss realized on the OPEB Plan obligation is primarily due to a decrease in the weighted average discount rate from 5.45 per cent in 2022 to 5.10 per cent in 2023. 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 $) 2023 2022 2023 2022 Other long-term assets (Note 16) 341 400 177 163 Accounts payable and other — — (7) (8) Other long-term liabilities (Note 19) — — (97) (111) 341 400 73 44 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 $) 2023 2022 2023 2022 Projected benefit obligation 1 — — (104) (119) Plan assets at fair value — — — — Funded Status – Plan Deficit — — (104) (119) 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 2023 2022 (millions of Canadian $) Accumulated benefit obligation (3,090) (2,880) Plan assets at fair value 3,697 3,481 Funded Status – Plan Surplus 607 601 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, 2023 and December 31, 2022. The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: at December 31 Percentage of Target Allocations 2023 2022 2023 Fixed income securities 41 % 38 % 30% to 50% Equity securities 44 % 44 % 30% to 55% Other investments 15 % 18 % 10% to 25% 100 % 100 % Fixed income and equity securities include the Company's debt and common shares as follows: at December 31 Percentage of (millions of Canadian $) 2023 2022 2023 2022 Fixed income securities 7 7 0.2 % 0.2 % Equity securities 2 3 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 29, 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 $) 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 Asset Category Cash and Cash Equivalents 68 55 1 1 — — 69 56 2 1 Equity Securities: Canadian 121 117 — — — — 121 117 3 3 U.S. 965 897 — — — — 965 897 24 24 International 167 172 187 172 — — 354 344 9 9 Global — — 74 75 — — 74 75 2 2 Emerging 54 50 140 127 — — 194 177 5 5 Fixed Income Securities: Canadian Bonds: Federal — — 266 221 — — 266 221 7 6 Provincial — — 314 249 — — 314 249 8 6 Municipal — — 16 12 — — 16 12 — — Corporate — — 143 108 — — 143 108 4 3 U.S. Bonds: Federal 185 177 240 158 — — 425 335 10 9 Municipal — — 1 1 — — 1 1 — — Corporate 312 345 74 94 — — 386 439 10 11 International: Government 4 5 11 6 — — 15 11 — — Corporate — — 83 58 — — 83 58 2 1 Mortgage backed 43 36 17 1 — — 60 37 1 1 Net forward contracts — — (131) (78) — — (131) (78) (4) (2) Other Investments: Real estate — — — — 283 336 283 336 7 9 Infrastructure — — — — 269 296 269 296 7 8 Private equity funds — — — — 10 — 10 — — — Funds held on deposit 138 144 — — — — 138 144 3 4 2,057 1,998 1,436 1,205 562 632 4,055 3,835 100 100 The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Balance at December 31, 2021 565 Purchases and sales 52 Realized and unrealized gains (losses) 15 Balance at December 31, 2022 632 Purchases and sales (76) Realized and unrealized gains (losses) 6 Balance at December 31, 2023 562 In 2024, the Company's expects to make funding contributions of $6 million for the other post-retirement benefit plans, approximately $70 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 2024. The following are estimated future benefit payments, which reflect expected future service: at December 31 Other Post-Retirement Benefits (millions of Canadian $) Pension Benefits 2024 204 23 2025 207 23 2026 211 23 2027 214 22 2028 216 22 2029 to 2033 1,127 104 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, 2023. 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 2023 2022 2023 2022 Discount rate 4.75 % 5.15 % 5.10 % 5.45 % Rate of compensation increase 3.20 % 3.30 % — — 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 2023 2022 2021 2023 2022 2021 Discount rate 5.15 % 3.05 % 2.70 % 5.45 % 3.10 % 2.80 % Expected long-term rate of return on plan assets 6.45 % 6.10 % 6.15 % 4.50 % 3.25 % 3.00 % Rate of compensation increase 3.25 % 3.00 % 2.60 % — — — 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 5.95 per cent weighted-average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2024 measurement purposes. The rate was assumed to decrease gradually to 4.80 per cent by 2030 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 $) 2023 2022 2021 2023 2022 2021 Service cost 1 93 145 171 3 5 6 Other components of net benefit cost 1 Interest cost 158 125 119 16 13 12 Expected return on plan assets (234) (239) (234) (16) (14) (13) Amortization of actuarial loss — 10 23 — 1 2 Amortization of regulatory asset — 12 27 — 1 2 Curtailment gain — — (5) — — — Settlement gain – AOCI — (2) (2) — — — (76) (94) (72) — 1 3 Net Benefit Cost Recognized 17 51 99 3 6 9 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 2023 2022 2021 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Net loss 71 6 38 24 147 5 Pre-tax amounts recognized in OCI were as follows: year ended December 31 2023 2022 2021 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Amortization of net gain (loss) from AOCI to net income — — (10) (1) (23) (2) Curtailment — — — — — 3 Settlement — — 2 — 2 — Funded status adjustment 33 (18) (101) 20 (190) (18) 33 (18) (109) 19 (211) (17)

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2023
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 liquids marketing business, TC Energy enters into pipeline and storage terminal capacity contracts as well as crude oil purchase and sale agreements. The Company fixes a portion of the exposure on these contracts by entering into financial instruments to manage variable price fluctuations that arise from physical liquids transactions • 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, crude oil 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. 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 the Company’s asset portfolio against a range of future pricing and supply and demand outcomes as part of the Company’s strategic planning process. TC Energy’s exposure to climate change-related transition risks and resulting policy changes is managed through the Company’s 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. As the Company's U.S. dollar-denominated operations continue to grow, this exposure increases. 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 from equity investments and Income tax expense. 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 2023 2022 Fair 1,2 Notional Amount Fair 1,2 Notional Amount (millions of Canadian $, unless otherwise noted) U.S. dollar foreign exchange options (maturing 2024) 8 US 1,000 (22) US 3,600 U.S. dollar cross-currency interest rate swaps (maturing 2024 to 2025) 3 2 US 200 (5) US 300 10 US 1,200 (27) US 3,900 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2023, Net income (loss) includes net realized gains of less than $1 million (2022 – gains of $1 million) related to the interest component of cross-currency swap settlements which are reported within Interest expense. The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2023 2022 (millions of Canadian $, unless otherwise noted) Notional amount 27,800 (US 21,100) 32,500 (US 24,000) Fair value 26,600 (US 20,200) 30,800 (US 22,700) Counterparty Credit Risk TC Energy's exposure to counterparty credit risk includes its cash and cash equivalents, accounts receivable and certain contractual recoveries, 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, 2023, the Company recorded a $73 million ECL recovery (2022 – an expense of $149 million; 2021 – nil) with respect to the net investment in leases associated with the in-service TGNH pipelines and a $10 million ECL recovery (2022 – $14 million expense; 2021 – nil) 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, 2023 and 2022. At December 31, 2023 and 2022, 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. Certain non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Other current assets, Restricted investments, Net investment in leases, 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. Each of these instruments are classified in Level II of the fair value hierarchy, except for the Company's LMCI equity securities which are classified in Level I of the fair value hierarchy. 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 2023 2022 Carrying Amount Fair Value Carrying Fair (millions of Canadian $) Long-term debt, including current portion (Note 21) 1,2 (52,914) (52,815) (41,543) (39,505) Junior subordinated notes (Note 22) (10,287) (9,217) (10,495) (9,415) (63,201) (62,032) (52,038) (48,920) 1 Long-term debt is recorded at amortized cost, except for US$2.0 billion (2022 – US$1.6 billion) that is attributed to hedged risk and recorded at fair value. 2 Net income (loss) for 2023 included unrealized losses of $53 million (2022 – unrealized gains of $64 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$2.0 billion of long-term debt at December 31, 2023 (2022 – US$1.6 billion). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments. 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 2023 2022 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 1 35 — 54 Maturing within 1-5 years 8 291 — 106 Maturing within 5-10 years 1,340 — 1,153 — Maturing after 10 years 102 — 77 — Fair value of equity securities 2,4 883 — 749 — 2,334 326 1,979 160 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 2023 2022 2021 (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) 190 13 (244) (7) 45 (2) Net realized gains (losses) 3 (34) — (32) — 3 — 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 assets or regulatory liabilities 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, 2023 Cash Flow Hedges Fair Value Hedges Net Held for Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 9) Commodities 2 9 — — 1,195 1,204 Foreign exchange — — 10 71 81 9 — 10 1,266 1,285 Other long-term assets (Note 16) Commodities 2 3 — — 86 89 Foreign exchange — — — 30 30 Interest rate — 36 — — 36 3 36 — 116 155 Total Derivative Assets 12 36 10 1,382 1,440 Accounts payable and other (Note 18) Commodities 2 (1) — — (1,110) (1,111) Foreign exchange — — — (14) (14) Interest rate — (18) — — (18) (1) (18) — (1,124) (1,143) Other long-term liabilities (Note 19) Commodities 2 — — — (75) (75) Foreign exchange — — — (2) (2) Interest rate — (29) — — (29) — (29) — (77) (106) Total Derivative Liabilities (1) (47) — (1,201) (1,249) Total Derivatives 11 (11) 10 181 191 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. The balance sheet classification of the fair value of derivative instruments was as follows: at December 31, 2022 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 9) Commodities 2 — — — 597 597 Foreign exchange — — 6 11 17 — — 6 608 614 Other long-term assets (Note 16) Commodities 2 — — — 62 62 Foreign exchange — — 2 15 17 Interest rate — 12 — — 12 — 12 2 77 91 Total Derivative Assets — 12 8 685 705 Accounts payable and other (Note 18) Commodities 2 (72) — — (584) (656) Foreign exchange — — (31) (158) (189) Interest rate — (26) — — (26) (72) (26) (31) (742) (871) Other long-term liabilities (Note 19) Commodities 2 (2) — — (75) (77) Foreign exchange — — (4) (20) (24) Interest rate — (50) — — (50) (2) (50) (4) (95) (151) Total Derivative Liabilities (74) (76) (35) (837) (1,022) Total Derivatives (74) (64) (27) (152) (317) 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. 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 $) 2023 2022 2023 2022 Long-term debt (2,630) (2,101) 11 64 1 At December 31, 2023 and 2022, adjustments for discontinued hedging relationships included in these balances were 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, 2023 Power Natural Gas Liquids Foreign Exchange Interest Rate Net sales (purchases) 1,2 9,209 50 (7) — — Millions of U.S. dollars — — — 4,978 2,000 Millions of Mexican pesos — — — 20,000 — Maturity dates 2024-2044 2024-2029 2024 2024-2026 2030-2034 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively. 2 In 2023, the Company entered into contracts to sell 50 MW of power commencing in 2025 with terms ranging from 15 to 20 years and provided from specified renewable sources in the Province of Alberta. at December 31, 2022 Power Natural Gas Liquids Foreign Exchange Interest Rate Net sales (purchases) 1 673 (96) 11 — — Millions of U.S. dollars — — — 5,997 1,600 Millions of Mexican pesos — — — 9,747 — Maturity dates 2023-2026 2023-2027 2023-2024 2023-2026 2030-2032 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, 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 2023 2022 2021 (millions of Canadian $) Derivative Instruments Held for Trading 1 Unrealized gains (losses) in the year Commodities 96 14 9 Foreign exchange (Note 23) 246 (149) (203) Realized gains (losses) in the year Commodities 811 759 287 Foreign exchange (Note 23) 155 (2) 240 Derivative Instruments in Hedging Relationships 2 Realized gains (losses) in the year Commodities (2) (73) (44) Interest rate (43) (3) (32) 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. 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. 2 In 2023, there were no gains or losses included in Net Income (loss) relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur (2022 – nil; 2021 – realized loss of $10 million). Derivatives in cash flow hedging relationships The components of OCI (Note 27) 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 2023 2022 2021 (millions of Canadian $, pre-tax) Gains (losses) in fair value of derivative instruments recognized in OCI 1 Commodities — (94) (35) Interest rate — 36 22 — (58) (13) 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 2023 2022 2021 (millions of Canadian $) Fair Value Hedges Interest rate contracts 1 Hedged items (98) (30) — Derivatives designated as hedging instruments (43) (1) — Cash Flow Hedges Reclassification of gains (losses) on derivative instruments from AOCI to Net income (loss) 2,3 Commodity contracts 4 (85) (47) (22) Interest rate contracts 1 (12) (16) (46) 1 Presented within Interest expense in the Consolidated statement of income. 2 Refer to Note 27, 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. 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, 2023 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 1,293 (1,099) 194 Foreign exchange 111 (16) 95 Interest rate 36 (5) 31 1,440 (1,120) 320 Derivative Instrument Liabilities Commodities (1,186) 1,099 (87) Foreign exchange (16) 16 — Interest rate (47) 5 (42) (1,249) 1,120 (129) 1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2022 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 659 (591) 68 Foreign exchange 34 (33) 1 Interest rate 12 (4) 8 705 (628) 77 Derivative Instrument Liabilities Commodities (733) 591 (142) Foreign exchange (213) 33 (180) Interest rate (76) 4 (72) (1,022) 628 (394) 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 $149 million and letters of credit of $83 million at December 31, 2023 (2022 – $138 million and $68 million, respectively) to its counterparties. At December 31, 2023, the Company held less than $1 million in cash collateral and $15 million in letters of credit (2022 – less than $1 million and $10 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, 2023, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $3 million (2022 – $19 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, 2023, 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, 2023 Quoted Prices in Active Markets Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets Commodities 1,054 229 10 1,293 Foreign exchange — 111 — 111 Interest rate — 36 — 36 Derivative Instrument Liabilities Commodities (1,002) (163) (21) (1,186) Foreign exchange — (16) — (16) Interest rate — (47) — (47) 52 150 (11) 191 1 There were no transfers from Level II to Level III for the year ended December 31, 2023. In 2023, the Company entered into contracts to sell 50 MW of power commencing in 2025 with terms ranging from 15 to 20 years and 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, 2022 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 515 142 2 659 Foreign exchange — 34 — 34 Interest rate — 12 — 12 Derivative Instrument Liabilities Commodities (478) (242) (13) (733) Foreign exchange — (213) — (213) Interest rate — (76) — (76) 37 (343) (11) (317) 1 There were no transfers from Level II to Level III for the year ended December 31, 2022. 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) 2023 2022 Balance at beginning of year (11) (6) Net gains (losses) included in Net income (loss) (2) (10) Net gains (losses) included in OCI — (3) Transfers out of Level III 2 7 Settlements — 1 Balance at End of Year 1 (11) (11) 1 Revenues .

CHANGES IN OPERATING WORKING CA

CHANGES IN OPERATING WORKING CAPITAL	12 Months Ended
	Dec. 31, 2023
CHANGES IN OPERATING WORKING CAPITAL
CHANGES IN OPERATING WORKING CAPITAL	CHANGES IN OPERATING WORKING CAPITAL year ended December 31 2023 2022 2021 (millions of Canadian $) (Increase) decrease in Accounts receivable (394) (575) (925) (Increase) decrease in Inventories (56) (190) (93) (Increase) decrease in Other current assets 618 118 (141) Increase (decrease) in Accounts payable and other (206) (83) 890 Increase (decrease) in Accrued interest 245 91 (18) (Increase) Decrease in Operating Working Capital 207 (639) (287)

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS U.S. Natural Gas Pipelines Disposition of Equity Interest On October 4, 2023, the Company completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf for $5.3 billion (US$3.9 billion). 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. Liquids Pipelines Northern Courier In November 2021, TC Energy completed the sale of its remaining 15 per cent equity interest in Northern Courier to a third party for gross proceeds of approximately $35 million resulting in a pre-tax gain of $13 million ($19 million after tax). The pre-tax gain was included in Net gain(loss) on sale of assets in the Consolidated statement of income. Power and Energy Solutions Texas Wind Farms

COMMITMENTS, CONTINGENCIES AND

COMMITMENTS, CONTINGENCIES AND GUARANTEES	12 Months Ended
	Dec. 31, 2023
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 2023 were $397 million (2022 – $362 million; 2021 – $239 million). The Company has entered into PPAs with solar and wind-power generating facilities ranging from 2024 to 2038 that require the purchase of generated energy and associated environmental attributes. At December 31, 2023, the total planned capacity secured under the PPAs is approximately 800 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, 2023, TC Energy had approximately $2.1 billion of capital expenditure commitments, primarily consisting of: • $0.3 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with ANR and other pipeline projects • $1.3 billion for its Mexico natural gas pipelines related to construction of the Southeast Gateway pipeline. Contingencies TC Energy is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2023, the Company had accrued approximately $19 million (2022 – $20 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 amounts involved in such proceedings are not reasonably estimable as the final outcome of such legal proceedings cannot be predicted with certainty. 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, for which the claims are material and there is a reasonable possibility of loss, but have not been assessed as probable and a reasonable estimate of loss cannot be made, 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. 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: SA Energy Group Coastal GasLink LP is in arbitration with SA Energy Group (SAEG), which is one of the prime construction contractors on the Coastal GasLink pipeline. While still engaged as prime contractor, SAEG filed a request to arbitrate in February 2022, seeking damages for incremental costs resulting from alleged project delays. In order to mitigate cost, schedule and environmental risk while the project was in active construction, Coastal GasLink LP advanced without prejudice payments to SAEG which Coastal GasLink LP now seeks to recover via set off. By agreement among the parties, the scope of the arbitration is limited to damages for project work completed prior to December 29, 2022. In November 2023, SAEG filed materials purporting to seek damages in excess of $1.1 billion. Coastal GasLink LP continues to dispute the merits of SAEG’s claims and to assert its right to set off. Arbitration is scheduled to proceed in late 2024. At December 31, 2023, the final outcome of this matter cannot be reasonably estimated. 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 November 2023, PAPC purports to seek at least $428 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 $1.2 billion. Arbitration is scheduled to proceed in late 2024. At December 31, 2023, the final outcome of this matter cannot be reasonably estimated. Separately, Coastal GasLink LP has sought to draw down 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 has 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, which is the subject of further court proceedings. Keystone XL In 2021, TC Energy filed a Request for Arbitration to formally initiate a legacy North American Free Trade Agreement (NAFTA) claim to recover economic damages resulting from the revocation of the Presidential Permit for the Keystone XL pipeline project. In 2022, the International Centre for Settlement of Investment Disputes formally constituted a tribunal to hear TC Energy's request for arbitration under NAFTA. In April 2023, the tribunal suspended the proceeding, granting a request from the U.S. Department of State to decide the jurisdictional grounds of the case as a preliminary matter. A hearing on the jurisdictional matter is set to occur in second quarter of 2024. In April 2023, the Government of Alberta filed its own request for arbitration, which will proceed separately from the Company's claim. Termination activities undertaken in 2023, including asset dispositions and preservation, will continue through the first half of 2024. The Company will continue to coordinate with regulators, stakeholders and Indigenous groups to meet its environmental and regulatory commitments. 2016 Columbia Pipeline Acquisition Lawsuit In 2023, the Delaware Chancery 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. The Court awarded US$1 per share in damages to the plaintiffs and total damages, which is presently estimated at US$400 million plus statutory interest. Post-trial briefing and argument has concluded and a decision from the Court allocating liability as between TC Energy and the CPG executives is expected sometime in the first half of 2024. Until the allocation of damages is known, the amount that TC Energy is liable for cannot be reasonably estimated, therefore, the Company has not accrued a provision for this claim at December 31, 2023. Management expects to proceed with an appeal following the Court’s determination of total damages and TC Energy’s allocated share. 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 construction services and the payment of liabilities. 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 2023 2022 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas Renewable to 2053 97 — 100 — Bruce Power Renewable to 2065 88 — 88 — Other jointly-owned entities to 2043 80 3 81 3 265 3 269 3 1 TC Energy's share of the potential estimated current or contingent exposure.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2023
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 $) 2023 1 2022 ASSETS Current Assets Cash and cash equivalents 190 60 Accounts receivable 476 98 Inventories 90 32 Other current assets 49 14 805 204 Plant, Property and Equipment 27,649 3,997 Equity Investments 823 748 Regulatory Assets 12 — Goodwill 439 449 29,728 5,398 LIABILITIES Current Liabilities Accounts payable and other 1,135 234 Accrued interest 210 18 Current portion of long-term debt 28 31 1,373 283 Regulatory Liabilities 280 78 Other Long-Term Liabilities 56 1 Deferred Income Tax Liabilities 22 16 Long-Term Debt 11,388 2,136 13,119 2,514 1 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 24, Non-controlling interests, and Note 31, 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 $) 2023 2022 Balance Sheet Exposure Equity investments Bruce Power 6,241 5,783 Pipeline equity investments and other 1,411 1,148 Off-Balance Sheet Exposure 1 Bruce Power 1,538 2,025 Coastal GasLink 2 855 3,300 Pipeline equity investments 58 58 Maximum exposure to loss 10,103 12,314 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. At December 31, 2023, the total capacity committed by TC Energy under this subordinated loan agreement was $3,375 million (December 31, 2022 – $1,262 million). In the year ended December 31, 2023, $2,520 million was drawn on the subordinated loan, reducing the Company's funding commitment under the subordinated loan agreement to $855 million. Refer to Note 8, Coastal GasLink, for further information.

SUBSEQUENT EVENT

SUBSEQUENT EVENT	12 Months Ended
	Dec. 31, 2023
Subsequent Events [Abstract]
SUBSEQUENT EVENT	SUBSEQUENT EVENT]

ACCOUNTING POLICIES (Policies)

ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2023
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. 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 the estimate or judgment is made or are subjective. These estimates and judgments include, but are not limited to: • fair value of TC Energy’s equity investment in Coastal GasLink LP (Note 8) • assessment of goodwill impairment indicators and fair value of reporting units that contain goodwill (Note 15) • estimates and judgments used in measuring the fair value of Columbia Gas Transmission, LLC (Columbia Gas) and Columbia Gulf Transmission, LLC (Columbia Gulf) (Note 15). 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: • valuation of Keystone XL assets and Class C Interests (Note 7) • recoverability and depreciation rates of plant, property and equipment (Note 10) • allocation of consideration to lease and non-lease components in a contract that contains a lease (Note 11) • assumptions used to measure the carrying amount of and expected credit losses on net investment in leases and certain contract assets (Notes 11 and 29) • fair value of equity investments not otherwise noted above (Note 12) • carrying value of regulatory assets and liabilities (Note 14) • assumptions used to measure the environmental remediation liability from the Keystone pipeline rupture (Note 18) • recognition of asset retirement obligations (Note 19) • 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 20) • assumptions used to measure retirement and other post-retirement benefit obligations (Note 28) • fair value of financial instruments (Note 29) • fair value of Fluvanna Wind Farm and Blue Cloud Wind Farm (Texas Wind Farms) assets (Note 31) • commitments and provisions for contingencies and guarantees (Note 32). TC Energy continues to assess the impact of climate change 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 and liquids 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 liquids pipelines as well as 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.
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 and liquids 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 crude oil, 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 The Company is contracted to provide pipeline construction services to a partially-owned entity for a development fee. The development fee is considered variable consideration due to refund provisions in the contract. The Company recognizes its estimate of the most likely amount of the variable consideration to which it will be entitled. The development fee is recognized over time as the services are 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. 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 certain leased pipelines. Revenues earned from these services are recognized ratably over the term of the contract. Liquids Pipelines Capacity Arrangements and Transportation Revenues from the Company's liquids pipelines are generated mainly from providing customers with firm capacity arrangements to transport crude oil. The performance obligation in these contracts is the reservation of a specified amount of capacity together with the transportation of crude oil on a monthly basis. Revenues earned from these arrangements are recognized ratably over the term of the contract regardless of the amount of crude oil that is transported. Revenues for interruptible or volumetric-based services are recognized when the service is performed. Liquids pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the crude oil that it transports for customers. 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 crude oil in transit, 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. Liquids Pipelines Plant, property and equipment for liquids pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent and other plant and equipment are depreciated at various rates reflecting their estimated useful lives. The cost of these assets includes interest capitalized during construction. When liquids pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income. 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 and liquids tank terminals 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. Leases In March 2023, the FASB issued new guidance that clarified the accounting for leasehold improvements associated with common control leases. The guidance requires all lessees to amortize leasehold improvements associated with common control leases over their useful life to the common control group and account for them as a transfer of assets between entities under common control at the end of the lease. Additional disclosures are required when the useful life of leasehold improvements to the common control group exceeds the related lease term. This new guidance is effective January 1, 2024 and can be applied either prospectively or retrospectively, with early application permitted. The Company will adopt the guidance on a prospective basis starting January 1, 2024, and it is not expected to have a material impact on the Company's consolidated financial statements.
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 / Impairment of Equity Method Investments/ 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 tax is reflected in income tax expense. 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 the annual period 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 does not expect this guidance to have a material impact on the Company's consolidated financial statements.
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 substantively related to its power generation facilities. The scope and timing of asset retirements related to the Company's natural gas and liquids 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, it records an asset 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 assets or liabilities and are refunded to or collected from ratepayers 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	ACCOUNTING CHANGES 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 the annual period 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 does not expect this guidance to have a material impact on the Company's consolidated financial statements. Segment Reporting In November 2023, the 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 is effective for annual periods beginning January 1, 2024 and interim periods beginning January 1, 2025. Early adoption is permitted and the guidance is applied retrospectively. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements. Leases In March 2023, the FASB issued new guidance that clarified the accounting for leasehold improvements associated with common control leases. The guidance requires all lessees to amortize leasehold improvements associated with common control leases over their useful life to the common control group and account for them as a transfer of assets between entities under common control at the end of the lease. Additional disclosures are required when the useful life of leasehold improvements to the common control group exceeds the related lease term. This new guidance is effective January 1, 2024 and can be applied either prospectively or retrospectively, with early application permitted. The Company will adopt the guidance on a prospective basis starting January 1, 2024, and it is not expected to have a material impact on the Company's consolidated financial statements.
Segment Reporting	Segment Reporting In November 2023, the 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 is effective for annual periods beginning January 1, 2024 and interim periods beginning January 1, 2025. Early adoption is permitted and the guidance is applied retrospectively. The Company is currently assessing the impact of the standard on the Company's consolidated financial statements.
Leases	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.

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	year ended December 31, 2023 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 5,173 6,229 846 2,667 1,019 — 15,934 Intersegment revenues — 101 — — 22 (123) 2 — 5,173 6,330 846 2,667 1,041 (123) 15,934 Income (loss) from equity investments 220 324 78 67 688 — 1,377 Impairment of equity investment (2,100) — — — — — (2,100) Plant operating costs and other (1,756) (1,660) (39) (836) (603) 7 2 (4,887) Commodity purchases resold — (56) — (437) (24) — (517) Property taxes (302) (473) — (116) (6) — (897) Depreciation and amortization (1,325) (934) (89) (338) (92) — (2,778) Goodwill and asset impairment charges and other — — — 4 — — 4 Segmented Earnings (Losses) (90) 3,531 796 1,011 1,004 (116) 6,136 Interest expense (3,263) Allowance for funds used during construction 575 Foreign exchange gains (losses), net 320 Interest income and other 242 Income (Loss) before Income Taxes 4,010 Income tax (expense) recovery (942) 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 3 Capital expenditures 2,953 2,536 2,292 49 144 33 8,007 Capital projects in development — — — — 142 — 142 Contributions to equity investments 3,231 124 — — 794 — 4,149 6,184 2,660 2,292 49 1,080 33 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 Plant operating costs and other 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 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 Liquids Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 4,764 5,933 688 2,668 924 — 14,977 Intersegment revenues — 132 — — 12 (144) 2 — 4,764 6,065 688 2,668 936 (144) 14,977 Income (loss) from equity investments 18 292 122 55 539 28 3 1,054 Impairment of Equity Investment (3,048) — — — — — (3,048) Plant operating costs and other (1,679) (1,856) (221) (756) (544) 124 2 (4,932) Commodity purchases resold — — — (512) (22) — (534) Property taxes (297) (426) — (121) (4) — (848) Depreciation and amortization (1,198) (887) (98) (329) (72) — (2,584) Goodwill and asset impairment charges and other — (571) — 118 — — (453) Segmented Earnings (Losses) (1,440) 2,617 491 1,123 833 8 3,632 Interest expense (2,588) Allowance for funds used during construction 369 Foreign exchange gains (losses), net 3 (185) Interest income and other 146 Income (Loss) before Income Taxes 1,374 Income tax (expense) recovery (589) 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 4 Capital expenditures 3,274 2,137 1,027 106 93 41 6,678 Capital projects in development — — — — 49 — 49 Contributions to equity investments 5 1,445 — — 37 752 — 2,234 4,719 2,137 1,027 143 894 41 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 Plant operating costs and other 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 13, Loans receivable from affiliates, for additional information. 4 Included in Investing activities in the Consolidated statement of cash flows. 5 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 13, Loans receivable from affiliates, for additional information. year ended December 31, 2021 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Energy Solutions Corporate Total (millions of Canadian $) 1 Revenues 4,519 5,233 605 2,306 724 — 13,387 Intersegment revenues — 145 — — 14 (159) 2 — 4,519 5,378 605 2,306 738 (159) 13,387 Income (loss) from equity investments 12 244 119 71 411 41 3 898 Plant operating costs and other (1,567) (1,393) (55) (700) (455) 72 2 (4,098) Commodity purchases resold — — (3) (84) — — (87) Property taxes (289) (367) — (113) (5) — (774) Depreciation and amortization (1,226) (791) (109) (318) (78) — (2,522) Goodwill and asset impairment charges and other — — — (2,775) — — (2,775) Net gain (loss) on sale of assets — — — 13 17 — 30 Segmented Earnings (Losses) 1,449 3,071 557 (1,600) 628 (46) 4,059 Interest expense (2,360) Allowance for funds used during construction 267 Foreign exchange gains (losses), net 3 10 Interest income and other 190 Income (Loss) before Income Taxes 2,166 Income tax (expense) recovery (120) Net Income (Loss) 2,046 Net (income) loss attributable to non-controlling interests (91) Net Income (Loss) Attributable to Controlling Interests 1,955 Preferred share dividends (140) Net Income (Loss) Attributable to Common Shares 1,815 Capital Spending 4 Capital expenditures 2,629 2,611 129 488 32 35 5,924 Contributions to equity investments 108 209 — 83 810 — 1,210 2,737 2,820 129 571 842 35 7,134 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 Plant operating costs and other 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. Refer to Note 13, Loans receivable from affiliates, for additional information. 4 Included in Investing activities in the Consolidated statement of cash flows. at December 31 2023 2022 (millions of Canadian $) Total Assets by Segment Canadian Natural Gas Pipelines 29,782 27,456 U.S. Natural Gas Pipelines 50,499 50,038 Mexico Natural Gas Pipelines 12,003 9,231 Liquids Pipelines 15,490 15,587 Power and Energy Solutions 9,525 8,272 Corporate 7,735 3,764 125,034 114,348
Revenue from External Customers by Geographic Areas	year ended December 31 2023 2022 2021 (millions of Canadian $) Revenues Canada – domestic 5,360 4,942 4,603 Canada – export 1,403 1,322 1,226 United States 8,325 8,025 6,953 Mexico 846 688 605 15,934 14,977 13,387
Schedule of Long-Lived Assets by Country	at December 31 2023 2022 (millions of Canadian $) Plant, Property and Equipment Canada 28,583 27,232 United States 44,609 43,505 Mexico 7,377 5,203 80,569 75,940

REVENUES (Tables)

REVENUES (Tables)	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenues	year ended December 31, 2023 Canadian U.S. Mexico Liquids Pipelines Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 5,141 5,107 442 2,115 — 12,805 Power generation — — — — 427 427 Natural gas storage and other 1,2 32 874 125 3 363 1,397 5,173 5,981 567 2,118 790 14,629 Sales-type lease income 3 — — 279 — — 279 Other revenues 4 — 248 — 549 229 1,026 5,173 6,229 846 2,667 1,019 15,934 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 11, Leases, for additional information. 3 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 11, Leases, for additional information. 4 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 11, Leases, and Note 29, Risk management and financial instruments, for additional information. year ended December 31, 2022 Canadian U.S. Mexico Liquids Pipelines Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,696 4,621 507 1,983 — 11,807 Power generation — — — — 490 490 Natural gas storage and other 1,2 68 1,298 54 4 391 1,815 4,764 5,919 561 1,987 881 14,112 Sales-type lease income 3 — — 127 — — 127 Other revenues 4,5 — 14 — 681 43 738 4,764 5,933 688 2,668 924 14,977 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 11, Leases, for additional information. 3 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 11, Leases, for additional information. 4 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 11, Leases, and Note 29, Risk management and financial instruments, for additional information. 5 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 14, Rate-regulated businesses, for additional information. year ended December 31, 2021 Canadian U.S. Mexico Liquids Pipelines Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,432 4,139 576 2,025 — 11,172 Power generation — — — — 324 324 Natural gas storage and other 1 87 1,057 29 5 278 1,456 4,519 5,196 605 2,030 602 12,952 Other revenues 2,3 — 37 — 276 122 435 4,519 5,233 605 2,306 724 13,387 1 Includes $87 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 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 11, Leases, and Note 29, Risk management and financial instruments, for additional information. 3 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 14, Rate-regulated businesses, for additional information.
Contract Balances	Contract Balances at December 31 2023 2022 Affected line item on the (millions of Canadian $) Receivables from contracts with customers 1,832 1,907 Accounts receivable Contract assets (Note 9) 151 155 Other current assets Long-term contract assets (Note 16) 457 355 Other long-term assets Contract liabilities 1 (Note 18) 69 62 Accounts payable and other Long-term contract liabilities 1 (Note 19) 12 32 Other long-term liabilities 1 During the year ended December 31, 2023, $64 million (2022 – $51 million) of revenues were recognized that were included in contract liabilities and long-term contract liabilities at the beginning of the year.

KEYSTONE XL (Tables)

KEYSTONE XL (Tables)	12 Months Ended
	Dec. 31, 2023
Investments, All Other Investments [Abstract]
Schedule of Impairment of Long-Lived Assets Held and Used	year ended December 31, 2021 Estimated Fair Value Asset impairment charge and other (millions of Canadian $) Pre tax After tax Asset impairment charge Plant and equipment 175 412 312 Related capital projects in development — 230 175 Other capitalized costs — 2,158 1,642 Capitalized interest — 326 248 175 3,126 2,377 Other Contractual recoveries n/a (693) (525) Contractual and legal obligations related to termination activities n/a 342 282 175 2,775 2,134

COASTAL GASLINK (Tables)

COASTAL GASLINK (Tables)	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Changes in Loan Balances	The table below reflects the changes in this loan receivable balance. at December 31 (millions of Canadian $) 2023 2022 Outstanding balance at beginning of year 250 238 Issuances 2,520 112 Repayments (250) (100) Outstanding balance at end of year 2,520 250 Impairment during the year (2,020) (250) Carrying value at end of year 500 —

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2023
Other Assets [Abstract]
Schedule of Other Current Assets	at December 31 2023 2022 (millions of Canadian $) Fair value of derivative contracts (Note 29) 1,285 614 Current portion of net investment in leases (Note 11) 306 291 Contract assets (Note 6) 151 155 Current portion of Keystone environmental provision recovery (Note 18) 150 410 Cash provided as collateral 120 106 Emissions credits 94 36 Prepaid expenses 92 118 Keystone XL contractual recoveries (Note 7) 83 86 Regulatory assets (Note 14) 76 67 Keystone XL assets held for sale 58 122 Other 88 147 2,503 2,152

PLANT, PROPERTY AND EQUIPMENT (

PLANT, PROPERTY AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Schedule of Plant, Property and Equipment	at December 31 2023 2022 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 20,232 6,855 13,377 18,119 6,285 11,834 Compression 6,603 2,349 4,254 6,265 2,224 4,041 Metering and other 1,589 830 759 1,518 769 749 28,424 10,034 18,390 25,902 9,278 16,624 Under construction 787 — 787 1,552 — 1,552 29,211 10,034 19,177 27,454 9,278 18,176 Canadian Mainline Pipeline 10,729 7,996 2,733 10,472 7,852 2,620 Compression 4,437 3,354 1,083 4,328 3,247 1,081 Metering and other 729 308 421 692 285 407 15,895 11,658 4,237 15,492 11,384 4,108 Under construction 147 — 147 269 — 269 16,042 11,658 4,384 15,761 11,384 4,377 Other Canadian Natural Gas Pipelines 1 Other 2,846 1,682 1,164 1,984 1,624 360 Under construction 23 — 23 455 — 455 2,869 1,682 1,187 2,439 1,624 815 48,122 23,374 24,748 45,654 22,286 23,368 U.S. Natural Gas Pipelines Columbia Gas Pipeline 12,952 1,247 11,705 12,471 1,069 11,402 Compression 5,310 559 4,751 5,190 495 4,695 Metering and other 4,074 372 3,702 4,026 346 3,680 22,336 2,178 20,158 21,687 1,910 19,777 Under construction 771 — 771 659 — 659 23,107 2,178 20,929 22,346 1,910 20,436 ANR Pipeline 2,117 657 1,460 2,066 641 1,425 Compression 3,928 773 3,155 3,785 734 3,051 Metering and other 1,625 458 1,167 1,666 440 1,226 7,670 1,888 5,782 7,517 1,815 5,702 Under construction 404 — 404 328 — 328 8,074 1,888 6,186 7,845 1,815 6,030 at December 31 2023 2022 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Other U.S. Natural Gas Pipelines Columbia Gulf 3,600 256 3,344 3,511 224 3,287 GTN 2,992 1,295 1,697 2,964 1,239 1,725 Great Lakes 2,359 1,401 958 2,367 1,387 980 Other 2 2,071 800 1,271 1,928 760 1,168 11,022 3,752 7,270 10,770 3,610 7,160 Under construction 584 — 584 328 — 328 11,606 3,752 7,854 11,098 3,610 7,488 42,787 7,818 34,969 41,289 7,335 33,954 Mexico Natural Gas Pipelines 3 Pipeline 2,280 387 1,893 2,299 348 1,951 Compression 370 79 291 374 59 315 Metering and other 482 123 359 487 113 374 3,132 589 2,543 3,160 520 2,640 Under construction 4,823 — 4,823 2,547 — 2,547 7,955 589 7,366 5,707 520 5,187 Liquids Pipelines Keystone Pipeline System Pipeline 9,569 2,212 7,357 9,777 2,056 7,721 Pumping equipment 1,096 312 784 1,064 288 776 Tanks and other 3,658 913 2,745 3,723 859 2,864 14,323 3,437 10,886 14,564 3,203 11,361 Under construction 54 — 54 96 — 96 14,377 3,437 10,940 14,660 3,203 11,457 Intra-Alberta Pipelines 203 25 178 199 19 180 14,580 3,462 11,118 14,859 3,222 11,637 Power and Energy Solutions Natural Gas Power Generation 1,239 637 602 1,260 642 618 Natural Gas Storage and Other 845 256 589 820 238 582 Renewable Power Generation 581 19 562 — — — 2,665 912 1,753 2,080 880 1,200 Under construction 153 — 153 80 — 80 2,818 912 1,906 2,160 880 1,280 Corporate 909 447 462 900 386 514 117,171 36,602 80,569 110,569 34,629 75,940 1 Includes Foothills, Ventures LP and Great Lakes Canada. 2 Includes Portland, North Baja, Tuscarora, Crossroads and mineral rights business. 3 During the year ended December 31, 2023, the Company derecognized $407 million (2022 – $2,319 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 11, Leases, for additional information.

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Operating Lease Cost and Other Information	Operating lease cost was as follows: year ended December 31 (millions of Canadian $) 2023 2022 Operating lease cost 1 118 106 Sublease income (4) (5) Net operating lease cost 114 101 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 $) 2023 2022 Cash paid for amounts included in the measurement of operating lease liabilities 72 67 ROU assets obtained in exchange for new operating lease liabilities 84 49 at December 31 2023 2022 Weighted average remaining lease term 13 years 8 years Weighted average discount rate 3.3 % 3.5 % The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2023 2022 Accounts payable and other 58 54 Other long-term liabilities (Note 19) 401 379 459 433
Maturities of Operating Lease Liabilities	Maturities of operating lease liabilities are as follows: at December 31 (millions of Canadian $) 2023 2022 Less than one year 72 68 One to two years 68 65 Two to three years 66 62 Three to four years 59 60 Four to five years 58 54 More than five years 225 187 Total operating lease payments 548 496 Imputed interest (89) (63) Operating lease liabilities 459 433
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 $) 2023 2022 Less than one year 113 113 One to two years 94 111 Two to three years 70 94 Three to four years — 70 277 388
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 $) 2023 2022 Net Investment in Leases Minimum lease payments 9,627 9,457 Unearned lease income (7,006) (7,132) Lease receivable 2,621 2,325 Expected credit loss provision 1 (76) (150) Present value of unguaranteed residual value 24 11 2,569 2,186 Current portion included in Other current assets (Note 9) (306) (291) 2,263 1,895 1 Includes nil (2022 – $1 million) 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 $) 2023 2022 Less than one year 305 291 One to two years 305 291 Two to three years 305 291 Three to four years 305 291 Four to five years 305 291 More than five years 8,102 8,002 9,627 9,457

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Investments	(millions of Canadian $) Ownership Interest at December 31, 2023 Income (Loss) from Equity Investments Equity year ended December 31 at December 31 2023 2022 2021 2023 2022 Canadian Natural Gas Pipelines TQM 1 50.0 % 17 17 12 166 165 Coastal GasLink 1 35.0 % 203 1 — 294 — U.S. Natural Gas Pipelines Northern Border 50.0 % 101 92 80 599 516 Millennium 47.5 % 109 103 91 476 500 Iroquois 50.0 % 98 77 55 227 237 Other Various 16 20 18 120 122 Mexico Natural Gas Pipelines Sur de Texas 60.0 % 78 150 160 1,078 1,050 Liquids Pipelines Grand Rapids 1 50.0 % 53 54 54 932 964 Port Neches Link LLC 2,3 74.9 % 13 — — 124 149 HoustonLink Pipeline 1 50.0 % 1 1 1 18 19 Northern Courier 1,4 nil — — 16 — — Power and Energy Solutions Bruce Power 1 48.3 % 690 537 411 6,242 5,783 Other Various (2) 2 — 38 30 1,377 1,054 898 10,314 9,535 1 Classified as a VIE. Refer to Note 33, Variable interest entities, for additional information. 2 Classified as a VIE in 2021. 3 In December 2023, TC Energy sold a 20.1 per cent equity interest in Port Neches Link LLC. 4 In November 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 31, Acquisitions and dispositions, for additional information. Summarized Financial Information of Equity Investments year ended December 31 2023 2022 2021 (millions of Canadian $) Income Revenues 6,425 5,891 5,447 Operating and other expenses (3,450) (3,390) (3,293) Net income 2,584 2,147 1,859 Net income attributable to TC Energy 1,377 1,054 898 at December 31 2023 2022 (millions of Canadian $) Balance Sheet Current assets 3,526 3,414 Non-current assets 42,933 37,713 Current liabilities (2,431) (2,856) Non-current liabilities (21,895) (17,690)
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, 2023, 2022 and 2021 were as follows: year ended December 31 2023 2022 2021 (millions of Canadian $) Distributions Distributions received from operating activities of equity investments 1,254 1,025 975 Sur de Texas debt repayments 1,2 — 2,404 73 Other 1 23 228 — 1,277 3,657 1,048 Contributions 1 Contributions to Coastal GasLink 3,231 1,414 92 Sur de Texas debt financing 2 — 1,199 — Contributions made to other equity investments 918 820 1,118 4,149 3,433 1,210 1 Included in Investing activities in the Consolidated statement of cash flows. 2 Represents TC Energy's proportionate share of the Sur de Texas debt financing requirements and subsequent repayments. Refer to Note 13, Loans receivable from affiliates, for additional information.

LOANS RECEIVABLE FROM AFFILIA_2

LOANS RECEIVABLE FROM AFFILIATES (Tables)	12 Months Ended
	Dec. 31, 2023
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 $) 2023 2022 2021 Interest income 1 — 19 87 Interest income and other Interest expense 2 — (19) (87) Income (loss) from equity investments Foreign exchange losses 1 — (28) (41) Foreign exchange (gains) losses, net Foreign exchange gains 1 — 28 41 Income 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, 2023
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	at December 31 Remaining Recovery/ Settlement Period (years) 2023 2022 (millions of Canadian $) Regulatory Assets Deferred income taxes 1 n/a 2,204 1,817 Operating and debt-service regulatory assets 2 1 29 2 Pensions and other post-retirement benefits 1,3 n/a 54 28 Foreign exchange on long-term debt 1,4 1-6 11 19 Other n/a 108 111 2,406 1,977 Less: Current portion included in Other current assets (Note 9) 76 67 2,330 1,910 Regulatory Liabilities Pipeline abandonment trust balances 5 n/a 2,355 2,014 Deferred income taxes – U.S. Tax Reform 6 n/a 1,137 1,197 Canadian Mainline short-term adjustment and toll-stabilization accounts 7,8 n/a 437 284 Canadian Mainline bridging amortization account 7 7 376 429 Cost of removal 9 n/a 351 337 Deferred income taxes 1 n/a 198 181 Canadian Mainline long-term adjustment account 7,10 3 111 149 ANR post-employment and retirement benefits other than pension 11 n/a 42 43 Operating and debt-service regulatory liabilities 2 1 23 50 Pensions and other post-retirement benefits 3 n/a 6 10 Other n/a 54 99 5,090 4,793 Less: Current portion included in Accounts payable and other (Note 18) 284 273 4,806 4,520 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 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, 2023
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 2023 2022 (millions) Canadian U.S. dollars Canadian dollars U.S. dollars Columbia Pipeline Group, Inc. 9,708 7,351 9,948 7,351 ANR 2,570 1,946 2,634 1,946 Great Lakes 161 122 165 122 North Baja 63 48 65 48 Tuscarora 30 23 31 23 12,532 9,490 12,843 9,490 Changes in Goodwill were as follows: (millions of Canadian $) U.S. Natural Balance at January 1, 2022 12,582 Great Lakes impairment charge (571) Foreign exchange rate changes 832 Balance at December 31, 2022 12,843 Foreign exchange rate changes (311) Balance at December 31, 2023 12,532

OTHER LONG-TERM ASSETS (Tables)

OTHER LONG-TERM ASSETS (Tables)	12 Months Ended
	Dec. 31, 2023
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Schedule of Other Long-Term Assets	at December 31 2023 2022 (millions of Canadian $) Deferred income tax assets (Note 20) 1,332 1,070 Employee post-retirement benefits (Note 28) 518 563 Long-term contract assets (Note 6) 457 355 Capital projects in development 237 99 Fair value of derivative contracts (Note 29) 155 91 Keystone XL contractual recoveries (Note 7) 34 44 Keystone environmental provision recovery (Note 18) 33 240 Other 252 323 3,018 2,785

NOTES PAYABLE (Tables)

NOTES PAYABLE (Tables)	12 Months Ended
	Dec. 31, 2023
Short-Term Debt [Abstract]
Schedule of Notes Payable	at December 31 2023 2022 (millions of Canadian $, unless otherwise noted) Outstanding Weighted Average Interest Rate per Annum Outstanding Weighted Average Interest Rate per Annum Canada 1 — — 5,971 4.9 % Mexico (2023 – nil; 2022 – US$215) 2 — — 291 6.0 % — 6,262 1 At December 31, 2023, Notes payable consisted of Canadian dollar-denominated notes of nil (2022 – $2,810 million) and U.S. dollar-denominated notes of nil (2022 – US$2,336 million). 2 In January 2023, the Company's Mexico subsidiary fully repaid the outstanding balance and terminated its MXN$5.0 billion demand senior unsecured revolving credit facility.
Schedule of Credit Facilities	These unsecured credit facilities included the following: at December 31 (billions of Canadian $, unless otherwise noted) 2023 2022 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 2028 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 2024 US 2.5 US 2.5 US 3.0 TCPL / TCPL USA Supports commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL December 2026 US 2.5 US 2.5 US 2.5 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 3 1.0 2.1 3 Mexico subsidiary For Mexico general corporate purposes, guaranteed by TCPL Demand — — MXN 5.0 3 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, 2023, the Company was in compliance with all financial covenants. 3 Or the U.S. dollar equivalent.

ACCOUNTS PAYABLE AND OTHER (Tab

ACCOUNTS PAYABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2023
Payables and Accruals [Abstract]
Schedule of Accounts Payable and Other	at December 31 2023 2022 (millions of Canadian $) Trade payables 4,832 4,330 Fair value of derivative contracts (Note 29) 1,143 871 Regulatory liabilities (Note 14) 284 273 Keystone environmental provision 122 650 Contract liabilities (Note 6) 69 62 Class C Interests (Note 7) 19 37 Coastal GasLink contractual contribution (Notes 8, 12 and 33) — 537 Other 518 389 6,987 7,149

OTHER LONG-TERM LIABILITIES (Ta

OTHER LONG-TERM LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2023
Deferred Costs, Noncurrent [Abstract]
Schedule of Other Long-Term Liabilities	at December 31 2023 2022 (millions of Canadian $) Operating lease obligations (Note 11) 401 379 Fair value of derivative contracts (Note 29) 106 151 Employee post-retirement benefits (Note 28) 97 111 Asset retirement obligations 64 79 Long-term contract liabilities (Note 6) 12 32 Other 335 265 1,015 1,017

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Geographic Components of Income	Geographic Components of Income before Income Taxes year ended December 31 2023 2022 2021 (millions of Canadian $) Canada (446) (2,154) (292) Foreign 4,456 3,528 2,458 Income before Income Taxes 4,010 1,374 2,166
Schedule of Provision for Income Taxes	year ended December 31 2023 2022 2021 (millions of Canadian $) Current Canada 73 43 29 Foreign 858 372 276 931 415 305 Deferred Canada (39) (467) (327) Foreign 50 641 142 11 174 (185) Income Tax Expense 942 589 120
Reconciliation of Income Tax Expense	year ended December 31 2023 2022 2021 (millions of Canadian $) Income before income taxes 4,010 1,374 2,166 Federal and provincial statutory tax rate 23.0 % 23.0 % 23.0 % Expected income tax expense 922 316 498 Income tax differential related to regulated operations (260) (174) (139) Foreign income tax rate differentials (174) (271) (230) Income from non-controlling interests and equity investments (56) (54) (70) Valuation allowance (release) 197 199 (8) Non-taxable capital (gains) and losses 196 173 — Mexico foreign exchange exposure 132 9 10 Impact of Mexico inflationary adjustments 1 24 32 Settlement of Mexico prior years' income tax assessments — 196 — U.S. minimum tax (14) 96 — Non-deductible goodwill impairment — 91 — Other (2) (16) 27 Income Tax Expense 942 589 120
Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet	at December 31 2023 2022 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,833 1,519 Regulatory and other deferred amounts 569 571 Unrealized foreign exchange losses on long-term debt 206 333 Other 73 193 2,681 2,616 Less: Valuation allowance 730 640 1,951 1,976 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment 6,816 6,686 Equity investments 1,115 1,152 Taxes on future revenue requirement 493 397 Financial instruments 160 126 Other 160 193 8,744 8,554 Net Deferred Income Tax Liabilities 6,793 6,578 The above deferred tax amounts have been classified on the Consolidated balance sheet as follows: at December 31 2023 2022 (millions of Canadian $) Deferred Income Tax Assets Other long-term assets (Note 16) 1,332 1,070 Deferred Income Tax Liabilities Deferred income tax liabilities 8,125 7,648 Net Deferred Income Tax Liabilities 6,793 6,578
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 2023 2022 2021 (millions of Canadian $) Unrecognized tax benefit at beginning of year 91 80 52 Gross increases – tax positions in prior years 9 6 5 Gross decreases – tax positions in prior years (1) — (1) Gross increases – tax positions in current year 16 7 26 Lapse of statutes of limitations (30) (2) (2) Unrecognized Tax Benefit at End of Year 85 91 80

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	at December 31 2023 2022 Maturity Dates Outstanding Interest Rate 1 Outstanding Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Medium Term Notes Canadian 2024 to 2052 15,466 4.6 % 13,966 4.5 % Senior Unsecured Notes U.S. (2023 – US$16,167; 2022 – US$15,542) 2024 to 2049 21,349 5.0 % 21,032 4.9 % 36,815 34,998 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2023 – nil; 2022 – US$200) — — 271 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2023 and 2022 – US$33) 2026 43 7.5 % 44 7.5 % 647 919 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes 2 U.S. (2023 – nil; 2022 – US$1,500) — — 2,030 4.9 % COLUMBIA PIPELINES OPERATING COMPANY LLC Senior Unsecured Notes 2 U.S. (2023 – US$6,100; 2022 – nil) 2025 to 2063 8,055 6.1 % — — COLUMBIA PIPELINES HOLDING COMPANY LLC Senior Unsecured Notes 2 U.S. (2023 – US$1,000; 2022 – nil) 2026 to 2028 1,320 6.2 % — — ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2023 and 2022 – US$1,172) 2024 to 2037 1,548 4.1 % 1,587 4.1 % TC PIPELINES, LP Senior Unsecured Notes U.S. (2023 and 2022 – US$850) 2025 to 2027 1,122 4.2 % 1,150 4.2 % at December 31 2023 2022 Maturity Dates Outstanding Interest Rate 1 Outstanding Interest Rate 1 (millions of Canadian $, unless otherwise noted) GAS TRANSMISSION NORTHWEST LLC Senior Unsecured Notes U.S. (2023 – US$375; 2022 – US$325) 2030 to 2035 495 4.4 % 440 4.3 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Unsecured Notes U.S. (2023 and 2022 – US$250) 2030 to 2031 330 2.8 % 338 2.8 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2023 – US$125; 2022 – US$146) 2028 to 2030 165 7.6 % 198 7.6 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2023 – nil; 2022 – US$34) — — 46 6.5 % TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. Senior Unsecured Term Loan U.S. (2023 – US$1,800; 2022 – nil) 2028 2,377 7.7 % — — Senior Unsecured Revolving Credit Facility U.S. (2023 – US$185; 2022 – nil) 2028 244 7.7 % — — 2,621 — 53,118 41,706 Current portion of long-term debt (2,938) (1,898) Unamortized debt discount and issue costs (312) (239) Fair value adjustments 3 108 76 49,976 39,645 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 8, 2023, US$1.5 billion senior unsecured notes were assigned from Columbia Pipelines Group, Inc. to Columbia Pipelines Operating Company LLC in advance of the October 4, 2023 sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf. Preceding this sale, US$5.6 billion of senior unsecured notes were issued. Refer to Note 24, Non-controlling interests, for additional information. 3 The fair value adjustments include $119 million (2022 – $140 million) related to the acquisition of Columbia Pipeline Group, Inc. These adjustments also include a decrease of $11 million (2022 – $64 million) related to hedged interest rate risk. Refer to Note 29, Risk management and financial instruments, for additional information. The Company issued long-term debt over the three years ended December 31, 2023 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED May 2023 Senior Unsecured Term Loan 1 May 2026 US 1,024 Floating March 2023 Senior Unsecured Notes March 2026 2 US 850 6.20 % March 2023 Senior Unsecured Notes March 2026 2 US 400 Floating March 2023 Medium Term Notes July 2030 1,250 5.28 % March 2023 Medium Term Notes March 2026 2 600 5.42 % March 2023 Medium Term Notes March 2026 2 400 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 % October 2021 Senior Unsecured Notes October 2024 US 1,250 1.00 % October 2021 Senior Unsecured Notes October 2031 US 1,000 2.50 % June 2021 Medium Term Notes June 2024 750 Floating June 2021 Medium Term Notes June 2031 500 2.97 % June 2021 Medium Term Notes September 2047 250 4.33 % 3 COLUMBIA PIPELINES OPERATING COMPANY LLC 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 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 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM October 2021 Senior Unsecured Notes October 2031 US 125 2.68 % (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TUSCARORA GAS TRANSMISSION COMPANY August 2021 Unsecured Term Loan August 2024 US 13 Floating KEYSTONE XL SUBSIDIARIES 4 Various Project-Level Credit Facility June 2021 US 849 Floating COLUMBIA PIPELINE GROUP, INC. 5 January 2021 Unsecured Term Loan June 2022 US 4,040 Floating 1 This loan was fully repaid and retired in September 2023. Related unamortized debt issue costs of $3 million were included in Interest expense in the Consolidated statement of income. 2 Callable at par in March 2024 or at any time thereafter. 3 Reflects coupon rate on re-opening of a pre-existing Medium Term Notes (MTN) issue. The MTNs were issued at a premium to par, resulting in a re-issuance yield of 4.19 per cent. 4 In January 2021, the Company established a US$4.1 billion project-level credit facility to support the construction of the Keystone XL pipeline, which was fully guaranteed by the Government of Alberta and non-recourse to TC Energy. The availability of this credit facility was subsequently reduced to US$1.6 billion and all amounts outstanding were fully repaid by the Government of Alberta in June 2021. Refer to Note 7, Keystone XL, for additional information. 5 In December 2020, Columbia entered into a US$4.2 billion Unsecured Term Loan agreement. In January 2021, US$4.0 billion was drawn on the Unsecured Term Loan and the total availability under the loan agreement was reduced accordingly. The loan was fully repaid and retired in December 2021. On January 9, 2024, Columbia Pipelines Holding Company LLC issued US$500 million senior unsecured notes due January 2034, bearing interest at a fixed rate of 5.68 per cent.
Schedule of Repayments of Long-Term Debt	At December 31, 2023, principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2024 2025 2026 2027 2028 Principal repayments on long-term debt 2,938 2,779 5,287 3,096 6,232
Schedule of Retired Long-Term Debt	The Company retired/repaid long-term debt over the three years ended December 31, 2023 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED October 2023 Senior Unsecured Notes US 625 3.75 % September 2023 Senior Unsecured Notes 1 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 % November 2021 Medium Term Notes 500 3.65 % January 2021 Debentures US 400 9.88 % TUSCARORA GAS TRANSMISSION COMPANY November 2023 Unsecured Term Loan US 32 Floating NOVA GAS TRANSMISSION LTD. April 2023 Debentures US 200 7.88 % TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. Various Senior Unsecured Revolving Credit Facility US 315 Floating COLUMBIA PIPELINE GROUP, INC. December 2021 Unsecured Term Loan 2 US 4,040 Floating NORTH BAJA PIPELINE, LLC December 2021 Unsecured Term Loan US 50 Floating TC PIPELINES, LP November 2021 Unsecured Term Loan US 450 Floating March 2021 Senior Unsecured Notes US 350 4.65 % ANR PIPELINE COMPANY November 2021 Senior Unsecured Notes US 300 9.63 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP November 2021 Senior Unsecured Notes US 10 9.09 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM October 2021 Unsecured Loan Facility US 93 Floating KEYSTONE XL SUBSIDIARIES 3 June 2021 Project-Level Credit Facility US 849 Floating 1 In May 2023, the Company entered into a US$1,024 million senior unsecured term loan and the full amount was drawn. The loan was fully repaid and retired in September 2023. Related unamortized debt issue costs of $3 million were included in Interest expense in the Consolidated statement of income. 2 In December 2020, Columbia entered into a US$4.2 billion Unsecured Term Loan agreement. In January 2021, US$4.0 billion was drawn on the Unsecured Term Loan and the total availability under the loan agreement was reduced accordingly. The loan was fully repaid and retired in December 2021. Related unamortized debt issue costs of $5 million were included in Interest expense in the Consolidated statement of income for the year ended December 31, 2021. 3 In June 2021, in accordance with the terms of the guarantee, the Government of Alberta repaid the US$849 million outstanding balance under the Keystone XL project-level credit facility bearing interest at a floating rate, subsequent to which it was terminated, resulting in no cash impact to TC Energy. Refer to Note 7, Keystone XL, for additional information.
Schedule of Interest Expense	Interest Expense year ended December 31 2023 2022 2021 (millions of Canadian $) Interest on long-term debt 2,562 1,883 1,841 Interest on junior subordinated notes 617 543 453 Interest on short-term debt 165 153 10 Capitalized interest (187) (27) (22) Amortization and other financial charges 1 106 36 78 3,263 2,588 2,360 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, 2023
Junior Subordinated Notes [Abstract]
Schedule of Junior Subordinated Notes	at December 31 2023 2022 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 1,320 6.5 % 1,353 6.2 % US$750 issued 2015 at 5.88% 3,4 2075 990 7.8 % 1,015 7.4 % US$1,200 issued 2016 at 6.13% 3,4 2076 1,585 8.3 % 1,624 8.0 % US$1,500 issued 2017 at 5.55% 3,4 2077 1,981 7.5 % 2,030 7.1 % $1,500 issued 2017 at 4.90% 3,4 2077 1,500 7.0 % 1,500 6.8 % US$1,100 issued 2019 at 5.75% 3,4 2079 1,453 8.0 % 1,488 7.6 % $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 1,056 7.1 % 1,083 7.2 % 10,385 10,593 Unamortized debt discount and issue costs (98) (98) 10,287 10,495 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, 2023
Foreign Currency [Abstract]
Schedule of Foreign Exchange Contracts	year ended December 31 2023 2022 2021 (millions of Canadian $) Derivative instruments held for trading (Note 29) (401) 151 (37) Other 81 34 27 (320) 185 (10)

NON-CONTROLLING INTERESTS (Tabl

NON-CONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2023
Noncontrolling Interest [Abstract]
Schedule of Business Acquisition and its Effect on the Balance Sheet	As the Company controlled TC PipeLines, LP, this acquisition was accounted for as an equity transaction with the following impact reflected on the Consolidated balance sheet: (millions of Canadian $) March 3, 2021 Common shares 2,063 Additional paid-in-capital (398) Accumulated other comprehensive income (loss) 353 Non-controlling interests (1,563) Deferred income tax liabilities (443) Other (12)
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, 2023 Income (Loss) Attributable to Non-Controlling Interests year ended December 31 at December 31 2023 2022 2021 2023 2022 Columbia Gas and Columbia Gulf 40.0 % 143 — — 9,167 — Portland Natural Gas Transmission System 38.3 % 41 37 30 106 126 Texas Wind Farms 100% 1 (38) — — 182 — TC PipeLines, LP nil 2 — — 60 — — Redeemable non-controlling interest (Note 7) nil — — 1 — — 146 37 91 9,455 126 1 Non-controlling interests in the Texas Wind Farms comprises Class A Membership Interests.

COMMON SHARES (Tables)

COMMON SHARES (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2021 940,064 24,488 Acquisition of TC PipeLines, LP, net of transaction costs (Note 24) 37,955 2,063 Exercise of options 2,797 165 Outstanding at December 31, 2021 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 1 Net of underwriting commissions and deferred income taxes.
Schedule of Weighted Average Shares	Weighted Average Common Shares Outstanding (millions) 2023 2022 2021 Basic 1,030 995 973 Diluted 1,030 996 974
Schedule of Stock Options Activity	Number of Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (thousands) (years) Options outstanding at January 1, 2023 6,109 $63.86 Options granted 1,933 $56.66 Options exercised (62) $48.44 Options forfeited/expired (544) $60.60 Options Outstanding at December 31, 2023 7,436 $62.36 4.1 Options Exercisable at December 31, 2023 4,375 $64.47 3.0
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 2023 2022 2021 Weighted average fair value $7.88 $8.24 $7.39 Expected life (years) 1 5.1 5.4 5.4 Interest rate 2.9 % 1.6 % 0.5 % Volatility 2 24 % 22 % 25 % Dividend yield 6.3 % 5.5 % 6.0 % 1 Expected life is based on historical exercise activity. 2 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 2023 2022 2021 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised — 33 28 Total fair value of options that have vested 76 89 110 Total options vested 1.5 million 1.6 million 1.9 million

PREFERRED SHARES (Tables)

PREFERRED SHARES (Tables)	12 Months Ended
	Dec. 31, 2023
Preferred Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Schedule of Preferred Shares	at December 31, 2023 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 2023 2022 2021 (thousands) (millions of Canadian $) Cumulative First Preferred Shares Series 1 14,577 3.48 % $0.86975 $25.00 December 31, 2024 Series 2 360 360 360 Series 2 7,423 Floating 4 Floating $25.00 December 31, 2024 Series 1 179 179 179 Series 3 9,997 1.69 % $0.4235 $25.00 June 30, 2025 Series 4 246 246 246 Series 4 4,003 Floating 4 Floating $25.00 June 30, 2025 Series 3 97 97 97 Series 5 12,071 1.95 % 5 $0.48725 $25.00 January 30, 2026 Series 6 294 294 294 Series 6 1,929 Floating 4 Floating $25.00 January 30, 2026 Series 5 48 48 48 Series 7 24,000 3.90 % $0.97575 $25.00 April 30, 2024 Series 8 589 589 589 Series 9 18,000 3.76 % $0.9405 $25.00 October 30, 2024 Series 10 442 442 442 Series 11 10,000 3.35 % $0.83775 $25.00 November 28, 2025 Series 12 244 244 244 Series 15 — — — — — — — — 988 2,499 2,499 3,487 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 floating quarterly dividend rate for the Series 2 preferred shares is 6.96 per cent for the period starting December 29, 2023 to, but excluding, March 28, 2024. The floating quarterly dividend rate for the Series 4 preferred shares is 6.32 per cent for the period starting December 29, 2023 to, but excluding, March 28, 2024. The floating quarterly dividend rate for the Series 6 preferred shares is 6.69 per cent for the period starting October 30, 2023 to, but excluding, January 30, 2024. These rates will reset each quarter going forward. 5 The fixed rate dividend for Series 5 preferred shares decreased from 2.26 per cent to 1.95 per cent on January 30, 2021 and is due to reset on every fifth anniversary thereafter.

OTHER COMPREHENSIVE INCOME(LO_2

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) (Tables)	12 Months Ended
	Dec. 31, 2023
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, 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 year ended December 31, 2021 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 (100) (8) (108) Change in fair value of net investment hedges (3) 1 (2) Change in fair value of cash flow hedges (13) 3 (10) Reclassification to net income of (gains) losses on cash flow hedges 68 (13) 55 Unrealized actuarial gains (losses) on pension and other post-retirement benefit plans 208 (50) 158 Reclassification to net income of actuarial (gains) losses on pension and other post-retirement benefit plans 20 (6) 14 Other comprehensive income (loss) on equity investments 714 (179) 535 Other Comprehensive Income (Loss) 894 (252) 642
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, 2021 (1,273) (143) (285) (738) (2,439) Other comprehensive income (loss) before reclassifications 1 (98) (11) 158 506 555 Amounts reclassified from AOCI — 55 14 28 97 Net current period other comprehensive income (loss) (98) 44 172 534 652 Acquisition of TC PipeLines, LP 2 362 (13) — 4 353 AOCI balance at December 31, 2021 (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 3 — 74 — (16) 58 Net current period other comprehensive income (loss) (231) 74 (11) (211) (379) Impact of non-controlling interest 4 (527) — — — (527) AOCI balance at December 31, 2023 (317) (35) (55) 456 49 1 Other comprehensive income(loss) before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling 2 Represents the AOCI attributable to non-controlling interests of TC PipeLines, LP which was reclassified to AOCI on the Consolidated balance sheet upon completion of the acquisition of all the outstanding publicly-held common units of TC PipeLines, LP on March 3, 2021. Refer to Note 24, Non-controlling interests, for additional information. 3 Losses 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 $4 million ($3 million, net of tax) at December 31, 2023. 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 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 24, Non-controlling interests, 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 Affected Line Item in the Consolidated Statement of Income 1 2023 2022 2021 (millions of Canadian $) Cash flow hedges Commodities (85) (47) (22) Revenues (Power and Energy Solutions) Interest rate (12) (16) (46) Interest expense (97) (63) (68) Total before tax 23 21 13 Income tax (expense) recovery (74) (42) (55) Net of tax Pension and other post-retirement benefit plan adjustments Amortization of actuarial gains (losses) — (11) (22) Plant operating costs and other 2 Settlement gain (loss) — 2 2 Plant operating costs and other 2 — (9) (20) Total before tax — 3 6 Income tax (expense) recovery — (6) (14) Net of tax Equity investments Equity income (loss) 22 4 (37) Income (loss) from equity investments (6) (1) 9 Income tax (expense) recovery 16 3 (28) 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 28, Employee post-retirement benefits, for additional information.

EMPLOYEE POST-RETIREMENT BENE_2

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2023
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 2023 2022 2021 (millions of Canadian $) DB Plans 28 78 105 Other post-retirement benefit plans 9 8 8 Savings and DC Plans 64 64 58 101 150 171
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 $) 2023 2022 2023 2022 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,081 4,027 310 419 Service cost 93 145 3 5 Interest cost 158 125 16 13 Employee contributions 7 6 2 2 Benefits paid (185) (324) (44) (24) Actuarial (gain) loss 219 (949) 2 (120) Foreign exchange rate changes (17) 51 (4) 15 Benefit obligation – end of year 3,356 3,081 285 310 Change in Plan Assets Plan assets at fair value – beginning of year 3,481 4,145 354 431 Actual return on plan assets 385 (483) 24 (89) Employer contributions 2 28 78 9 8 Employee contributions 7 6 2 2 Benefits paid (185) (324) (23) (24) Foreign exchange rate changes (19) 59 (8) 26 Plan assets at fair value – end of year 3,697 3,481 358 354 Funded Status – Plan Surplus 341 400 73 44 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 The Company reduced letters of credit by $78 million in the Canadian DB Plan (2022 – nil) for funding purposes.
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 $) 2023 2022 2023 2022 Other long-term assets (Note 16) 341 400 177 163 Accounts payable and other — — (7) (8) Other long-term liabilities (Note 19) — — (97) (111) 341 400 73 44
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 $) 2023 2022 2023 2022 Projected benefit obligation 1 — — (104) (119) Plan assets at fair value — — — — Funded Status – Plan Deficit — — (104) (119) 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 2023 2022 (millions of Canadian $) Accumulated benefit obligation (3,090) (2,880) Plan assets at fair value 3,697 3,481 Funded Status – Plan Surplus 607 601
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 2023 2022 2023 Fixed income securities 41 % 38 % 30% to 50% Equity securities 44 % 44 % 30% to 55% Other investments 15 % 18 % 10% to 25% 100 % 100 %
Schedule of Allocation of Plan Assets, Employer and Related Party Securities	Fixed income and equity securities include the Company's debt and common shares as follows: at December 31 Percentage of (millions of Canadian $) 2023 2022 2023 2022 Fixed income securities 7 7 0.2 % 0.2 % Equity securities 2 3 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 29, 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 $) 2023 2022 2023 2022 2023 2022 2023 2022 2023 2022 Asset Category Cash and Cash Equivalents 68 55 1 1 — — 69 56 2 1 Equity Securities: Canadian 121 117 — — — — 121 117 3 3 U.S. 965 897 — — — — 965 897 24 24 International 167 172 187 172 — — 354 344 9 9 Global — — 74 75 — — 74 75 2 2 Emerging 54 50 140 127 — — 194 177 5 5 Fixed Income Securities: Canadian Bonds: Federal — — 266 221 — — 266 221 7 6 Provincial — — 314 249 — — 314 249 8 6 Municipal — — 16 12 — — 16 12 — — Corporate — — 143 108 — — 143 108 4 3 U.S. Bonds: Federal 185 177 240 158 — — 425 335 10 9 Municipal — — 1 1 — — 1 1 — — Corporate 312 345 74 94 — — 386 439 10 11 International: Government 4 5 11 6 — — 15 11 — — Corporate — — 83 58 — — 83 58 2 1 Mortgage backed 43 36 17 1 — — 60 37 1 1 Net forward contracts — — (131) (78) — — (131) (78) (4) (2) Other Investments: Real estate — — — — 283 336 283 336 7 9 Infrastructure — — — — 269 296 269 296 7 8 Private equity funds — — — — 10 — 10 — — — Funds held on deposit 138 144 — — — — 138 144 3 4 2,057 1,998 1,436 1,205 562 632 4,055 3,835 100 100
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, 2021 565 Purchases and sales 52 Realized and unrealized gains (losses) 15 Balance at December 31, 2022 632 Purchases and sales (76) Realized and unrealized gains (losses) 6 Balance at December 31, 2023 562
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 2024 204 23 2025 207 23 2026 211 23 2027 214 22 2028 216 22 2029 to 2033 1,127 104
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 2023 2022 2023 2022 Discount rate 4.75 % 5.15 % 5.10 % 5.45 % Rate of compensation increase 3.20 % 3.30 % — —
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 2023 2022 2021 2023 2022 2021 Discount rate 5.15 % 3.05 % 2.70 % 5.45 % 3.10 % 2.80 % Expected long-term rate of return on plan assets 6.45 % 6.10 % 6.15 % 4.50 % 3.25 % 3.00 % Rate of compensation increase 3.25 % 3.00 % 2.60 % — — —
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 $) 2023 2022 2021 2023 2022 2021 Service cost 1 93 145 171 3 5 6 Other components of net benefit cost 1 Interest cost 158 125 119 16 13 12 Expected return on plan assets (234) (239) (234) (16) (14) (13) Amortization of actuarial loss — 10 23 — 1 2 Amortization of regulatory asset — 12 27 — 1 2 Curtailment gain — — (5) — — — Settlement gain – AOCI — (2) (2) — — — (76) (94) (72) — 1 3 Net Benefit Cost Recognized 17 51 99 3 6 9 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 2023 2022 2021 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Net loss 71 6 38 24 147 5
Schedule of the Pre-Tax Amounts Recognized in OCI	Pre-tax amounts recognized in OCI were as follows: year ended December 31 2023 2022 2021 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Amortization of net gain (loss) from AOCI to net income — — (10) (1) (23) (2) Curtailment — — — — — 3 Settlement — — 2 — 2 — Funded status adjustment 33 (18) (101) 20 (190) (18) 33 (18) (109) 19 (211) (17)

RISK MANAGEMENT AND FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2023
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 2023 2022 Fair 1,2 Notional Amount Fair 1,2 Notional Amount (millions of Canadian $, unless otherwise noted) U.S. dollar foreign exchange options (maturing 2024) 8 US 1,000 (22) US 3,600 U.S. dollar cross-currency interest rate swaps (maturing 2024 to 2025) 3 2 US 200 (5) US 300 10 US 1,200 (27) US 3,900 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2023, Net income (loss) includes net realized gains of less than $1 million (2022 – gains of $1 million) related to the interest component of cross-currency swap settlements which are reported within Interest expense. The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2023 2022 (millions of Canadian $, unless otherwise noted) Notional amount 27,800 (US 21,100) 32,500 (US 24,000) Fair value 26,600 (US 20,200) 30,800 (US 22,700) 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, 2023 Power Natural Gas Liquids Foreign Exchange Interest Rate Net sales (purchases) 1,2 9,209 50 (7) — — Millions of U.S. dollars — — — 4,978 2,000 Millions of Mexican pesos — — — 20,000 — Maturity dates 2024-2044 2024-2029 2024 2024-2026 2030-2034 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively. 2 In 2023, the Company entered into contracts to sell 50 MW of power commencing in 2025 with terms ranging from 15 to 20 years and provided from specified renewable sources in the Province of Alberta. at December 31, 2022 Power Natural Gas Liquids Foreign Exchange Interest Rate Net sales (purchases) 1 673 (96) 11 — — Millions of U.S. dollars — — — 5,997 1,600 Millions of Mexican pesos — — — 9,747 — Maturity dates 2023-2026 2023-2027 2023-2024 2023-2026 2030-2032 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 2023 2022 Carrying Amount Fair Value Carrying Fair (millions of Canadian $) Long-term debt, including current portion (Note 21) 1,2 (52,914) (52,815) (41,543) (39,505) Junior subordinated notes (Note 22) (10,287) (9,217) (10,495) (9,415) (63,201) (62,032) (52,038) (48,920) 1 Long-term debt is recorded at amortized cost, except for US$2.0 billion (2022 – US$1.6 billion) that is attributed to hedged risk and recorded at fair value. 2 Net income (loss) for 2023 included unrealized losses of $53 million (2022 – unrealized gains of $64 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$2.0 billion of long-term debt at December 31, 2023 (2022 – US$1.6 billion). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments. 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 2023 2022 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 1 35 — 54 Maturing within 1-5 years 8 291 — 106 Maturing within 5-10 years 1,340 — 1,153 — Maturing after 10 years 102 — 77 — Fair value of equity securities 2,4 883 — 749 — 2,334 326 1,979 160 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, 2023 Cash Flow Hedges Fair Value Hedges Net Held for Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 9) Commodities 2 9 — — 1,195 1,204 Foreign exchange — — 10 71 81 9 — 10 1,266 1,285 Other long-term assets (Note 16) Commodities 2 3 — — 86 89 Foreign exchange — — — 30 30 Interest rate — 36 — — 36 3 36 — 116 155 Total Derivative Assets 12 36 10 1,382 1,440 Accounts payable and other (Note 18) Commodities 2 (1) — — (1,110) (1,111) Foreign exchange — — — (14) (14) Interest rate — (18) — — (18) (1) (18) — (1,124) (1,143) Other long-term liabilities (Note 19) Commodities 2 — — — (75) (75) Foreign exchange — — — (2) (2) Interest rate — (29) — — (29) — (29) — (77) (106) Total Derivative Liabilities (1) (47) — (1,201) (1,249) Total Derivatives 11 (11) 10 181 191 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. The balance sheet classification of the fair value of derivative instruments was as follows: at December 31, 2022 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 9) Commodities 2 — — — 597 597 Foreign exchange — — 6 11 17 — — 6 608 614 Other long-term assets (Note 16) Commodities 2 — — — 62 62 Foreign exchange — — 2 15 17 Interest rate — 12 — — 12 — 12 2 77 91 Total Derivative Assets — 12 8 685 705 Accounts payable and other (Note 18) Commodities 2 (72) — — (584) (656) Foreign exchange — — (31) (158) (189) Interest rate — (26) — — (26) (72) (26) (31) (742) (871) Other long-term liabilities (Note 19) Commodities 2 (2) — — (75) (77) Foreign exchange — — (4) (20) (24) Interest rate — (50) — — (50) (2) (50) (4) (95) (151) Total Derivative Liabilities (74) (76) (35) (837) (1,022) Total Derivatives (74) (64) (27) (152) (317) 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids.
Unrealized Gain (Loss) on Investments	year ended December 31 2023 2022 2021 (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) 190 13 (244) (7) 45 (2) Net realized gains (losses) 3 (34) — (32) — 3 — 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 2023 2022 2021 (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) 190 13 (244) (7) 45 (2) Net realized gains (losses) 3 (34) — (32) — 3 — 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 $) 2023 2022 2023 2022 Long-term debt (2,630) (2,101) 11 64 1 At December 31, 2023 and 2022, adjustments for discontinued hedging relationships included in these balances were nil. The following summary does not include hedges of the net investment in foreign operations: year ended December 31 2023 2022 2021 (millions of Canadian $) Derivative Instruments Held for Trading 1 Unrealized gains (losses) in the year Commodities 96 14 9 Foreign exchange (Note 23) 246 (149) (203) Realized gains (losses) in the year Commodities 811 759 287 Foreign exchange (Note 23) 155 (2) 240 Derivative Instruments in Hedging Relationships 2 Realized gains (losses) in the year Commodities (2) (73) (44) Interest rate (43) (3) (32) 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. 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. 2 In 2023, there were no gains or losses included in Net Income (loss) relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur (2022 – nil; 2021 – realized loss of $10 million). 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 2023 2022 2021 (millions of Canadian $) Fair Value Hedges Interest rate contracts 1 Hedged items (98) (30) — Derivatives designated as hedging instruments (43) (1) — Cash Flow Hedges Reclassification of gains (losses) on derivative instruments from AOCI to Net income (loss) 2,3 Commodity contracts 4 (85) (47) (22) Interest rate contracts 1 (12) (16) (46) 1 Presented within Interest expense in the Consolidated statement of income. 2 Refer to Note 27, 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.
Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships	The components of OCI (Note 27) 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 2023 2022 2021 (millions of Canadian $, pre-tax) Gains (losses) in fair value of derivative instruments recognized in OCI 1 Commodities — (94) (35) Interest rate — 36 22 — (58) (13) 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, 2023 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 1,293 (1,099) 194 Foreign exchange 111 (16) 95 Interest rate 36 (5) 31 1,440 (1,120) 320 Derivative Instrument Liabilities Commodities (1,186) 1,099 (87) Foreign exchange (16) 16 — Interest rate (47) 5 (42) (1,249) 1,120 (129) 1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2022 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 659 (591) 68 Foreign exchange 34 (33) 1 Interest rate 12 (4) 8 705 (628) 77 Derivative Instrument Liabilities Commodities (733) 591 (142) Foreign exchange (213) 33 (180) Interest rate (76) 4 (72) (1,022) 628 (394) 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, 2023 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 1,293 (1,099) 194 Foreign exchange 111 (16) 95 Interest rate 36 (5) 31 1,440 (1,120) 320 Derivative Instrument Liabilities Commodities (1,186) 1,099 (87) Foreign exchange (16) 16 — Interest rate (47) 5 (42) (1,249) 1,120 (129) 1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2022 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 659 (591) 68 Foreign exchange 34 (33) 1 Interest rate 12 (4) 8 705 (628) 77 Derivative Instrument Liabilities Commodities (733) 591 (142) Foreign exchange (213) 33 (180) Interest rate (76) 4 (72) (1,022) 628 (394) 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, 2023 Quoted Prices in Active Markets Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets Commodities 1,054 229 10 1,293 Foreign exchange — 111 — 111 Interest rate — 36 — 36 Derivative Instrument Liabilities Commodities (1,002) (163) (21) (1,186) Foreign exchange — (16) — (16) Interest rate — (47) — (47) 52 150 (11) 191 1 There were no transfers from Level II to Level III for the year ended December 31, 2023. In 2023, the Company entered into contracts to sell 50 MW of power commencing in 2025 with terms ranging from 15 to 20 years and 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, 2022 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 515 142 2 659 Foreign exchange — 34 — 34 Interest rate — 12 — 12 Derivative Instrument Liabilities Commodities (478) (242) (13) (733) Foreign exchange — (213) — (213) Interest rate — (76) — (76) 37 (343) (11) (317) 1 There were no transfers from Level II to Level III for the year ended December 31, 2022.
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) 2023 2022 Balance at beginning of year (11) (6) Net gains (losses) included in Net income (loss) (2) (10) Net gains (losses) included in OCI — (3) Transfers out of Level III 2 7 Settlements — 1 Balance at End of Year 1 (11) (11) 1 Revenues .

CHANGES IN OPERATING WORKING _2

CHANGES IN OPERATING WORKING CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2023
CHANGES IN OPERATING WORKING CAPITAL
Schedule of changes in operating working capital	year ended December 31 2023 2022 2021 (millions of Canadian $) (Increase) decrease in Accounts receivable (394) (575) (925) (Increase) decrease in Inventories (56) (190) (93) (Increase) decrease in Other current assets 618 118 (141) Increase (decrease) in Accounts payable and other (206) (83) 890 Increase (decrease) in Accrued interest 245 91 (18) (Increase) Decrease in Operating Working Capital 207 (639) (287)

COMMITMENTS, CONTINGENCIES AN_2

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)	12 Months Ended
	Dec. 31, 2023
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 2023 2022 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas Renewable to 2053 97 — 100 — Bruce Power Renewable to 2065 88 — 88 — Other jointly-owned entities to 2043 80 3 81 3 265 3 269 3 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, 2023
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 $) 2023 1 2022 ASSETS Current Assets Cash and cash equivalents 190 60 Accounts receivable 476 98 Inventories 90 32 Other current assets 49 14 805 204 Plant, Property and Equipment 27,649 3,997 Equity Investments 823 748 Regulatory Assets 12 — Goodwill 439 449 29,728 5,398 LIABILITIES Current Liabilities Accounts payable and other 1,135 234 Accrued interest 210 18 Current portion of long-term debt 28 31 1,373 283 Regulatory Liabilities 280 78 Other Long-Term Liabilities 56 1 Deferred Income Tax Liabilities 22 16 Long-Term Debt 11,388 2,136 13,119 2,514 1 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 24, Non-controlling interests, and Note 31, 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 $) 2023 2022 Balance Sheet Exposure Equity investments Bruce Power 6,241 5,783 Pipeline equity investments and other 1,411 1,148 Off-Balance Sheet Exposure 1 Bruce Power 1,538 2,025 Coastal GasLink 2 855 3,300 Pipeline equity investments 58 58 Maximum exposure to loss 10,103 12,314 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. At December 31, 2023, the total capacity committed by TC Energy under this subordinated loan agreement was $3,375 million (December 31, 2022 – $1,262 million). In the year ended December 31, 2023, $2,520 million was drawn on the subordinated loan, reducing the Company's funding commitment under the subordinated loan agreement to $855 million. Refer to Note 8, Coastal GasLink, for further information.

DESCRIPTION OF TC ENERGY'S BU_2

DESCRIPTION OF TC ENERGY'S BUSINESS (Details)	12 Months Ended
	Dec. 31, 2023 plant segment km mi Bcf
Segment Reporting Information [Line Items]
Number of business segments in which the entity operates (in segments) | segment	5
Canadian Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) | km	40,596
Investments of regulated natural gas pipelines (in miles) | mi	25,226
U.S. Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) | km	50,088
Investments of regulated natural gas pipelines (in miles) | mi	31,123
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	2,895
Investments of regulated natural gas pipelines (in miles) | mi	1,798
Liquids Pipelines
Segment Reporting Information [Line Items]
Wholly owned and operated crude oil pipeline systems (in kilometers) | km	4,865
Wholly owned and operated crude oil pipeline systems (in miles) | mi	3,024
Power and Energy Solutions
Segment Reporting Information [Line Items]
Number of electrical power generation plants (in plants) | plant	4,600
Non-regulated natural gas storage facilities (in billion cubic feet) | Bcf	118

ACCOUNTING POLICIES (Details)

ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2023
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 | Pipeline | Liquids Pipelines
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	2%
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 | Pipeline | Liquids Pipelines
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	2.50%
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%

SPINOFF OF LIQUIDS PIPELINES _2

SPINOFF OF LIQUIDS PIPELINES BUSINESS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)
Spin off Transactions [Abstract]
Pre tax separation, before reclassification	$ 40
Pre tax separation, before reclassification, after Tax	$ 34

SEGMENTED INFORMATION - Schedul

SEGMENTED INFORMATION - Schedule of Segment Reporting Information, by Segment (Details) - CAD ($) $ in Millions		12 Months Ended
	Mar. 15, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segmented information
Revenues		$ 15,934	$ 14,977	$ 13,387
Income (loss) from equity investments		1,377	1,054	898
Impairment of equity investment		(2,100)	(3,048)	0
Plant operating costs and other		(4,887)	(4,932)	(4,098)
Commodity purchases resold		(517)	(534)	(87)
Property taxes		(897)	(848)	(774)
Depreciation and amortization		(2,778)	(2,584)	(2,522)
Goodwill and asset impairment charges and other		4	(453)	(2,775)
Net gain (loss) on sale of assets		0	0	30
Segmented Earnings (Losses)		6,136	3,632	4,059
Interest expense		(3,263)	(2,588)	(2,360)
Allowance for funds used during construction		575	369	267
Foreign exchange gain (loss), net		320	(185)	10
Interest income and other		242	146	190
Income (Loss) before Income Taxes		4,010	1,374	2,166
Income tax (expense) recovery		(942)	(589)	(120)
Net Income (Loss)		3,068	785	2,046
Net (income) loss attributable to non-controlling interests		(146)	(37)	(91)
Net Income (Loss) Attributable to Controlling Interests		2,922	748	1,955
Preferred share dividends		(93)	(107)	(140)
Net Income (Loss) Attributable to Common Shares		2,829	641	1,815
Capital Spending3
Capital expenditures		8,007	6,678	5,924
Capital projects in development		142	49	0
Contributions to equity method investments, net of other corporate distributions			2,234
Contributions to equity investments, net of distributions		4,149
Contributions to equity investments		4,149	3,433	1,210
Capital Spending		12,298	8,961	7,134
Assets		125,034	114,348
Sur de Texas | Line of credit | Joint venture
Capital Spending3
Contributions to equity investments, net of distributions	$ 1,200
Intersegment eliminations
Segmented information
Revenues		(123)	(144)	(159)
Corporate
Segmented information
Revenues		(123)	(144)	(159)
Income (loss) from equity investments		0	28	41
Impairment of equity investment		0	0
Plant operating costs and other		7	124	72
Commodity purchases resold		0	0	0
Property taxes		0	0	0
Depreciation and amortization		0	0	0
Goodwill and asset impairment charges and other		0	0	0
Net gain (loss) on sale of assets				0
Segmented Earnings (Losses)		(116)	8	(46)
Capital Spending3
Capital expenditures		33	41	35
Capital projects in development		0	0
Contributions to equity investments, net of distributions		0
Contributions to equity investments			0	0
Capital Spending		33	41	35
Assets		7,735	3,764
Canadian Natural Gas Pipelines
Segmented information
Revenues		5,173	4,764	4,519
Canadian Natural Gas Pipelines | Operating segments
Segmented information
Revenues		5,173	4,764	4,519
Income (loss) from equity investments		220	18	12
Impairment of equity investment		(2,100)	(3,048)
Plant operating costs and other		(1,756)	(1,679)	(1,567)
Commodity purchases resold		0	0	0
Property taxes		(302)	(297)	(289)
Depreciation and amortization		(1,325)	(1,198)	(1,226)
Goodwill and asset impairment charges and other		0	0	0
Net gain (loss) on sale of assets				0
Segmented Earnings (Losses)		(90)	(1,440)	1,449
Capital Spending3
Capital expenditures		2,953	3,274	2,629
Capital projects in development		0	0
Contributions to equity investments, net of distributions		3,231
Contributions to equity investments			1,445	108
Capital Spending		6,184	4,719	2,737
Assets		29,782	27,456
Canadian Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues		0	0	0
U.S. Natural Gas Pipelines
Segmented information
Revenues		6,229	5,933	5,233
U.S. Natural Gas Pipelines | Operating segments
Segmented information
Revenues		6,330	6,065	5,378
Income (loss) from equity investments		324	292	244
Impairment of equity investment		0	0
Plant operating costs and other		(1,660)	(1,856)	(1,393)
Commodity purchases resold		(56)	0	0
Property taxes		(473)	(426)	(367)
Depreciation and amortization		(934)	(887)	(791)
Goodwill and asset impairment charges and other		0	(571)	0
Net gain (loss) on sale of assets				0
Segmented Earnings (Losses)		3,531	2,617	3,071
Capital Spending3
Capital expenditures		2,536	2,137	2,611
Capital projects in development		0	0
Contributions to equity investments, net of distributions		124
Contributions to equity investments			0	209
Capital Spending		2,660	2,137	2,820
Assets		50,499	50,038
U.S. Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues		(101)	(132)	(145)
Mexico Natural Gas Pipelines
Segmented information
Revenues		846	688	605
Mexico Natural Gas Pipelines | Operating segments
Segmented information
Revenues		846	688	605
Income (loss) from equity investments		78	122	119
Impairment of equity investment		0	0
Plant operating costs and other		(39)	(221)	(55)
Commodity purchases resold		0	0	(3)
Property taxes		0	0	0
Depreciation and amortization		(89)	(98)	(109)
Goodwill and asset impairment charges and other		0	0	0
Net gain (loss) on sale of assets				0
Segmented Earnings (Losses)		796	491	557
Capital Spending3
Capital expenditures		2,292	1,027	129
Capital projects in development		0	0
Contributions to equity investments, net of distributions		0
Contributions to equity investments			0	0
Capital Spending		2,292	1,027	129
Assets		12,003	9,231
Mexico Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues		0	0	0
Liquids Pipelines
Segmented information
Revenues		2,667	2,668	2,306
Liquids Pipelines | Operating segments
Segmented information
Revenues		2,667	2,668	2,306
Income (loss) from equity investments		67	55	71
Impairment of equity investment		0	0
Plant operating costs and other		(836)	(756)	(700)
Commodity purchases resold		(437)	(512)	(84)
Property taxes		(116)	(121)	(113)
Depreciation and amortization		(338)	(329)	(318)
Goodwill and asset impairment charges and other		4	118	(2,775)
Net gain (loss) on sale of assets				13
Segmented Earnings (Losses)		1,011	1,123	(1,600)
Capital Spending3
Capital expenditures		49	106	488
Capital projects in development		0	0
Contributions to equity investments, net of distributions		0
Contributions to equity investments			37	83
Capital Spending		49	143	571
Assets		15,490	15,587
Liquids Pipelines | Intersegment eliminations
Segmented information
Revenues		0	0	0
Power and Energy Solutions
Segmented information
Revenues		1,019	924	724
Power and Energy Solutions | Operating segments
Segmented information
Revenues		1,041	936	738
Income (loss) from equity investments		688	539	411
Impairment of equity investment		0	0
Plant operating costs and other		(603)	(544)	(455)
Commodity purchases resold		(24)	(22)	0
Property taxes		(6)	(4)	(5)
Depreciation and amortization		(92)	(72)	(78)
Goodwill and asset impairment charges and other		0	0	0
Net gain (loss) on sale of assets				17
Segmented Earnings (Losses)		1,004	833	628
Capital Spending3
Capital expenditures		144	93	32
Capital projects in development		142	49
Contributions to equity investments, net of distributions		794
Contributions to equity investments			752	810
Capital Spending		1,080	894	842
Assets		9,525	8,272
Power and Energy Solutions | Intersegment eliminations
Segmented information
Revenues		$ (22)	$ (12)	$ (14)

SEGMENTED INFORMATION - Revenue

SEGMENTED INFORMATION - Revenue from External Customers by Geographic Areas (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Revenues	$ 15,934	$ 14,977	$ 13,387
Canada – domestic
Segment Reporting Information [Line Items]
Revenues	5,360	4,942	4,603
Canada – export
Segment Reporting Information [Line Items]
Revenues	1,403	1,322	1,226
United States
Segment Reporting Information [Line Items]
Revenues	8,325	8,025	6,953
Mexico
Segment Reporting Information [Line Items]
Revenues	$ 846	$ 688	$ 605

SEGMENTED INFORMATION - Sched_2

SEGMENTED INFORMATION - Schedule of Long-Lived Assets by Country (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 80,569	$ 75,940
Canada
Segment Reporting Information [Line Items]
Property, plant and equipment, net	28,583	27,232
United States
Segment Reporting Information [Line Items]
Property, plant and equipment, net	44,609	43,505
Mexico
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 7,377	$ 5,203

REVENUES - Disaggregation of Re

REVENUES - Disaggregation of Revenues (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 14,629	$ 14,112	$ 12,952
Other revenues	1,026	738	435
Revenues	15,934	14,977	13,387
Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	12,805	11,807	11,172
Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	427	490	324
Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,397	1,815	1,456
Canadian Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5,173	4,764	4,519
Sales-type lease income	0	0
Other revenues	0	0	0
Revenues	$ 5,173	4,764	4,519
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	$ 5,141	4,696	4,432
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	32	68	87
Canadian Natural Gas Pipelines | Coastal GasLink | Related party
Disaggregation of Revenue [Line Items]
Revenues	31	68	87
U.S. Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5,981	5,919	5,196
Sales-type lease income	0	0
Other revenues	248	14	37
Revenues	6,229	5,933	5,233
U.S. Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5,107	4,621	4,139
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	874	1,298	1,057
Mexico Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	567	561	605
Sales-type lease income	279	127
Other revenues	0	0	0
Revenues	846	688	605
Mexico Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	442	507	576
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	125	54	29
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,118	1,987	2,030
Sales-type lease income	0	0
Other revenues	549	681	276
Revenues	2,667	2,668	2,306
Liquids Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,115	1,983	2,025
Liquids Pipelines | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Liquids Pipelines | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3	4	5
Power and Energy Solutions
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	790	881	602
Sales-type lease income	0	0
Other revenues	229	43	122
Revenues	1,019	924	724
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	427	490	324
Power and Energy Solutions | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	363	391	$ 278
TGNH Pipelines | Non-lease components
Disaggregation of Revenue [Line Items]
Revenues	$ 97	$ 37

REVENUES - Contract Balances (D

REVENUES - Contract Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 1,832	$ 1,907
Contract assets (Note 9)	151	155
Long-term contract assets (Note 16)	457	355
Contract liabilities (Note 6)	69	62
Long-term contract liabilities1 (Note 19)	12	32
Revenue recognized	$ 64	$ 51

REVENUES - Remaining Performanc

REVENUES - Remaining Performance Obligations - Narrative (Details) $ in Billions	Dec. 31, 2023 CAD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 22.9
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 4.9
Future revenues, expected timing of satisfaction, period	1 year

KEYSTONE XL - Narrative (Detail

KEYSTONE XL - Narrative (Details) $ in Millions, $ in Millions			1 Months Ended		12 Months Ended
	Jan. 08, 2021 CAD ($)	Jan. 08, 2021 USD ($)	Jun. 30, 2021 CAD ($)	Jan. 31, 2021 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 CAD ($)	Jun. 30, 2021 USD ($)	Jan. 04, 2021 USD ($)
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net					$ 80,569	$ 75,940
Proceeds from sales of assets, net of transaction costs					33	0	$ 35
Goodwill, expected tax deductible amount					0	91	0
Class A interests issued									$ 1,033
Repurchase of Class A Interests					0	0	633
Keystone XL project-level facility retirement and issuance of Class C interests, before taxes							937
Keystone XL project-level credit facility retirement and issuance of Class C Interests (Note 7)							737
Payments to noncontrolling interests					49	43	16
Additional Paid-In Capital
Property, Plant and Equipment [Line Items]
Aggregate transaction value							(394)
Keystone XL project-level credit facility retirement and issuance of Class C Interests (Note 7)							737
Class C Interests
Property, Plant and Equipment [Line Items]
Stock issued during period					32
Class C Interests | Government of Alberta
Property, Plant and Equipment [Line Items]
Payments to noncontrolling interests					49	43	16
Class C Interests | Government of Alberta | Additional Paid-In Capital
Property, Plant and Equipment [Line Items]
Aggregate transaction value			$ 394
Keystone XL | U.S. federal
Property, Plant and Equipment [Line Items]
Goodwill, expected tax deductible amount					14	96
Project Level Credit Facility due June 2021 | Line of credit | Keystone XL
Property, Plant and Equipment [Line Items]
Revolving credit facility, borrowing capacity				$ 4,100						$ 1,600	$ 4,100
Amount				$ 849			1,028	$ 849
Keystone XL
Property, Plant and Equipment [Line Items]
Goodwill and asset impairment charges and other (Notes 7 and 15)					2	24	192
Contractual recoveries					10	571
Remaining contractual recoveries					117	130
Changes in asset impairments						54
Legal obligations and termination accruals					45	48
Proceeds from sales of assets, net of transaction costs					63	25	16
Gain (loss) on disposition of property plant equipment					$ 36	$ 64	0
Keystone XL | Class C Interests | Government of Alberta
Property, Plant and Equipment [Line Items]
Stock issued during period							91
Keystone XL | Liquids Pipelines
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net							175
Goodwill and asset impairment charges and other (Notes 7 and 15)							2,775
Asset impairment charges, net of tax							2,134
Contractual recoveries							693
Repurchase of Class A Interests	$ 633	$ 497
Keystone XL | Liquids Pipelines | Carrying Amount | Power generation and natural gas storage plant, equipment and structures
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net							3,301
Keystone XL | Liquids Pipelines | Fair Value
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net							175
Keystone XL | Liquids Pipelines | Fair Value | Power generation and natural gas storage plant, equipment and structures
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net							175
Keystone XL | Liquids Pipelines | Fair Value | Under construction
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net							$ 0

KEYSTONE XL - Impairment of Lon

KEYSTONE XL - Impairment of Long-Lived Assets Held and Used (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment (Note 10)	$ 80,569	$ 75,940
Asset impairment charge and other, Pre-tax
Goodwill and asset impairment charges and other (Notes 7 and 15)	(4)	453	$ 2,775
Keystone XL
Asset impairment charge and other, Pre-tax
Contractual recoveries	(10)	(571)
Goodwill and asset impairment charges and other (Notes 7 and 15)	$ 2	$ 24	192
Keystone XL | Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment (Note 10)			175
Asset impairment charge and other, Pre-tax
Plant and equipment			412
Related capital projects in development			230
Other capitalized costs			2,158
Capitalized interest			326
Goodwill and asset impairment charges and other (Notes 7 and 15)			3,126
Contractual recoveries			(693)
Contractual and legal obligations related to termination activities			342
Goodwill and asset impairment charges and other (Notes 7 and 15)			2,775
Asset impairment charge and other, After-tax
Plant and equipment			312
Related capital projects in development			175
Other capitalized costs			1,642
Capitalized interest			248
Asset impairment charge, After-tax			2,377
Contractual recoveries			(525)
Contractual and legal obligations related to termination activities			282
Asset impairment charges, net of tax			2,134
Keystone XL | Fair Value | Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment (Note 10)			175
Keystone XL | Fair Value | Plant and equipment | Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment (Note 10)			175
Keystone XL | Fair Value | Related capital projects in development | Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment (Note 10)			0
Keystone XL | Fair Value | Other capitalized costs | Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment (Note 10)			0
Keystone XL | Fair Value | Capitalized interest | Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment (Note 10)			$ 0

COASTAL GASLINK - Narrative (De

COASTAL GASLINK - Narrative (Details) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2023 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Equity Investments
Equity Investments (Note 12)		$ 10,314	$ 9,535
Repayments of subordinated debt	$ 250
Coastal GasLink
Equity Investments
Impairment losses pre tax		5,148
Impairment charges after tax		4,586
Equity Investments (Note 12)		294	$ 0
Additional aggregate cost		900
Coastal GasLink | Expected term | Discounted cash flow
Equity Investments
Equity method investments, measurement input			40
Coastal GasLink | Coastal GasLink | Subordinated Loan Agreement | Subordinated debt
Equity Investments
Revolving credit facility, borrowing capacity	$ 2,020	3,375	$ 1,262
Line of credit facility, outstanding amount		2,500
Coastal GasLink | Canadian Natural Gas Pipelines
Equity Investments
Impairment losses pre tax		2,100	3,048
Impairment charges after tax		1,943	2,643
Coastal GasLink | Canadian Natural Gas Pipelines
Equity Investments
Equity Investments (Note 12)		294	0
Expected cost of pipeline project		$ 14,500	$ 14,500

COASTAL GASLINK - Changes in Lo

COASTAL GASLINK - Changes in Loan Balances (Details) - Subordinated Loan Agreement - Subordinated debt - Coastal GasLink - Related party - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Related Party Transaction [Roll Forward]
Beginning balance	$ 250	$ 238
Issuances	2,520	112
Repayments	(250)	(100)
Ending balance	2,520	250
Impairment during the year	(2,020)	(250)
Carrying value at end of year	$ 500	$ 0

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Other Assets [Abstract]
Fair value of derivative contracts (Note 29)	$ 1,285	$ 614
Current portion of net investment in leases (Note 11)	306	291
Current portion of Keystone environmental provision recovery (Note 18)	150	410
Contract assets (Note 6)	151	155
Cash provided as collateral	120	106
Emissions credits	94	36
Prepaid expenses	92	118
Keystone XL contractual recoveries (Note 7)	83	86
Regulatory assets (Note 14)	76	67
Keystone XL assets held for sale	58	122
Other	88	147
Other current assets	$ 2,503	$ 2,152

PLANT, PROPERTY AND EQUIPMENT_2

PLANT, PROPERTY AND EQUIPMENT (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Cost	$ 117,171	$ 110,569
Accumulated Depreciation	36,602	34,629
Net Book Value	80,569	75,940
TGNH Pipelines
Property, Plant and Equipment [Line Items]
Sales-type lease, net investment in lease, before allowance for credit loss	407	2,319
Operating segments | Canadian Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	48,122	45,654
Accumulated Depreciation	23,374	22,286
Net Book Value	24,748	23,368
Operating segments | Canadian Natural Gas Pipelines | NGTL System
Property, Plant and Equipment [Line Items]
Cost	29,211	27,454
Accumulated Depreciation	10,034	9,278
Net Book Value	19,177	18,176
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	16,042	15,761
Accumulated Depreciation	11,658	11,384
Net Book Value	4,384	4,377
Operating segments | Canadian Natural Gas Pipelines | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	2,869	2,439
Accumulated Depreciation	1,682	1,624
Net Book Value	1,187	815
Operating segments | Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | NGTL System
Property, Plant and Equipment [Line Items]
Cost	28,424	25,902
Accumulated Depreciation	10,034	9,278
Net Book Value	18,390	16,624
Operating segments | Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	15,895	15,492
Accumulated Depreciation	11,658	11,384
Net Book Value	4,237	4,108
Operating segments | Canadian Natural Gas Pipelines | Pipeline | NGTL System
Property, Plant and Equipment [Line Items]
Cost	20,232	18,119
Accumulated Depreciation	6,855	6,285
Net Book Value	13,377	11,834
Operating segments | Canadian Natural Gas Pipelines | Pipeline | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	10,729	10,472
Accumulated Depreciation	7,996	7,852
Net Book Value	2,733	2,620
Operating segments | Canadian Natural Gas Pipelines | Compression | NGTL System
Property, Plant and Equipment [Line Items]
Cost	6,603	6,265
Accumulated Depreciation	2,349	2,224
Net Book Value	4,254	4,041
Operating segments | Canadian Natural Gas Pipelines | Compression | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	4,437	4,328
Accumulated Depreciation	3,354	3,247
Net Book Value	1,083	1,081
Operating segments | Canadian Natural Gas Pipelines | Metering and other | NGTL System
Property, Plant and Equipment [Line Items]
Cost	1,589	1,518
Accumulated Depreciation	830	769
Net Book Value	759	749
Operating segments | Canadian Natural Gas Pipelines | Metering and other | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	729	692
Accumulated Depreciation	308	285
Net Book Value	421	407
Operating segments | Canadian Natural Gas Pipelines | Under construction | NGTL System
Property, Plant and Equipment [Line Items]
Cost	787	1,552
Accumulated Depreciation	0	0
Net Book Value	787	1,552
Operating segments | Canadian Natural Gas Pipelines | Under construction | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	147	269
Accumulated Depreciation	0	0
Net Book Value	147	269
Operating segments | Canadian Natural Gas Pipelines | Under construction | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	23	455
Accumulated Depreciation	0	0
Net Book Value	23	455
Operating segments | Canadian Natural Gas Pipelines | Other | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	2,846	1,984
Accumulated Depreciation	1,682	1,624
Net Book Value	1,164	360
Operating segments | U.S. Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	42,787	41,289
Accumulated Depreciation	7,818	7,335
Net Book Value	34,969	33,954
Operating segments | U.S. Natural Gas Pipelines | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	11,606	11,098
Accumulated Depreciation	3,752	3,610
Net Book Value	7,854	7,488
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	23,107	22,346
Accumulated Depreciation	2,178	1,910
Net Book Value	20,929	20,436
Operating segments | U.S. Natural Gas Pipelines | ANR
Property, Plant and Equipment [Line Items]
Cost	8,074	7,845
Accumulated Depreciation	1,888	1,815
Net Book Value	6,186	6,030
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	11,022	10,770
Accumulated Depreciation	3,752	3,610
Net Book Value	7,270	7,160
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	22,336	21,687
Accumulated Depreciation	2,178	1,910
Net Book Value	20,158	19,777
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | ANR
Property, Plant and Equipment [Line Items]
Cost	7,670	7,517
Accumulated Depreciation	1,888	1,815
Net Book Value	5,782	5,702
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	2,071	1,928
Accumulated Depreciation	800	760
Net Book Value	1,271	1,168
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	12,952	12,471
Accumulated Depreciation	1,247	1,069
Net Book Value	11,705	11,402
Operating segments | U.S. Natural Gas Pipelines | Pipeline | ANR
Property, Plant and Equipment [Line Items]
Cost	2,117	2,066
Accumulated Depreciation	657	641
Net Book Value	1,460	1,425
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Columbia Gulf
Property, Plant and Equipment [Line Items]
Cost	3,600	3,511
Accumulated Depreciation	256	224
Net Book Value	3,344	3,287
Operating segments | U.S. Natural Gas Pipelines | Pipeline | GTN
Property, Plant and Equipment [Line Items]
Cost	2,992	2,964
Accumulated Depreciation	1,295	1,239
Net Book Value	1,697	1,725
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Great Lakes
Property, Plant and Equipment [Line Items]
Cost	2,359	2,367
Accumulated Depreciation	1,401	1,387
Net Book Value	958	980
Operating segments | U.S. Natural Gas Pipelines | Compression | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	5,310	5,190
Accumulated Depreciation	559	495
Net Book Value	4,751	4,695
Operating segments | U.S. Natural Gas Pipelines | Compression | ANR
Property, Plant and Equipment [Line Items]
Cost	3,928	3,785
Accumulated Depreciation	773	734
Net Book Value	3,155	3,051
Operating segments | U.S. Natural Gas Pipelines | Metering and other | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	4,074	4,026
Accumulated Depreciation	372	346
Net Book Value	3,702	3,680
Operating segments | U.S. Natural Gas Pipelines | Metering and other | ANR
Property, Plant and Equipment [Line Items]
Cost	1,625	1,666
Accumulated Depreciation	458	440
Net Book Value	1,167	1,226
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	584	328
Accumulated Depreciation	0	0
Net Book Value	584	328
Operating segments | U.S. Natural Gas Pipelines | Under construction | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	771	659
Accumulated Depreciation	0	0
Net Book Value	771	659
Operating segments | U.S. Natural Gas Pipelines | Under construction | ANR
Property, Plant and Equipment [Line Items]
Cost	404	328
Net Book Value	404	328
Operating segments | Mexico Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	7,955	5,707
Accumulated Depreciation	589	520
Net Book Value	7,366	5,187
Operating segments | Mexico Natural Gas Pipelines | Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost	3,132	3,160
Accumulated Depreciation	589	520
Net Book Value	2,543	2,640
Operating segments | Mexico Natural Gas Pipelines | Pipeline
Property, Plant and Equipment [Line Items]
Cost	2,280	2,299
Accumulated Depreciation	387	348
Net Book Value	1,893	1,951
Operating segments | Mexico Natural Gas Pipelines | Compression
Property, Plant and Equipment [Line Items]
Cost	370	374
Accumulated Depreciation	79	59
Net Book Value	291	315
Operating segments | Mexico Natural Gas Pipelines | Metering and other
Property, Plant and Equipment [Line Items]
Cost	482	487
Accumulated Depreciation	123	113
Net Book Value	359	374
Operating segments | Mexico Natural Gas Pipelines | Under construction
Property, Plant and Equipment [Line Items]
Cost	4,823	2,547
Accumulated Depreciation	0	0
Net Book Value	4,823	2,547
Operating segments | Liquids Pipelines
Property, Plant and Equipment [Line Items]
Cost	14,580	14,859
Accumulated Depreciation	3,462	3,222
Net Book Value	11,118	11,637
Operating segments | Liquids Pipelines | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	14,377	14,660
Accumulated Depreciation	3,437	3,203
Net Book Value	10,940	11,457
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines
Property, Plant and Equipment [Line Items]
Cost	203	199
Accumulated Depreciation	25	19
Net Book Value	178	180
Operating segments | Liquids Pipelines | Property, plant and equipment excluding under construction | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	14,323	14,564
Accumulated Depreciation	3,437	3,203
Net Book Value	10,886	11,361
Operating segments | Liquids Pipelines | Pipeline | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	9,569	9,777
Accumulated Depreciation	2,212	2,056
Net Book Value	7,357	7,721
Operating segments | Liquids Pipelines | Pumping equipment | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	1,096	1,064
Accumulated Depreciation	312	288
Net Book Value	784	776
Operating segments | Liquids Pipelines | Tanks and other | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	3,658	3,723
Accumulated Depreciation	913	859
Net Book Value	2,745	2,864
Operating segments | Liquids Pipelines | Under construction | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	54	96
Accumulated Depreciation	0	0
Net Book Value	54	96
Operating segments | Power and Energy Solutions
Property, Plant and Equipment [Line Items]
Cost	2,818	2,160
Accumulated Depreciation	912	880
Net Book Value	1,906	1,280
Operating segments | Power and Energy Solutions | Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost	2,665	2,080
Accumulated Depreciation	912	880
Net Book Value	1,753	1,200
Operating segments | Power and Energy Solutions | Natural Gas
Property, Plant and Equipment [Line Items]
Cost	1,239	1,260
Accumulated Depreciation	637	642
Net Book Value	602	618
Operating segments | Power and Energy Solutions | Natural Gas Storage and Other
Property, Plant and Equipment [Line Items]
Cost	845	820
Accumulated Depreciation	256	238
Net Book Value	589	582
Operating segments | Power and Energy Solutions | Renewable Power Generation
Property, Plant and Equipment [Line Items]
Cost	581	0
Accumulated Depreciation	19	0
Net Book Value	562	0
Operating segments | Power and Energy Solutions | Under construction
Property, Plant and Equipment [Line Items]
Cost	153	80
Accumulated Depreciation	0	0
Net Book Value	153	80
Corporate
Property, Plant and Equipment [Line Items]
Cost	909	900
Accumulated Depreciation	447	386
Net Book Value	$ 462	$ 514

LEASES - (Lessee) Narrative (De

LEASES - (Lessee) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Operating lease termination period	1 year
Right-of-use asset	$ 437	$ 415
Mexico Natural Gas Pipelines
Lessee, Lease, Description [Line Items]
Sales-type lease income	$ 279	$ 127
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, 2023	Dec. 31, 2022
Operating lease cost
Operating lease cost	$ 118	$ 106
Sublease income	(4)	(5)
Net operating lease cost	114	101
Cash paid for amounts included in the measurement of operating lease liabilities	72	67
ROU assets obtained in exchange for new operating lease liabilities	$ 84	$ 49
Weighted average remaining lease term	13 years	8 years
Weighted average discount rate	3.30%	3.50%

LEASES - (Lessee) Maturities of

LEASES - (Lessee) Maturities of Operating Lease Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Less than one year	$ 72	$ 68
One to two years	68	65
Two to three years	66	62
Three to four years	59	60
Four to five years	58	54
More than five years	225	187
Total operating lease payments	548	496
Imputed interest	(89)	(63)
Operating lease liabilities	459	433
Operating lease, reported as accounts payable and other	58	54
Operating lease, reported as other long-term liabilities	$ 401	$ 379
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts payable and other (Note 18)	Accounts payable and other (Note 18)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other Long-Term Liabilities (Note 19)	Other Long-Term Liabilities (Note 19)

LEASES - (Lessor) Narrative (De

LEASES - (Lessor) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Fixed portion of the operating lease income	$ 116	$ 118	$ 126
Cost for facilities accounted for as operating leases	796	802
Accumulated depreciation for facilities accounted for as operating leases	$ 370	$ 360

LEASES - (Lessor) Future Lease

LEASES - (Lessor) Future Lease Payments to be Received Under Operating Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Less than one year	$ 113	$ 113
One to two years	94	111
Two to three years	70	94
Three to four years	0	70
Total payments to be received	$ 277	$ 388

LEASES - Sale Type Leases Narra

LEASES - Sale Type Leases Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Expected credit loss provision (Note 29)	$ (83)	$ 163	$ 0
TGNH Pipelines
Lessee, Lease, Description [Line Items]
Expected credit loss provision (Note 29)	73	149	$ 0
Mexico Natural Gas Pipelines | TGNH Pipelines
Lessee, Lease, Description [Line Items]
Sales-type lease, aggregate investment	$ 407	$ 2,319

LEASES - Component of Aggregate

LEASES - Component of Aggregate Investment in Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Minimum lease payments	$ 9,627	$ 9,457
Unearned lease income	(7,006)	(7,132)
Lease receivable	2,621	2,325
Expected credit loss provision	(76)	(150)
Present value of unguaranteed residual value	24	11
Sales-type lease, net investment in lease, before allowance for credit loss	2,569	2,186
Current portion included in Other current assets (Note 9)	(306)	(291)
Sales-type lease, net investment in lease, before allowance for credit loss, noncurrent	2,263	1,895
Currency Translation Adjustments
Lessee, Lease, Description [Line Items]
Expected credit loss provision	$ 0	$ 1

LEASES - Sales-Type Leases (Det

LEASES - Sales-Type Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Less than one year	$ 305	$ 291
One to two years	305	291
Two to three years	305	291
Three to four years	305	291
Four to five years	305	291
More than five years	8,102	8,002
Payments to be received	$ 9,627	$ 9,457

EQUITY INVESTMENTS - Ownership

EQUITY INVESTMENTS - Ownership Information of Equity Investments (Details) - CAD ($) $ in Millions	1 Months Ended		12 Months Ended
	Dec. 31, 2023	Nov. 30, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity Investments
Income (Loss) from Equity Investments			$ 1,377	$ 1,054	$ 898
Equity Investments	$ 10,314		$ 10,314	9,535
TQM | Canadian Natural Gas Pipelines
Equity Investments
Ownership interest percentage	50%		50%
Income (Loss) from Equity Investments			$ 17	17	12
Equity Investments	$ 166		$ 166	165
Coastal GasLink | Canadian Natural Gas Pipelines
Equity Investments
Ownership interest percentage	35%		35%
Income (Loss) from Equity Investments			$ 203	1	0
Equity Investments	$ 294		$ 294	0
Northern Border | U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage	50%		50%
Income (Loss) from Equity Investments			$ 101	92	80
Equity Investments	$ 599		$ 599	516
Millennium | U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage	47.50%		47.50%
Income (Loss) from Equity Investments			$ 109	103	91
Equity Investments	$ 476		$ 476	500
Iroquois | U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage	50%		50%
Income (Loss) from Equity Investments			$ 98	77	55
Equity Investments	$ 227		227	237
Other | U.S. Natural Gas Pipelines
Equity Investments
Income (Loss) from Equity Investments			16	20	18
Equity Investments	120		120	122
Other | Power and Energy Solutions
Equity Investments
Income (Loss) from Equity Investments			(2)	2	0
Equity Investments	$ 38		$ 38	30
Sur de Texas | Mexico Natural Gas Pipelines
Equity Investments
Ownership interest percentage	60%		60%
Income (Loss) from Equity Investments			$ 78	150	160
Equity Investments	$ 1,078		$ 1,078	1,050
Grand Rapids | Liquids Pipelines
Equity Investments
Ownership interest percentage	50%		50%
Income (Loss) from Equity Investments			$ 53	54	54
Equity Investments	$ 932		$ 932	964
Port Neches Link LLC | Liquids Pipelines
Equity Investments
Ownership interest percentage	74.90%		74.90%
Income (Loss) from Equity Investments			$ 13	0	0
Equity Investments	$ 124		$ 124	149
Ownership interest sold	20.10%
HoustonLink Pipeline | Liquids Pipelines
Equity Investments
Ownership interest percentage	50%		50%
Income (Loss) from Equity Investments			$ 1	1	1
Equity Investments	$ 18		18	19
Northern Courier | Liquids Pipelines
Equity Investments
Income (Loss) from Equity Investments			0	0	16
Equity Investments	$ 0		$ 0	0
Ownership interest sold		15%
Bruce Power | Power and Energy Solutions
Equity Investments
Ownership interest percentage	48.30%		48.30%
Income (Loss) from Equity Investments			$ 690	537	$ 411
Equity Investments	$ 6,242		$ 6,242	$ 5,783

EQUITY INVESTMENTS - Narrative

EQUITY INVESTMENTS - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets	$ 183	$ 299
Coastal GasLink
Equity Investments
Impairment losses pre tax	5,148
Impairment charges after tax	4,586
Coastal GasLink | LNG Canada
Equity Investments
Payment for incentive fee	200
Coastal GasLink | Canadian Natural Gas Pipelines
Equity Investments
Impairment losses pre tax	2,100	3,048
Impairment charges after tax	$ 1,943	$ 2,643

EQUITY INVESTMENTS - Schedule o

EQUITY INVESTMENTS - Schedule of Distribution Received and Contribution Paid (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity Investments
Distributions received from equity investments	$ 1,277	$ 3,657	$ 1,048
Contributions to equity investments	4,149	3,433	1,210
Coastal GasLink
Equity Investments
Contributions to equity investments	3,231	1,414	92
Sur de Texas
Equity Investments
Distributions received from equity investments	0	2,404	73
Contributions to equity investments	0	1,199	0
Equity investments
Equity Investments
Distributions received from equity investments	1,254	1,025	975
Contributions to equity investments	918	820	1,118
Other
Equity Investments
Distributions received from equity investments	$ 23	$ 228	$ 0

EQUITY INVESTMENTS - Summarized

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income
Revenues	$ 15,934	$ 14,977	$ 13,387
Operating and other expenses	(9,075)	(9,351)	(10,256)
Net income	2,922	748	1,955
Income (Loss) from Equity Investments	1,377	1,054	898
Balance Sheet
Current assets	11,372	7,332
Current liabilities	(11,817)	(16,907)
Group of Investees
Income
Revenues	6,425	5,891	5,447
Operating and other expenses	(3,450)	(3,390)	(3,293)
Net income	2,584	2,147	$ 1,859
Balance Sheet
Current assets	3,526	3,414
Non-current assets	42,933	37,713
Current liabilities	(2,431)	(2,856)
Non-current liabilities	$ (21,895)	$ (17,690)

EQUITY INVESTMENTS - Interest i

EQUITY INVESTMENTS - Interest income and foreign exchange impact (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
Difference between the carrying value of the investment and the underlying equity in the net assets	$ 183	$ 299

LOANS RECEIVABLE FROM AFFILIA_3

LOANS RECEIVABLE FROM AFFILIATES - Narrative (Details) $ in Millions, $ in Billions	Mar. 15, 2022 USD ($)	Mar. 15, 2022 CAD ($)	Dec. 31, 2023 CAD ($)	Sep. 30, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	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		$ 1,200,000,000
Inter-affiliate debt issuance	$ 938	$ 1,200,000,000
Coastal GasLink | Canadian Natural Gas Pipelines
Loans and Leases Receivable Disclosure [Line Items]
Ownership interest percentage			35%
Coastal GasLink | Subordinated debt | Subordinated Loan Agreement | Related party
Loans and Leases Receivable Disclosure [Line Items]
Other receivables			$ 2,520,000,000		$ 250,000,000	$ 238,000,000
Impairment during the year			(2,020,000,000)		(250,000,000)
Coastal GasLink | Revolving credit facility | Line of credit
Loans and Leases Receivable Disclosure [Line Items]
Revolving credit facility, borrowing capacity			100,000,000		100,000,000
Other receivables			0
Coastal GasLink | Coastal GasLink | Subordinated debt | Subordinated Loan Agreement
Loans and Leases Receivable Disclosure [Line Items]
Revolving credit facility, borrowing capacity			$ 3,375,000,000	$ 2,020,000,000	$ 1,262,000,000
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Loans and Leases Receivable Disclosure [Line Items]
Interest income	$ 242	$ 146	$ 190
Interest expense	(3,263)	(2,588)	(2,360)
Foreign exchange gains (losses)	(320)	185	(10)
Sur de Texas | Joint venture
Loans and Leases Receivable Disclosure [Line Items]
Interest income	0	19	87
Interest expense	0	(19)	(87)
Foreign exchange gains (losses)	$ 0	$ (28)	$ (41)

RATE-REGULATED BUSINESSES - Nar

RATE-REGULATED BUSINESSES - Narrative (Details) - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2014
Columbia Gas Transmission
Public Utilities, General Disclosures [Line Items]
Maximum cost recovery and return on investment	$ 1.2
Regulatory liability, amortization period	4 years
NGTL System
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity	10.10%
Deemed common equity, percent	40%
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, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)
Regulatory Assets
Regulatory Assets	$ 2,406		$ 1,977
Less: Current portion included in Other current assets (Note 9)	76		67
Regulatory Assets, noncurrent	2,330		1,910
Regulatory Liabilities
Regulatory Liabilities	5,090		4,793
Less: Current portion included in Accounts payable and other (Note 18)	284		273
Regulatory liabilities, noncurrent	$ 4,806		4,520
Columbia Gas Transmission
Regulatory Liabilities
Regulatory liability, amortization period	4 years	4 years
Pipeline abandonment trust balances
Regulatory Liabilities
Regulatory Liabilities	$ 2,355		2,014
Deferred income taxes - U.S. Tax Reform
Regulatory Liabilities
Regulatory Liabilities	1,137		1,197
Canadian Mainline short-term adjustment and toll-stabilization accounts
Regulatory Liabilities
Regulatory Liabilities	$ 437		284
Canadian Mainline bridging amortization account
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	7 years	7 years
Regulatory Liabilities
Regulatory Liabilities	$ 376		429
Cost of removal
Regulatory Liabilities
Regulatory Liabilities	351		337
Deferred income taxes
Regulatory Liabilities
Regulatory Liabilities	$ 198		181
Canadian Mainline long-term adjustment account
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	3 years	3 years
Regulatory Liabilities
Regulatory Liabilities	$ 111		149
Pensions and other post retirement benefits
Regulatory Liabilities
Regulatory Liabilities	6		10
Pensions and other post retirement benefits | ANR PIPELINE COMPANY
Regulatory Liabilities
Regulatory Liabilities	$ 42		43
Operating and debt-service regulatory liabilities
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Regulatory Liabilities
Regulatory Liabilities	$ 23		50
Other
Regulatory Liabilities
Regulatory Liabilities	54		99
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	$ 42	$ 32
Deferred income taxes
Regulatory Assets
Regulatory Assets	$ 2,204		1,817
Operating and debt-service regulatory assets
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Regulatory Assets	$ 29		2
Pensions and other post retirement benefits
Regulatory Assets
Regulatory Assets	54		28
Foreign exchange on long-term debt
Regulatory Assets
Regulatory Assets	$ 11		19
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)	6 years	6 years
Other
Regulatory Assets
Regulatory Assets	$ 108		$ 111

GOODWILL - Acquisitions (Detail

GOODWILL - Acquisitions (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)
Goodwill
Balance at the beginning of the period	$ 12,843	$ 9,490
Balance at the end of the period	12,532	9,490	$ 12,843
U.S. Natural Gas Pipelines
Goodwill
Balance at the beginning of the period	12,843		12,582
Great Lakes impairment charge			(571)
Foreign exchange rate changes	(311)		832
Balance at the end of the period	12,532		12,843
COLUMBIA PIPELINE GROUP, INC.
Goodwill
Balance at the beginning of the period	9,948	7,351
Balance at the end of the period	9,708	7,351	9,948
ANR PIPELINE COMPANY
Goodwill
Balance at the beginning of the period	2,634	1,946
Balance at the end of the period	2,570	1,946	2,634
Great Lakes
Goodwill
Balance at the beginning of the period	165	122
Balance at the end of the period	161	122	165
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Goodwill
Balance at the beginning of the period	65	48
Balance at the end of the period	63	48	65
TUSCARORA GAS TRANSMISSION COMPANY
Goodwill
Balance at the beginning of the period	31	23
Balance at the end of the period	$ 30	$ 23	$ 31

GOODWILL - Narrative (Details)

GOODWILL - Narrative (Details) $ in Millions, $ in Millions		12 Months Ended
	Oct. 04, 2023	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill		$ 12,532	$ 12,843		$ 9,490	$ 9,490
Goodwill, expected tax deductible amount		0	91	$ 0
Columbia Gas and Columbia Gulf
Goodwill recorded on Company's acquisitions in the U.S.
Equity interest percentage	40%
Great Lakes
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill		161	165		$ 122	$ 122
Goodwill, expected tax deductible amount			40
U.S. Natural Gas Pipelines
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill, impairment loss, before tax			571
Goodwill, impairment loss, net of tax			531
Goodwill		$ 12,532	$ 12,843	$ 12,582

OTHER LONG-TERM ASSETS - Summar

OTHER LONG-TERM ASSETS - Summary (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Deferred income tax assets (Note 20)	$ 1,332	$ 1,070
Employee post-retirement benefits (Note 28)	518	563
Long-term contract assets (Note 6)	457	355
Capital projects in development	237	99
Fair value of derivative contracts (Note 29)	155	91
Keystone XL contractual recoveries (Note 7)	34	44
Keystone environmental provision recovery (Note 18)	33	240
Other	252	323
Total other assets	$ 3,018	$ 2,785

NOTES PAYABLE (Details)

NOTES PAYABLE (Details)	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 MXN ($)	Aug. 25, 2023 CAD ($)	Jan. 31, 2023 MXN ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 MXN ($)
Notes payable
Outstanding					$ 0					$ 6,262,000,000
Unsecured Term Loan | Unsecured Loan Facility
Notes payable
Total Facilities							$ 1,500,000,000
Revolving credit facility
Notes payable
Cost to maintain	$ 14,000,000	$ 14,000,000	$ 17,000,000
Notes payable
Notes payable
Denominated value				$ 0	0				$ 2,336,000,000	2,810,000,000
Revolving and demand credit facility
Notes payable
Total Facilities					11,600,000,000					12,900,000,000
TCPL | Revolving credit facility | Maturing December 2027
Notes payable
Total Facilities					3,000,000,000					3,000,000,000
Unused Capacity					3,000,000,000
TCPL | Notes payable
Notes payable
Outstanding					$ 0					$ 5,971,000,000
Weighted average interest rate per annum				0%	0%	0%			4.90%	4.90%	4.90%
Mexico subsidiary | Revolving credit facility
Notes payable
Total Facilities						$ 0		$ 5,000,000,000			$ 5,000,000,000
Unused Capacity						$ 0
Mexico subsidiary | Notes payable
Notes payable
Outstanding				$ 0	$ 0				$ 215,000,000	$ 291,000,000
Weighted average interest rate per annum				0%	0%	0%			6%	6%	6%
TCPL / TCPL USA | Revolving credit facility
Notes payable
Total Facilities					$ 2,000,000,000					$ 2,100,000,000
Unused Capacity					$ 1,000,000,000
TCPL / TCPL USA | Revolving credit facility | Maturing December 2023
Notes payable
Total Facilities				$ 2,500,000,000					$ 3,000,000,000
Unused Capacity				2,500,000,000
TCPL / TCPL USA | Revolving credit facility | Maturing December 2025
Notes payable
Total Facilities				2,500,000,000					$ 2,500,000,000
Unused Capacity				$ 2,500,000,000

ACCOUNTS PAYABLE AND OTHER - Sc

ACCOUNTS PAYABLE AND OTHER - Schedule of Accounts Payable and Other (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Payables and Accruals [Abstract]
Trade payables	$ 4,832	$ 4,330
Fair value of derivative contracts (Note 29)	1,143	871
Regulatory liabilities (Note 14)	284	273
Keystone environmental provision	122	650
Contract liabilities (Note 6)	69	62
Class C Interests (Note 7)	19	37
Coastal GasLink contractual contribution (Notes 8, 12 and 33)	0	537
Other	518	389
Accounts payable and other	$ 6,987	$ 7,149

ACCOUNTS PAYABLE AND OTHER - Na

ACCOUNTS PAYABLE AND OTHER - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Jun. 30, 2023
Environmental Exit Cost [Line Items]
Keystone environmental provision recovery, current	$ 150	$ 410
Keystone environmental provision recovery, noncurrent	33	240
Keystone Pipeline System
Environmental Exit Cost [Line Items]
Environmental remediation liability costs		650	$ 794
Environmental remediation liability	676	0
Environmental recoveries	36
Insurance received	575	0
Accounts payable and other | Keystone Pipeline System
Environmental Exit Cost [Line Items]
Keystone environmental provision recovery, current	122	650
Other current assets | Keystone Pipeline System
Environmental Exit Cost [Line Items]
Expected recovery amount	150	410
Other long-term assets | Keystone Pipeline System
Environmental Exit Cost [Line Items]
Expected recovery amount	33	240
Other long-term liabilities | Keystone Pipeline System
Environmental Exit Cost [Line Items]
Keystone environmental provision recovery, noncurrent	$ 9	$ 0

OTHER LONG-TERM LIABILITIES (De

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred Costs, Noncurrent [Abstract]
Operating lease obligations (Note 11)	$ 401	$ 379
Fair value of derivative contracts (Note 29)	106	151
Employee post-retirement benefits (Note 28)	97	111
Asset retirement obligations	64	79
Long-term contract liabilities (Note 6)	12	32
Other	335	265
Other long-term liabilities	$ 1,015	$ 1,017

INCOME TAXES - Geographic Compo

INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Canada	$ (446)	$ (2,154)	$ (292)
Foreign	4,456	3,528	2,458
Income (Loss) before Income Taxes	$ 4,010	$ 1,374	$ 2,166

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current
Canada	$ 73	$ 43	$ 29
Foreign	858	372	276
Total	931	415	305
Deferred
Canada	(39)	(467)	(327)
Foreign	50	641	142
Total	11	174	(185)
Income Tax Expense	$ 942	$ 589	$ 120

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income before income taxes	$ 4,010	$ 1,374	$ 2,166
Federal and provincial statutory tax rate	23%	23%	23%
Expected income tax expense	$ 922	$ 316	$ 498
Income tax differential related to regulated operations	(260)	(174)	(139)
Foreign income tax rate differentials	(174)	(271)	(230)
Income from non-controlling interests and equity investments	(56)	(54)	(70)
Valuation allowance (release)	197	199	(8)
Non-taxable capital (gains) and losses	196	173	0
Mexico foreign exchange exposure	132	9	10
Impact of Mexico inflationary adjustments	1	24	32
Settlement of Mexico prior years' income tax assessments	0	196	0
U.S. minimum tax	(14)	96	0
Non-deductible goodwill impairment	0	91	0
Other	(2)	(16)	27
Income Tax Expense	$ 942	$ 589	$ 120

INCOME TAXES - Deferred Assets

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred Income Tax Assets
Tax loss and credit carryforwards	$ 1,833	$ 1,519
Regulatory and other deferred amounts	569	571
Unrealized foreign exchange losses on long-term debt	206	333
Other	73	193
Deferred tax assets, gross	2,681	2,616
Less: Valuation allowance	730	640
Deferred tax assets, net of Valuation allowance	1,951	1,976
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment	6,816	6,686
Equity investments	1,115	1,152
Taxes on future revenue requirement	493	397
Financial instruments	160	126
Other	160	193
Deferred tax liabilities, gross	8,744	8,554
Net Deferred Income Tax Liabilities	6,793	6,578
Deferred Income Tax Assets
Other long-term assets (Note 16)	1,332	1,070
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities	8,125	7,648
Deferred income tax liabilities	$ 6,793	$ 6,578

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2019 USD ($)
Net operating loss carryforwards
Not recognized tax benefits	$ 22,000,000
Valuation allowance	730,000,000	$ 640,000,000
Deferred income tax liabilities on the unremitted earnings of foreign investments	1,629,000,000	1,216,000,000
Income tax payments, net of refunds	836,000,000	394,000,000	$ 371,000,000
Interest expense (recovery) reflected within net tax expense	3,000,000	6,000,000	1,000,000
Accrued interest expense	21,000,000	18,000,000	12,000,000
Income tax penalties expense	0	0	0
Income tax penalties accrued	0	0	$ 0
Coastal GasLink
Net operating loss carryforwards
Decrease in valuation allowance	358,000,000	173,000,000
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards	6,593,000,000	5,429,000,000
Capital loss carryforwards unrecognized	478,000,000	251,000,000
Canada federal and provincial | Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits	$ 140,000,000	126,000,000
Not recognized tax benefits		22,000,000
Foreign Tax Authority | Mexican Tax Authority (SAT)
Net operating loss carryforwards
Unused net operating loss carryforwards				$ 47	$ 69
Foreign Tax Authority | Mexican Tax Authority (SAT) | Tax Year 2013
Net operating loss carryforwards
Audit assessment						$ 1
Foreign Tax Authority | Mexican Tax Authority (SAT) | Tax Years 2014 through 2017
Net operating loss carryforwards
Audit assessment					490
Foreign Tax Authority | Mexican Tax Authority (SAT) | Tax Years 2013 Through 2021
Net operating loss carryforwards
Audit assessment		$ 196,000,000			$ 153

INCOME TAXES - Reconciliation_2

INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefit at beginning of year	$ 91	$ 80	$ 52
Gross increases – tax positions in prior years	9	6	5
Gross decreases – tax positions in prior years	(1)	0	(1)
Gross increases – tax positions in current year	16	7	26
Lapse of statutes of limitations	(30)	(2)	(2)
Unrecognized Tax Benefit at End of Year	$ 85	$ 91	$ 80

LONG-TERM DEBT - Amounts Outsta

LONG-TERM DEBT - Amounts Outstanding and Principal Repayments (Details) $ in Millions, $ in Millions		12 Months Ended
	Oct. 04, 2023	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2023 USD ($)	Aug. 08, 2023 USD ($)	Dec. 31, 2022 USD ($)
Debt Instrument [Line Items]
Outstanding		$ 53,118	$ 41,706
Current portion of long-term debt		(2,938)	(1,898)
Unamortized debt discount and issue costs		(312)	(239)
Fair value adjustments		108	76
Noncurrent portion of long-term debt		49,976	39,645
Fair value adjustments of interest rate hedge		11	64
Repayments of Long-term Debt [Abstract]
2024		2,938
2025		2,779
2026		5,287
2027		3,096
2028		6,232
Columbia Gas and Columbia Gulf
Debt Instrument [Line Items]
Equity interest percentage	40%
COLUMBIA PIPELINE GROUP, INC.5
Debt Instrument [Line Items]
Fair value adjustments of interest rate hedge		119	140
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding		36,815	34,998
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding		647	919
Medium Term Notes | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding		$ 15,466	$ 13,966
Interest Rate		4.60%	4.50%	4.60%		4.50%
Senior Unsecured Notes | TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding		$ 21,349	$ 21,032	$ 16,167		$ 15,542
Interest Rate		5%	4.90%	5%		4.90%
Senior Unsecured Notes | COLUMBIA PIPELINE GROUP, INC.5
Debt Instrument [Line Items]
Outstanding		$ 0	$ 2,030	$ 0		$ 1,500
Interest Rate		0%	4.90%	0%		4.90%
Senior Unsecured Notes | COLUMBIA PIPELINES OPERATING COMPANY LLC
Debt Instrument [Line Items]
Outstanding		$ 8,055	$ 0	$ 6,100		$ 0
Interest Rate		6.10%	0%	6.10%		0%
Senior Unsecured Notes | COLUMBIA PIPELINES OPERATING COMPANY LLC | Columbia Pipelines Group
Debt Instrument [Line Items]
Outstanding					$ 1,500
Senior Unsecured Notes | COLUMBIA PIPELINES HOLDING COMPANY LLC
Debt Instrument [Line Items]
Outstanding		$ 1,320	$ 0	$ 1,000		$ 0
Interest Rate		6.20%	0%	6.20%		0%
Senior Unsecured Notes | ANR PIPELINE COMPANY
Debt Instrument [Line Items]
Outstanding		$ 1,548	$ 1,587	$ 1,172		$ 1,172
Interest Rate		4.10%	4.10%	4.10%		4.10%
Senior Unsecured Notes | TC PIPELINES, LP
Debt Instrument [Line Items]
Outstanding		$ 1,122	$ 1,150	$ 850		$ 850
Interest Rate		4.20%	4.20%	4.20%		4.20%
Senior Unsecured Notes | GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Outstanding		$ 495	$ 440	$ 375		$ 325
Interest Rate		4.40%	4.30%	4.40%		4.30%
Senior Unsecured Notes | PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Debt Instrument [Line Items]
Outstanding		$ 330	$ 338	$ 250		$ 250
Interest Rate		2.80%	2.80%	2.80%		2.80%
Senior Unsecured Notes | GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Debt Instrument [Line Items]
Outstanding		$ 165	$ 198	$ 125		$ 146
Interest Rate		7.60%	7.60%	7.60%		7.60%
Debentures and Notes, Maturity Date of 2024 | NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding		$ 100	$ 100
Interest Rate		9.90%	9.90%	9.90%		9.90%
Debentures and Notes, Maturity Date of 2023 | NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding		$ 0	$ 271	$ 0		$ 200
Interest Rate		0%	7.90%	0%		7.90%
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		$ 43	$ 44	$ 33		$ 33
Interest Rate		7.50%	7.50%	7.50%		7.50%
Unsecured Term Loan | TUSCARORA GAS TRANSMISSION COMPANY
Debt Instrument [Line Items]
Outstanding		$ 0	$ 46	$ 0		$ 34
Interest Rate		0%	6.50%	0%		6.50%
Senior Unsecured Term Loan | TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Debt Instrument [Line Items]
Outstanding		$ 2,377	$ 0	$ 1,800		$ 0
Interest Rate		7.70%	0%	7.70%		0%
Unsecured Revolving Credit Facility
Debt Instrument [Line Items]
Outstanding		$ 2,621	$ 0
Unsecured Revolving Credit Facility | TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Debt Instrument [Line Items]
Outstanding		$ 244	$ 0	$ 185		$ 0
Interest Rate		7.70%	0%	7.70%		0%

LONG-TERM DEBT - Issued (Detail

LONG-TERM DEBT - Issued (Details) $ in Millions, $ in Millions

1 Months Ended

12 Months Ended

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 ($)

Oct. 31, 2021 USD ($)

Aug. 31, 2021 USD ($)

Jun. 30, 2021 CAD ($)

Jan. 31, 2021 USD ($)

Dec. 31, 2021 USD ($)

Dec. 31, 2021 CAD ($)

Jan. 09, 2024 CAD ($)

Dec. 31, 2023 USD ($)

Dec. 31, 2023 CAD ($)

Sep. 30, 2023 CAD ($)

Dec. 31, 2022 USD ($)

Dec. 31, 2022 CAD ($)

Jun. 30, 2021 USD ($)

Jan. 04, 2021 USD ($)

Debt Instrument [Line Items]

Outstanding

$ 53,118

$ 41,706

TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Outstanding

36,815

34,998

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 2024 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

$ 1,250

Interest Rate

1%

Senior Unsecured Notes due October 2031 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

$ 1,000

Interest Rate

2.50%

Senior Unsecured Notes due October 2031 | PORTLAND NATURAL GAS TRANSMISSION SYSTEM

Debt Instrument [Line Items]

Amount

$ 125

Interest Rate

2.68%

Medium Term Notes due June 2024 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

$ 750

Medium Term Notes due June 2031 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

500

Interest Rate

2.97%

Medium Term Notes due September 2047 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

$ 250

Interest Rate

4.33%

Long-term debt, re-issuance yield

4.19%

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 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%

Line of credit | KEYSTONE XL SUBSIDIARIES | Project Level Credit Facility due June 2021

Debt Instrument [Line Items]

Amount

$ 849

$ 849

$ 1,028

Revolving credit facility, borrowing capacity

4,100

$ 1,600

$ 4,100

Unsecured Term Loan due June 2022 | COLUMBIA PIPELINE GROUP, INC.

Debt Instrument [Line Items]

Amount

$ 4,040

Total committed amount

$ 4,200

Senior Unsecured Notes due August 2024 | TUSCARORA GAS TRANSMISSION COMPANY

Debt Instrument [Line Items]

Amount

$ 13

Senior Unsecured Term Loan

Debt Instrument [Line Items]

Unamortized debt issue costs

$ 3

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

Debt Instrument [Line Items]

Outstanding

$ 1,800

$ 2,377

$ 0

$ 0

Senior Unsecured Notes, Maturity Date of January 2034 | COLUMBIA PIPELINES HOLDING COMPANY LLC | Subsequent event

Debt Instrument [Line Items]

Interest Rate

5.68%

Outstanding

$ 500

LONG-TERM DEBT - Retired_Repaid

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

1 Months Ended

12 Months Ended

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, 2021 USD ($)

Nov. 30, 2021 CAD ($)

Nov. 30, 2021 USD ($)

Oct. 31, 2021 USD ($)

Jun. 30, 2021 USD ($)

Mar. 31, 2021 USD ($)

Jan. 31, 2021 USD ($)

Dec. 31, 2023 USD ($)

Dec. 31, 2021 CAD ($)

Dec. 31, 2021 USD ($)

Aug. 08, 2023 USD ($)

May 31, 2023 USD ($)

Dec. 31, 2022 USD ($)

Mar. 31, 2021 CAD ($)

Mar. 31, 2021 USD ($)

Debt Instrument [Line Items]

Unsecured debt

$ 5,600

Long-term debt

$ 2,000

$ 1,600

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due October 2030

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

$ 750,000,000

Interest Rate

3.69%

TRANSCANADA PIPELINES LIMITED | Medium Term Note due December 2022

Debt Instrument [Line Items]

Amount

$ 25,000,000

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 | Medium Term Note due November 2021

Debt Instrument [Line Items]

Amount

$ 500,000,000

Interest Rate

3.65%

3.65%

TRANSCANADA PIPELINES LIMITED | Debentures due January 2021

Debt Instrument [Line Items]

Amount

$ 400

Interest Rate

9.88%

TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan Due November 2023

Debt Instrument [Line Items]

Amount

$ 32

NOVA GAS TRANSMISSION LTD. | Debentures Due April 2023

Debt Instrument [Line Items]

Amount

$ 200

Interest Rate

7.88%

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

Debt Instrument [Line Items]

Amount

$ 315

COLUMBIA PIPELINE GROUP, INC. | Unsecured Term Loan due December 2021

Debt Instrument [Line Items]

Amount

$ 4,040

Debt instrument, face amount

4,200

$ 4,200

Amount

$ 4,000

Amortization of debt Issue costs

$ 5,000,000

COLUMBIA PIPELINE GROUP, INC. | Senior Unsecured Term Loan

Debt Instrument [Line Items]

Unsecured debt

$ 1,024

Amortization of debt Issue costs

3,000,000

COLUMBIA PIPELINE GROUP, INC. | Unsecured Term Loan due June 2022

Debt Instrument [Line Items]

Debt instrument, face amount

$ 4,200

Amount

4,040

TC ENERGÍA MEXICANA, S. DE R.L. DE C.V. | Unsecured Term Loan due December 2021

Debt Instrument [Line Items]

Amount

$ 50

TC PIPELINES, LP | Unsecured Term Loan due November 2021

Debt Instrument [Line Items]

Amount

$ 450

TC PIPELINES, LP | Senior Unsecured Notes due March 2021

Debt Instrument [Line Items]

Amount

$ 350

Interest Rate

4.65%

4.65%

TC PIPELINES, LP | Line of credit | Project Level Credit Facility due June 2021

Debt Instrument [Line Items]

Terminated amount

$ 500

Long-term debt

$ 0

ANR PIPELINE COMPANY | Senior Unsecured Notes due November 2021

Debt Instrument [Line Items]

Amount

$ 300

Interest Rate

9.63%

9.63%

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | Senior Unsecured Notes due November 2021

Debt Instrument [Line Items]

Amount

$ 10

Interest Rate

9.09%

9.09%

PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Unsecured Loan Facility due October 2021

Debt Instrument [Line Items]

Amount

$ 93

KEYSTONE XL SUBSIDIARIES | Line of credit | Project Level Credit Facility due June 2021

Debt Instrument [Line Items]

Amount

$ 849

Amount

$ 849

$ 1,028,000,000

$ 849

LONG-TERM DEBT - Interest Expen

LONG-TERM DEBT - Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Interest Expense [Abstract]
Capitalized interest	$ (187)	$ (27)	$ (22)
Amortization and other financial charges	106	36	78
Interest expense	3,263	2,588	2,360
Interest payments, net of interest capitalized	2,931	2,478	2,299
Short-term debt
Interest Expense [Abstract]
Interest on debt	165	153	10
Long-term debt (excluding junior subordinated notes)
Interest Expense [Abstract]
Interest on debt	2,562	1,883	1,841
Junior subordinated notes
Interest Expense [Abstract]
Interest on debt	$ 617	$ 543	$ 453

JUNIOR SUBORDINATED NOTES (Deta

JUNIOR SUBORDINATED NOTES (Details) $ in Millions, $ in Millions	1 Months Ended		12 Months Ended
	Mar. 31, 2022 USD ($)	Mar. 31, 2021 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)
Debt Instrument [Line Items]
Outstanding				$ 53,118		$ 41,706
Unamortized debt discount and issue costs				(312)		(239)
Long-term Debt					$ 2,000		$ 1,600
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding				36,815		34,998
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding				10,385		10,593
Unamortized debt discount and issue costs				(98)		(98)
Long-term Debt				$ 10,287		10,495
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%
Outstanding				$ 1,320		$ 1,353
Effective Interest Rate				6.50%	6.50%	6.20%	6.20%
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				$ 990		$ 1,015
Effective Interest Rate				7.80%	7.80%	7.40%	7.40%
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				$ 1,585		$ 1,624
Effective Interest Rate				8.30%	8.30%	8%	8%
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				$ 1,981		$ 2,030
Effective Interest Rate				7.50%	7.50%	7.10%	7.10%
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				7%	7%	6.80%	6.80%
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				$ 1,453		$ 1,488
Effective Interest Rate				8%	8%	7.60%	7.60%
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				$ 1,056		$ 1,083
Effective Interest Rate				7.10%	7.10%	7.20%	7.20%
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 | Five-Year Government of Canada Yield
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 three | Junior subordinated notes | Five-Year Government of Canada Yield
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
TransCanada Trust | Trust Notes - Series 2021-A | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 500
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 Trust | Trust Notes - Series 2021-A | Notes payable
Debt Instrument [Line Items]
Debt instrument, face amount	$ 800	$ 500
TransCanada Trust | Trust Notes - Series 2021-A | Period one | Junior subordinated notes
Debt Instrument [Line Items]
Stated interest rate		4.45%
TransCanada Trust | Trust Notes - Series 2021-A | Period one | Notes payable
Debt Instrument [Line Items]
Stated interest rate		4.20%
Stated interest rate, period of time		10 years
TransCanada Trust | Trust Notes - Series 2021-A | Period two | Junior subordinated notes | Five-Year Government of Canada Yield
Debt Instrument [Line Items]
Stated interest rate, period of time		5 years
Variable interest rate		3.316%
TransCanada Trust | Trust Notes - Series 2021-A | Period two | Notes payable
Debt Instrument [Line Items]
Stated interest rate, period of time		5 years
TransCanada Trust | Trust Notes - Series 2021-A | Period three | Junior subordinated notes | Five-Year Government of Canada Yield
Debt Instrument [Line Items]
Variable interest rate		4.066%

FOREIGN EXCHANGE (GAINS) LOSS_3

FOREIGN EXCHANGE (GAINS) LOSSES, NET (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Components of OCI related to derivatives
Foreign exchange gains (losses)	$ (320)	$ 185	$ (10)
Derivative instrument held-for-trading
Components of OCI related to derivatives
Foreign exchange gains (losses)	(401)	151	(37)
Other instruments
Components of OCI related to derivatives
Foreign exchange gains (losses)	$ 81	$ 34	$ 27

NON-CONTROLLING INTERESTS - Nar

NON-CONTROLLING INTERESTS - Narrative (Details) $ in Millions, $ in Millions									12 Months Ended
	Oct. 04, 2023 CAD ($)	Oct. 04, 2023 USD ($)	Aug. 08, 2023 USD ($)	Jun. 14, 2023 CAD ($)	Jun. 14, 2023 USD ($)	Mar. 15, 2023 CAD ($)	Mar. 15, 2023 USD ($)	Mar. 03, 2021 shares	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2021
Non-controlling interests
Sale of equity, noncontrolling interest	$ 9,500	$ 6,900
Fair value of noncontrolling interest									$ 222	$ 167
Columbia Gas and Columbia Gulf
Non-controlling interests
Consideration received as a reduction to additional paid in capital	$ 3,500	$ 3,000
Texas Wind Farms
Non-controlling interests
Business acquisition, percentage of voting interests acquired				100%	100%
Fluvanna Wind Farm
Non-controlling interests
Business acquisition, percentage of voting interests acquired						100%	100%
Noncontrolling interest acquired						$ 106	$ 80
Blue Cloud Wind Farm
Non-controlling interests
Business acquisition, percentage of voting interests acquired				100%	100%
Noncontrolling interest acquired				$ 116	$ 87
TC PipeLines, LP
Non-controlling interests
Common shares issued to common unitholders								0.70
Common shares issued (in shares) | shares								37,955,093
Columbia Gas and Columbia Gulf
Non-controlling interests
Equity interest percentage	40%	40%
Proceeds from sale of equity	$ 5,300	$ 3,900
Percentage of non-controlling interests									40%	40%
COLUMBIA PIPELINES OPERATING COMPANY LLC
Non-controlling interests
Proceeds from issuance of debt			$ 4,600
COLUMBIA PIPELINES HOLDING COMPANY LLC
Non-controlling interests
Proceeds from issuance of debt			$ 1,000
TC PipeLines, LP
Non-controlling interests
Percentage of non-controlling interests									0%	0%
TC PipeLines, LP | Noncontrolling Interest | TC PipeLines, LP
Non-controlling interests
Percentage of non-controlling interests											74.50%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Non-controlling interests
Percentage of non-controlling interests									38.30%	38.30%

NON-CONTROLLING INTERESTS - Bus

NON-CONTROLLING INTERESTS - Business Acquisition and its Effect on the Balance Sheet (Details) - CAD ($) $ in Millions	Mar. 03, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Non-controlling interests
Common shares		$ 30,002	$ 28,995
Common shares
Non-controlling interests
Common shares		$ 30,002	$ 28,995	$ 26,716	$ 24,488
TC PipeLines, LP
Non-controlling interests
Deferred income tax liabilities	$ (443)
Other	(12)
TC PipeLines, LP | Common shares
Non-controlling interests
Common shares	2,063
TC PipeLines, LP | Additional Paid-In Capital
Non-controlling interests
Noncontrolling interest, fair value	(398)
TC PipeLines, LP | AOCI Attributable to Parent
Non-controlling interests
Noncontrolling interest, fair value	353
TC PipeLines, LP | Equity Attributable to Non-Controlling Interests
Non-controlling interests
Noncontrolling interest, fair value	$ (1,563)

NON-CONTROLLING INTERESTS - Sch

NON-CONTROLLING INTERESTS - Schedule of Non-controlling Interests (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Non-controlling interests
Net income (loss) attributable to non-controlling interests (Note 24)	$ 146	$ 37	$ 91
Redeemable non-controlling interest	0	0	1
Non-Controlling Interests	9,455	126
Equity Attributable to Non-Controlling Interests
Non-controlling interests
Net income (loss) attributable to non-controlling interests (Note 24)	$ (146)	(37)	(90)
Columbia Gas and Columbia Gulf
Non-controlling interests
Noncontrolling Interests Ownership	40%
Net income (loss) attributable to non-controlling interests (Note 24)	$ 143	0	0
Non-Controlling Interests	$ 9,167
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Non-controlling interests
Noncontrolling Interests Ownership	38.30%
Net income (loss) attributable to non-controlling interests (Note 24)	$ 41	37	30
Non-Controlling Interests	$ 106	126
Texas Wind Farms
Non-controlling interests
Noncontrolling Interests Ownership	100%
Net income (loss) attributable to non-controlling interests (Note 24)	$ (38)	0	0
Non-Controlling Interests	$ 182
TC PipeLines, LP
Non-controlling interests
Noncontrolling Interests Ownership	0%
Net income (loss) attributable to non-controlling interests (Note 24)	$ 0	$ 0	$ 60
TC PipeLines, LP | Equity Attributable to Non-Controlling Interests | TC PipeLines, LP
Non-controlling interests
Noncontrolling Interests Ownership			74.50%
Redeemable non-controlling interest (Note 7)
Non-controlling interests
Noncontrolling Interests Ownership	0%

COMMON SHARES - Reconciliation

COMMON SHARES - Reconciliation and Weighted Average Common Shares Outstanding (Details) - CAD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Number of Shares
Outstanding at the beginning of the period (in shares)	1,018,000
Acquisition of TC PipeLines, LP, net of transaction costs (Note 24) (in shares)			37,955
Exercise of options (in shares)	62
Outstanding at the end of the period (in shares)	1,037,000	1,018,000
Amount
Outstanding at the beginning of the period	$ 28,995,000
Acquisition of TC PipeLines, LP, net of transaction costs (Note 24)			$ 2,063,000
Outstanding at the end of the period	$ 30,002,000	$ 28,995,000
Common shares
Number of Shares
Outstanding at the beginning of the period (in shares)	1,017,962	980,816	940,064
Exercise of options (in shares)	62	2,830	2,797
Issued under public offering (in shares)		28,400
Dividend reinvestment and share purchase plan (in shares)	19,464	5,916
Outstanding at the end of the period (in shares)	1,037,488	1,017,962	980,816
Amount
Outstanding at the beginning of the period	$ 28,995,000	$ 26,716,000	$ 24,488,000
Acquisition of TC PipeLines, LP, net of transaction costs (Note 24)			2,063,000
Exercise of options	4,000	183,000	165,000
Issued under public offering		1,754,000
Dividend reinvestment and share purchase plan	1,003,000	342,000
Outstanding at the end of the period	$ 30,002,000	$ 28,995,000	$ 26,716,000

COMMON SHARES - Common Shares I

COMMON SHARES - Common Shares Issued Under Public Offering (Details) - Public Offering $ / shares in Units, $ in Billions	Aug. 10, 2022 CAD ($) $ / shares shares
Class of Stock [Line Items]
Number of shares issued in transaction (in shares) | shares	28,400,000
Price per share (in Canadian dollars per share) | $ / shares	$ 63.50
Consideration received on transaction | $	$ 1.8

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 - Acquisition of

COMMON SHARES - Acquisition of TC Pipelines, LP (Details)	Mar. 03, 2021 shares
TC PipeLines, LP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common shares issued (in shares)	37,955,093

COMMON SHARES - Weighted Averag

COMMON SHARES - Weighted Average Common Shares Outstanding (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Basic (in shares)	1,030	995	973
Diluted (in shares)	1,030	996	974
Common shares
Class of Stock [Line Items]
Basic (in shares)	1,030	995	973
Diluted (in shares)	1,030	996	974

COMMON SHARES - Options (Detail

COMMON SHARES - Options (Details)	12 Months Ended
	Dec. 31, 2023 $ / shares shares
Number of Options
Outstanding at the beginning of the period (in shares)	6,109,000
Granted (in shares)	1,933,000
Exercised (in shares)	(62,000)
Options forfeited/expired (in shares)	(544,000)
Outstanding at the end of the period (in shares)	7,436,000
Options Exercisable (in shares)	4,375,000
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share) | $ / shares	$ 63.86
Granted (in Canadian dollars per share) | $ / shares	56.66
Exercised (in Canadian dollars per share) | $ / shares	48.44
Options forfeited/expired (in Canadian dollars per share) | $ / shares	60.60
Outstanding at the end of the period (in Canadian dollars per share) | $ / shares	62.36
Options Exercisable at December 31, 2020 (in Canadian dollars per share) | $ / shares	$ 64.47
Weighted Average Remaining Contractual Life
Options Outstanding at December 31, 2023	4 years 1 month 6 days
Options Exercisable at December 31, 2023	3 years
Number of shares available for grant (in shares)	2,267,871
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Weighted average fair value (in Canadian dollars per share)	$ 7.88	$ 8.24	$ 7.39
Expected life (years)	5 years 1 month 6 days	5 years 4 months 24 days	5 years 4 months 24 days
Interest rate	2.90%	1.60%	0.50%
Volatility	24%	22%	25%
Dividend yield	6.30%	5.50%	6%
Expense for stock options	$ 9	$ 10	$ 12
Unrecognized compensation costs related to non-vested stock options	$ 12
Expense recognition period	2 years

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Total intrinsic value of options exercised	$ 0	$ 33	$ 28
Total fair value of options that have vested	$ 76	$ 89	$ 110
Total options vested (in shares)	1.5	1.6	1.9
Options, exercisable, intrinsic value	$ 0
Options, outstanding, intrinsic value	$ 0

COMMON SHARES - Shareholder Rig

COMMON SHARES - Shareholder Rights Plan (Details)	Dec. 31, 2023 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	3 Months Ended	12 Months Ended
	Jan. 30, 2021	Jan. 29, 2021	Jun. 30, 2022	Dec. 31, 2023	Dec. 31, 2022	May 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Preferred shares				$ 2,499	$ 2,499		$ 3,487
Series 1
Class of Stock [Line Items]
Number of shares outstanding (in shares)				14,577
Current yield (as a percent)				3.48%
Annual dividend ( in Canadian dollars per share)				$ 0.86975
Redemption price per share (in Canadian dollars per share)				$ 25
Preferred shares				$ 360	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%
Series 2
Class of Stock [Line Items]
Number of shares outstanding (in shares)				7,423
Current yield (as a percent)				6.96%
Redemption price per share (in Canadian dollars per share)				$ 25
Preferred shares				$ 179	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%
Series 3
Class of Stock [Line Items]
Number of shares outstanding (in shares)				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
Preferred shares				$ 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%
Series 4
Class of Stock [Line Items]
Number of shares outstanding (in shares)				4,003
Current yield (as a percent)				6.32%
Redemption price per share (in Canadian dollars per share)				$ 25
Preferred shares				$ 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%
Series 5
Class of Stock [Line Items]
Number of shares outstanding (in shares)				12,071
Current yield (as a percent)	1.95%	2.26%		1.95%
Annual dividend ( in Canadian dollars per share)				$ 0.48725
Redemption price per share (in Canadian dollars per share)				$ 25
Preferred shares				$ 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%
Series 6
Class of Stock [Line Items]
Number of shares outstanding (in shares)				1,929
Current yield (as a percent)				6.69%
Redemption price per share (in Canadian dollars per share)				$ 25
Preferred shares				$ 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%
Series 7
Class of Stock [Line Items]
Number of shares outstanding (in shares)				24,000
Current yield (as a percent)				3.90%
Annual dividend ( in Canadian dollars per share)				$ 0.97575
Redemption price per share (in Canadian dollars per share)				$ 25
Preferred shares				$ 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%
Series 9
Class of Stock [Line Items]
Number of shares outstanding (in shares)				18,000
Current yield (as a percent)				3.76%
Annual dividend ( in Canadian dollars per share)				$ 0.9405
Redemption price per share (in Canadian dollars per share)				$ 25
Preferred shares				$ 442	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%
Series 11
Class of Stock [Line Items]
Number of shares outstanding (in shares)				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
Preferred shares				$ 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%
Series 15
Class of Stock [Line Items]
Number of shares outstanding (in shares)				0
Current yield (as a percent)				0%
Annual dividend ( in Canadian dollars per share)			$ 0.30625	$ 0
Redemption price per share (in Canadian dollars per share)				$ 0		$ 25
Preferred shares				$ 0	$ 0		$ 988
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%
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%
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%
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 (Details)

PREFERRED SHARES (Details) $ / shares in Units, $ in Millions, $ in Millions				3 Months Ended		12 Months Ended
	May 31, 2022 $ / shares shares	May 31, 2021 $ / shares shares	Feb. 01, 2021 shares	Jun. 30, 2022 $ / shares	Jun. 30, 2021 $ / shares	Dec. 31, 2023 $ / shares	Mar. 31, 2022 USD ($)	Mar. 31, 2021 CAD ($)
Trust Notes - Series 2021-A | Notes payable | TransCanada Trust
Class of Stock [Line Items]
Total committed amount							$ 800	$ 500
Series 2 and Series 4 and Series 6
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)						$ 25.50
Series 15
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)	$ 25					0
Stock redeemed during period (in shares) | shares	40,000,000
Annual dividend ( in Canadian dollars per share)				$ 0.30625		0
Series 13
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)		$ 25
Stock redeemed during period (in shares) | shares		20,000,000
Annual dividend ( in Canadian dollars per share)					$ 0.34375
Series 5
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)						25
Annual dividend ( in Canadian dollars per share)						0.48725
Shares converted (in shares) | shares			818,876
Conversion ratio			1
Series 6
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)						25
Shares converted (in shares) | shares			175,208
Conversion ratio			1
Series 3
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)						25
Annual dividend ( in Canadian dollars per share)						0.4235
Series 4
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)						$ 25

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Before Tax Amount
Other Comprehensive Income (Loss)	$ (1,326)	$ 2,613	$ 894
Income Tax (Expense) Recovery
Other Comprehensive Income (Loss)	54	(216)	(252)
Net of Tax Amount
Other comprehensive income (loss) (Note 27)	(1,272)	2,397	642
Foreign currency translation gains and losses on net investment in foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(1,148)	1,410	(100)
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	7	84	(8)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(1,141)	1,494	(108)
Change in fair value of net investment hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	23	(48)	(3)
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	(6)	12	1
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	17	(36)	(2)
Change in fair value and reclassification of gains and losses of cash flow hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications		(58)	(13)
Reclassification from accumulated other comprehensive Income (loss)	97	63	68
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications		19	3
Reclassification from AOCI	(23)	(21)	(13)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications		(39)	(10)
Reclassification from accumulated other comprehensive income (loss)	74	42	55
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	(15)	81	208
Reclassification from accumulated other comprehensive Income (loss)		9	20
Income Tax (Expense) Recovery
Other comprehensive income (loss) before reclassifications	4	(18)	(50)
Reclassification from AOCI		(3)	(6)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(11)	63	158
Reclassification from accumulated other comprehensive income (loss)		6	14
Other comprehensive income (loss) on equity investments
Before Tax Amount
Other Comprehensive Income (Loss)	(283)	1,156	714
Income Tax (Expense) Recovery
Other Comprehensive Income (Loss)	72	(289)	(179)
Net of Tax Amount
Other comprehensive income (loss) (Note 27)	$ (211)	$ 867	$ 535

OTHER COMPREHENSIVE INCOME(LO_4

OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(LOSS) - Reconciliation (Details) - CAD ($) $ in Millions		12 Months Ended
	Oct. 04, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year		$ 33,990
Other comprehensive income (loss) (Note 27)		(1,272)	$ 2,397	$ 642
Balance at end of year		29,553	33,990
Cash flow hedge loss reclassified within twelve months		4
Cash flow hedge loss to be reclassified within twelve months, net of tax		$ 3
Columbia Gas and Columbia Gulf
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Percentage of non-controlling interests		40%
Equity interest percentage	40%
AOCI Attributable to Parent
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year		$ 955	(1,434)	(2,439)
Other comprehensive (loss) / income, before reclassifications		(437)	2,344	555
Amounts reclassified from AOCI		58	45	97
Other comprehensive income (loss) (Note 27)		(379)	2,389	652
Acquisition of TC Pipelines, LP and Monetization of Columbia Gas and Columbia Gulf		(527)		353
Balance at end of year		49	955	(1,434)
Currency Translation Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year		441	(1,009)	(1,273)
Other comprehensive (loss) / income, before reclassifications		(231)	1,450	(98)
Amounts reclassified from AOCI		0	0	0
Other comprehensive income (loss) (Note 27)		(231)	1,450	(98)
Acquisition of TC Pipelines, LP and Monetization of Columbia Gas and Columbia Gulf		(527)		362
Balance at end of year		(317)	441	(1,009)
Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year		(109)	(112)	(143)
Other comprehensive (loss) / income, before reclassifications		0	(39)	(11)
Amounts reclassified from AOCI		74	42	55
Other comprehensive income (loss) (Note 27)		74	3	44
Acquisition of TC Pipelines, LP and Monetization of Columbia Gas and Columbia Gulf		0		(13)
Balance at end of year		(35)	(109)	(112)
Pension and Other Post-Retirement Benefit Plan Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year		(44)	(113)	(285)
Other comprehensive (loss) / income, before reclassifications		(11)	63	158
Amounts reclassified from AOCI		0	6	14
Other comprehensive income (loss) (Note 27)		(11)	69	172
Acquisition of TC Pipelines, LP and Monetization of Columbia Gas and Columbia Gulf		0		0
Balance at end of year		(55)	(44)	(113)
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year		667	(200)	(738)
Other comprehensive (loss) / income, before reclassifications		(195)	870	506
Amounts reclassified from AOCI		(16)	(3)	28
Other comprehensive income (loss) (Note 27)		(211)	867	534
Acquisition of TC Pipelines, LP and Monetization of Columbia Gas and Columbia Gulf		0		4
Balance at end of year		456	667	(200)
Accumulated foreign currency adjustment attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive (loss) / income, before reclassifications		366	(8)	(12)
Accumulated net gain (loss) from cash flow hedges attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive (loss) / income, before reclassifications		0	0	(1)
Accumulated net gain (loss) from equity investments attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive (loss) / income, before reclassifications		$ 0	$ 0	$ 1

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Energy Solutions)	$ 15,934	$ 14,977	$ 13,387
Interest expense	(3,263)	(2,588)	(2,360)
Total before tax	4,010	1,374	2,166
Income tax (expense) recovery	(942)	(589)	(120)
Net Income (Loss) Attributable to Common Shares	2,829	641	1,815
Plant operating costs and other	4,887	4,932	4,098
Income (loss) from equity investments	1,377	1,054	898
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	(97)	(63)	(68)
Income tax (expense) recovery	23	21	13
Net Income (Loss) Attributable to Common Shares	(74)	(42)	(55)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges | Interest rate
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(12)	(16)	(46)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Pension and other post-retirement benefit plan adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	0	(9)	(20)
Income tax (expense) recovery	0	3	6
Net Income (Loss) Attributable to Common Shares	0	(6)	(14)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Amortization of actuarial gains (losses)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other	0	(11)	(22)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Settlement gain (loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other	0	2	2
Amounts Reclassified From Accumulated Other Comprehensive Loss | Equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax (expense) recovery	(6)	(1)	9
Net Income (Loss) Attributable to Common Shares	16	3	(28)
Income (loss) from equity investments	22	4	(37)
Power and Energy Solutions | Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges | Commodities
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Energy Solutions)	$ (85)	$ (47)	$ (22)

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized	12 years	12 years	11 years
Expense for savings plan and DC Plans	$ 64	$ 64	$ 58
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Savings and DC Plans	64	64	58
Total cash contributions	101	150	171
Gain (loss) due to settlement			81
Net periodic benefit cost, settlement charge			$ 18
Change in Plan Assets
Plan assets at fair value – beginning of year	3,835
Plan assets at fair value – end of year	4,055	3,835
Amounts recognized in the Balance Sheet
Other long-term assets (Note 16)	518	563
Other long-term liabilities (Note 19)	(97)	$ (111)
Company's expected funding contributions for savings plan and DC Plans	$ 70
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	10 years
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans	$ 28	$ 78	$ 105
Total amount outstanding under letters of credit	78	0
Settlement gain (loss), before tax	0	(2)	(2)
Curtailment gain	0	0	5
Net benefit cost recognized	17	51	99
Change in Benefit Obligation
Benefit obligation – beginning of year	3,081	4,027
Service cost	93	145	171
Interest cost	158	125	119
Employee contributions	7	6
Benefits paid	(185)	(324)
Actuarial (gain) loss	219	(949)
Foreign exchange rate changes	(17)	51
Benefit obligation – end of year	3,356	3,081	4,027
Change in Plan Assets
Plan assets at fair value – beginning of year	3,481	4,145
Actual return on plan assets	385	(483)
Employer contributions	28	78
Employee contributions	7	6
Benefits paid	(185)	(324)
Foreign exchange rate changes	(19)	59
Plan assets at fair value – end of year	3,697	3,481	4,145
Funded Status – Plan Surplus	$ 341	$ 400
Discount rate	4.75%	5.15%
Amounts recognized in the Balance Sheet
Other long-term assets (Note 16)	$ 341	$ 400
Accounts payable and other	0	0
Other long-term liabilities (Note 19)	0	0
Net	341	400
Company's expected funding contributions	$ 0
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	$ 9	8	8
Settlement gain (loss), before tax	0	0	0
Curtailment gain	0	0	0
Net benefit cost recognized	3	6	9
Change in Benefit Obligation
Benefit obligation – beginning of year	310	419
Service cost	3	5	6
Interest cost	16	13	12
Employee contributions	2	2
Benefits paid	(44)	(24)
Actuarial (gain) loss	2	(120)
Foreign exchange rate changes	(4)	15
Benefit obligation – end of year	285	310	419
Change in Plan Assets
Plan assets at fair value – beginning of year	354	431
Actual return on plan assets	24	(89)
Employer contributions	9	8
Employee contributions	2	2
Benefits paid	(23)	(24)
Foreign exchange rate changes	(8)	26
Plan assets at fair value – end of year	358	354	431
Funded Status – Plan Surplus	$ 73	$ 44
Discount rate	5.10%	5.45%
Amounts recognized in the Balance Sheet
Other long-term assets (Note 16)	$ 177	$ 163
Accounts payable and other	(7)	(8)
Other long-term liabilities (Note 19)	(97)	(111)
Net	73	44
Company's expected funding contributions	6
Canadian | Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Total amount outstanding under letters of credit	$ 244	322	322
United States | Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Settlement gain (loss), before tax		$ 2	2
Curtailment gain			5
United States | Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Settlement gain (loss), before tax			3
Curtailment gain			$ 3

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Benefit obligation and fair value of plan assets for plans that are not fully funded
Plan assets at fair value	$ 4,055	$ 3,835
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	$ (3,356)	$ (3,081)	$ (4,027)
Plan assets at fair value	3,697	3,481	4,145
Funded Status – Plan Surplus	341	400
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(3,090)	(2,880)
Plan assets at fair value	3,697	3,481
Funded Status – Plan Surplus	$ 607	$ 601
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100%	100%
Pension Benefit Plans | Fixed income securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	41%	38%
Company debt or common shares included in plan assets, amount	$ 7	$ 7
Company debt or common shares included in plan assets, percentage	0.20%	0.20%
Pension Benefit Plans | Fixed income securities | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	30%
Pension Benefit Plans | Fixed income securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	0.50%
Pension Benefit Plans | Equity securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	44%	44%
Company debt or common shares included in plan assets, amount	$ 2	$ 3
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	0.30%
Pension Benefit Plans | Equity securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	0.55%
Pension Benefit Plans | Other investments
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	15%	18%
Pension Benefit Plans | Other investments | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	0.10%
Pension Benefit Plans | Other investments | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	0.25%
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	(285)	(310)	(419)
Plan assets at fair value	358	354	$ 431
Funded Status – Plan Surplus	73	44
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	(104)	(119)
Plan assets at fair value	0	0
Funded Status – Plan Surplus	$ (104)	$ (119)

EMPLOYEE POST-RETIREMENT BENE_5

EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Employee post-retirement benefits
Fair value of plan assets	$ 4,055	$ 3,835
Percentage of Total Portfolio	100%	100%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 2,057	$ 1,998
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1,436	1,205
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	562	632	$ 565
Cash and Cash Equivalents
Employee post-retirement benefits
Fair value of plan assets	$ 69	$ 56
Percentage of Total Portfolio	2%	1%
Cash and Cash Equivalents | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 68	$ 55
Cash and Cash Equivalents | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1	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	$ 121	$ 117
Percentage of Total Portfolio	3%	3%
Equity Securities, Canadian | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 121	$ 117
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	$ 965	$ 897
Percentage of Total Portfolio	24%	24%
Equity Securities, U.S. | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 965	$ 897
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	$ 354	$ 344
Percentage of Total Portfolio	9%	9%
Equity Securities, International | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 167	$ 172
Equity Securities, International | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	187	172
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	$ 74	$ 75
Percentage of Total Portfolio	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	74	75
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	$ 194	$ 177
Percentage of Total Portfolio	5%	5%
Equity Securities, Emerging | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 54	$ 50
Equity Securities, Emerging | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	140	127
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	$ 266	$ 221
Percentage of Total Portfolio	7%	6%
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	266	221
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	$ 314	$ 249
Percentage of Total Portfolio	8%	6%
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	314	249
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	$ 16	$ 12
Percentage of Total Portfolio	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	16	12
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	$ 143	$ 108
Percentage of Total Portfolio	4%	3%
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	143	108
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	$ 425	$ 335
Percentage of Total Portfolio	10%	9%
Fixed Income Securities, U.S. Bonds, Federal | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 185	$ 177
Fixed Income Securities, U.S. Bonds, Federal | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	240	158
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 Total Portfolio	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	$ 386	$ 439
Percentage of Total Portfolio	10%	11%
Fixed Income Securities, U.S. Bonds, Corporate | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 312	$ 345
Fixed Income Securities, U.S. Bonds, Corporate | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	74	94
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	$ 15	$ 11
Percentage of Total Portfolio	0%	0%
Fixed Income Securities, International, Government | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 4	$ 5
Fixed Income Securities, International, Government | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	11	6
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	$ 83	$ 58
Percentage of Total Portfolio	2%	1%
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	83	58
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	$ 37
Percentage of Total Portfolio	1%	1%
Fixed Income Securities, International, Mortgage-backed | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 43	$ 36
Fixed Income Securities, International, Mortgage-backed | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	17	1
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	$ (131)	$ (78)
Percentage of Total Portfolio	(4.00%)	(2.00%)
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	(131)	(78)
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	$ 283	$ 336
Percentage of Total Portfolio	7%	9%
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	283	336
Infrastructure
Employee post-retirement benefits
Fair value of plan assets	$ 269	$ 296
Percentage of Total Portfolio	7%	8%
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	269	296
Private equity funds
Employee post-retirement benefits
Fair value of plan assets	$ 10	$ 0
Percentage of Total Portfolio	0%	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	10	0
Funds held on deposit
Employee post-retirement benefits
Fair value of plan assets	$ 138	$ 144
Percentage of Total Portfolio	3%	4%
Funds held on deposit | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 138	$ 144
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

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, 2023	Dec. 31, 2022
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	$ 3,835
Plan assets at fair value – end of year	4,055	$ 3,835
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	632	565
Purchases and sales	(76)	52
Realized and unrealized gains (losses)	6	15
Plan assets at fair value – end of year	$ 562	$ 632

EMPLOYEE POST-RETIREMENT BENE_7

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for savings plan and DC Plans	$ 70
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits	5.95%
Percentage level to which average annual rate was assumed to decrease	4.80%
Pension Benefit Plans
DB Plans
Company's expected funding contributions	$ 0
Estimated future benefit payments, which reflect expected future service
2024	204
2025	207
2026	211
2027	214
2028	216
2029 to 2033	$ 1,127
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	4.75%	5.15%
Rate of compensation increase	3.20%	3.30%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	5.15%	3.05%	2.70%
Expected long-term rate of return on plan assets	6.45%	6.10%	6.15%
Rate of compensation increase	3.25%	3%	2.60%
Net benefit cost
Service cost	$ 93	$ 145	$ 171
Other components of net benefit cost
Interest cost	158	125	119
Expected return on plan assets	(234)	(239)	(234)
Amortization of actuarial loss	0	10	23
Amortization of regulatory asset	0	12	27
Curtailment gain	0	0	(5)
Settlement gain – AOCI	0	(2)	(2)
Other components of net benefit cost	(76)	(94)	(72)
Net Benefit Cost Recognized	17	51	99
Pre-tax amounts recognized in AOCI
Net loss	71	38	147
Pre-tax amounts recognized in OCI
Amortization of net gain (loss) from AOCI to net income	0	(10)	(23)
Curtailment	0	0	0
Settlement	0	2	2
Funded status adjustment	33	(101)	(190)
Total pre-tax amounts recognized in OCI	33	$ (109)	$ (211)
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	6
Estimated future benefit payments, which reflect expected future service
2024	23
2025	23
2026	23
2027	22
2028	22
2029 to 2033	$ 104
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	5.10%	5.45%
Rate of compensation increase	0%	0%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	5.45%	3.10%	2.80%
Expected long-term rate of return on plan assets	4.50%	3.25%	3%
Rate of compensation increase	0%	0%	0%
Net benefit cost
Service cost	$ 3	$ 5	$ 6
Other components of net benefit cost
Interest cost	16	13	12
Expected return on plan assets	(16)	(14)	(13)
Amortization of actuarial loss	0	1	2
Amortization of regulatory asset	0	1	2
Curtailment gain	0	0	0
Settlement gain – AOCI	0	0	0
Other components of net benefit cost	0	1	3
Net Benefit Cost Recognized	3	6	9
Pre-tax amounts recognized in AOCI
Net loss	6	24	5
Pre-tax amounts recognized in OCI
Amortization of net gain (loss) from AOCI to net income	0	(1)	(2)
Curtailment	0	0	3
Settlement	0	0	0
Funded status adjustment	(18)	20	(18)
Total pre-tax amounts recognized in OCI	$ (18)	$ 19	$ (17)

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, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Derivative [Line Items]
Fair Value	$ 191	$ (317)
Designated as a net investment hedge
Derivative [Line Items]
Fair Value	10	(27)
Designated as a net investment hedge | US$ denominated
Derivative [Line Items]
Notional Amount			$ 1,200	$ 3,900
U.S. dollar foreign exchange options (maturing 2024) | Designated as a net investment hedge
Derivative [Line Items]
Fair Value	8	(22)
U.S. dollar foreign exchange options (maturing 2024) | Designated as a net investment hedge | US$ denominated
Derivative [Line Items]
Notional Amount			1,000	3,600
U.S. dollar cross-currency interest rate swaps (maturing 2023 to 2025) | Designated as a net investment hedge
Derivative [Line Items]
Fair Value	2	(5)
U.S. dollar cross-currency interest rate swaps (maturing 2023 to 2025) | Designated as a net investment hedge | US$ denominated
Derivative [Line Items]
Notional Amount			$ 200	$ 300
Net realized gains related to the interest component	$ 1	$ 1

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, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)
Derivative [Line Items]
Notional amount	$ 27,800		$ 32,500
Fair value	$ 26,600		$ 30,800
US$ denominated
Derivative [Line Items]
Notional amount		$ 21,100		$ 24,000
Fair value		$ 20,200		$ 22,700

RISK MANAGEMENT AND FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Expected credit loss provision (Note 29)	$ (83,000,000)	$ 163,000,000	$ 0
Provision for other credit losses	0	0
Financing receivable, recorded investment, past due	0	0
Past due or impaired	0	0
TGNH Pipelines
Derivative [Line Items]
Expected credit loss provision (Note 29)	73,000,000	149,000,000	0
Mexico Natural Gas Pipelines
Derivative [Line Items]
Expected credit loss provision (Note 29)	$ 10,000,000	$ 14,000,000	$ 0

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, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	$ (53,118)	$ (41,706)
Junior subordinated notes (Note 22)	(10,287)	(10,495)
Long-term debt			$ 2	$ 1.6
Interest rate swap agreements
Carrying and fair values of non-derivative financial instruments
Hedged items	(53)	64
Long-term debt hedged			$ 2	$ 1.6
Level II | Carrying Amount
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	(52,914)	(41,543)
Junior subordinated notes (Note 22)	(10,287)	(10,495)
Total liabilities	(63,201)	(52,038)
Level II | Fair Value
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	(52,815)	(39,505)
Junior subordinated notes (Note 22)	(9,217)	(9,415)
Total liabilities	$ (62,032)	$ (48,920)

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Total Derivatives
Derivative Assets	$ 1,440	$ 705
Derivative Liabilities	(1,249)	(1,022)
Total Derivatives	191	(317)
Total trading activity
Total Derivatives
Derivative Assets	1,382	685
Derivative Liabilities	(1,201)	(837)
Total Derivatives	181	(152)
Cash Flow Hedges
Total Derivatives
Derivative Assets	12	0
Derivative Liabilities	(1)	(74)
Total Derivatives	11	(74)
Net Investment Hedges
Total Derivatives
Derivative Assets	10	8
Derivative Liabilities	0	(35)
Total Derivatives	10	(27)
Other current assets
Total Derivatives
Derivative Assets	1,285	614
Other current assets | Total trading activity
Total Derivatives
Derivative Assets	1,266	608
Other current assets | Cash Flow Hedges
Total Derivatives
Derivative Assets	9	0
Other current assets | Net Investment Hedges
Total Derivatives
Derivative Assets	10	6
Other current assets | Commodities
Total Derivatives
Derivative Assets	1,204	597
Other current assets | Commodities | Commodities
Total Derivatives
Derivative Assets	1,195	597
Other current assets | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Assets	9	0
Other current assets | Commodities | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets | Foreign exchange
Total Derivatives
Derivative Assets	81	17
Other current assets | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Assets	71	11
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	10	6
Other long-term assets
Total Derivatives
Derivative Assets	155	91
Other long-term assets | Total trading activity
Total Derivatives
Derivative Assets	116	77
Other long-term assets | Cash Flow Hedges
Total Derivatives
Derivative Assets	3	0
Other long-term assets | Net Investment Hedges
Total Derivatives
Derivative Assets	0	2
Other long-term assets | Commodities
Total Derivatives
Derivative Assets	89	62
Other long-term assets | Commodities | Commodities
Total Derivatives
Derivative Assets	86	62
Other long-term assets | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Assets	3	0
Other long-term assets | Commodities | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets | Foreign exchange
Total Derivatives
Derivative Assets	30	17
Other long-term assets | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Assets	30	15
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	2
Other long-term assets | Interest rate
Total Derivatives
Derivative Assets	36	12
Other long-term assets | Interest rate | Interest rate
Total Derivatives
Derivative Assets	0	0
Other long-term assets | Interest rate | Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Accounts payable and other
Total Derivatives
Derivative Liabilities	(1,143)	(871)
Accounts payable and other | Total trading activity
Total Derivatives
Derivative Liabilities	(1,124)	(742)
Accounts payable and other | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(1)	(72)
Accounts payable and other | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	(31)
Accounts payable and other | Commodities
Total Derivatives
Derivative Liabilities	(1,111)	(656)
Accounts payable and other | Commodities | Commodities
Total Derivatives
Derivative Liabilities	(1,110)	(584)
Accounts payable and other | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(1)	(72)
Accounts payable and other | Commodities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other | Foreign exchange
Total Derivatives
Derivative Liabilities	(14)	(189)
Accounts payable and other | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Liabilities	(14)	(158)
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	0	(31)
Accounts payable and other | Interest rate
Total Derivatives
Derivative Liabilities	(18)	(26)
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
Other long-term liabilities
Total Derivatives
Derivative Liabilities	(106)	(151)
Other long-term liabilities | Total trading activity
Total Derivatives
Derivative Liabilities	(77)	(95)
Other long-term liabilities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	(2)
Other long-term liabilities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	(4)
Other long-term liabilities | Commodities
Total Derivatives
Derivative Liabilities	(75)	(77)
Other long-term liabilities | Commodities | Commodities
Total Derivatives
Derivative Liabilities	(75)	(75)
Other long-term liabilities | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	(2)
Other long-term liabilities | Commodities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Foreign exchange
Total Derivatives
Derivative Liabilities	(2)	(24)
Other long-term liabilities | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Liabilities	(2)	(20)
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	(4)
Other long-term liabilities | Interest rate
Total Derivatives
Derivative Liabilities	(29)	(50)
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
LMCI Restricted Investments
Fair value
Fair value of equity securities	883	749
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains (losses)	190	(244)	$ 45
Net realized (losses)/ gains	(34)	(32)	3
Other Restricted Investments
Fair value
Fair value of equity securities	0	0
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains (losses)	13	(7)	(2)
Net realized (losses)/ gains	0	0	$ 0
Fixed income securities | LMCI Restricted Investments
Fair value
Maturing within 1 year	1	0
Maturing within 1-5 years	8	0
Maturing within 5-10 years	1,340	1,153
Maturing after 10 years	102	77
Fair value of securities	2,334	1,979
Fixed income securities | Other Restricted Investments
Fair value
Maturing within 1 year	35	54
Maturing within 1-5 years	291	106
Maturing within 5-10 years	0	0
Maturing after 10 years	0	0
Fair value of securities	$ 326	$ 160

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Fair Value Hedging Relationships (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value hedging adjustments, discontinued hedges	$ 0	$ 0
Long-term debt | Carrying Amount
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability	2,630	2,101
Long-term debt | Fair Value
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Adjustments	$ 11	$ 64

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional and Maturity Summary (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) GWh MWh Bcf MMBbls	Dec. 31, 2022 USD ($) GWh MMBbls Bcf	Dec. 31, 2023 MXN ($)	Dec. 31, 2022 MXN ($)
Minimum
Derivative [Line Items]
Notional amount, life (in years)	15 years		15 years
Maximum
Derivative [Line Items]
Notional amount, life (in years)	20 years		20 years
Commodities | Sales
Derivative [Line Items]
Notional amount, energy (gwh) | MWh	50
Foreign exchange
Derivative [Line Items]
Notional amount	$ 4,978	$ 5,997	$ 20,000	$ 9,747
Interest rate
Derivative [Line Items]
Notional amount	$ 2,000	$ 1,600	$ 0
Power
Derivative [Line Items]
Notional amount, energy (gwh) | MWh	50
Power | Minimum
Derivative [Line Items]
Notional amount, life (in years)	15 years		15 years
Power | Maximum
Derivative [Line Items]
Notional amount, life (in years)	20 years		20 years
Power | Commodities | Sales
Derivative [Line Items]
Notional amount, energy (gwh) | GWh	9,209	673
Natural Gas | Commodities | Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | Bcf	50
Natural Gas | Commodities | Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | Bcf		96
Liquids | Commodities | Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | MMBbls		11
Liquids | Commodities | Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | MMBbls	(7)

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses) / Gains on Derivative Instruments (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Gain (loss) on cash flow hedge	$ 0	$ 0	$ (10,000,000)
Commodities
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	96,000,000	14,000,000	9,000,000
Realized gains (losses) in the year	811,000,000	759,000,000	287,000,000
Commodities | Derivative instruments in hedging relationships
Derivative [Line Items]
Realized gains (losses) in the year	(2,000,000)	(73,000,000)	(44,000,000)
Foreign exchange
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	246,000,000	(149,000,000)	(203,000,000)
Realized gains (losses) in the year	155,000,000	(2,000,000)	240,000,000
Interest rate | Derivative instruments in hedging relationships
Derivative [Line Items]
Realized gains (losses) in the year	$ (43,000,000)	$ (3,000,000)	$ (32,000,000)

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ 0	$ (58)	$ (13)
Commodities
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	0	(94)	(35)
Interest rate
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ 0	$ 36	$ 22

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Interest rate contracts | Interest Expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged items	$ (98)	$ (30)	$ 0
Derivatives designated as hedging instruments	(43)	(1)	0
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	(12)	(16)	(46)
Commodity contracts | Revenue
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	$ (85)	$ (47)	$ (22)

RISK MANAGEMENT AND FINANCIA_13

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivative Instrument Assets
Gross Derivative Instruments	$ 1,440	$ 705
Amounts Available for Offset	(1,120)	(628)
Net Amounts	320	77
Derivative Instrument Liabilities
Gross Derivative Instruments	(1,249)	(1,022)
Amounts Available for Offset	1,120	628
Net Amounts	(129)	(394)
Cash collateral provided by the Company	149	138
Letters of credit provided by the Company	83	68
Cash collateral received by the Company (less than)	1	1
Letters of credit received by the Company	15	10
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	3	19
Foreign exchange
Derivative Instrument Assets
Gross Derivative Instruments	111	34
Amounts Available for Offset	(16)	(33)
Net Amounts	95	1
Derivative Instrument Liabilities
Gross Derivative Instruments	(16)	(213)
Amounts Available for Offset	16	33
Net Amounts	0	(180)
Interest rate
Derivative Instrument Assets
Gross Derivative Instruments	36	12
Amounts Available for Offset	(5)	(4)
Net Amounts	31	8
Derivative Instrument Liabilities
Gross Derivative Instruments	(47)	(76)
Amounts Available for Offset	5	4
Net Amounts	(42)	(72)
Power | Commodities
Derivative Instrument Assets
Gross Derivative Instruments	1,293	659
Amounts Available for Offset	(1,099)	(591)
Net Amounts	194	68
Derivative Instrument Liabilities
Gross Derivative Instruments	(1,186)	(733)
Amounts Available for Offset	1,099	591
Net Amounts	$ (87)	$ (142)

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, 2023 CAD ($) MWh	Dec. 31, 2022 CAD ($)
Fair Value Hierarchy
Derivative Instrument Assets	$ 1,440	$ 705
Derivative Instrument Liabilities	(1,249)	(1,022)
Fair Value	$ 191	(317)
Minimum
Fair Value Hierarchy
Notional amount, life (in years)	15 years
Maximum
Fair Value Hierarchy
Notional amount, life (in years)	20 years
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	$ 191	(317)
Recurring basis | Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	52	37
Recurring basis | Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Assets and (liabilities), net	150	(343)
Recurring basis | Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	(11)	(11)
Total trading activity
Fair Value Hierarchy
Derivative Instrument Assets	1,382	685
Derivative Instrument Liabilities	(1,201)	(837)
Fair Value	181	(152)
Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	12	0
Derivative Instrument Liabilities	(1)	(74)
Fair Value	11	(74)
Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	36	12
Derivative Instrument Liabilities	(47)	(76)
Fair Value	(11)	(64)
Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	10	8
Derivative Instrument Liabilities	0	(35)
Fair Value	10	(27)
Commodities | Recurring basis | Power
Fair Value Hierarchy
Derivative Instrument Assets	1,293	659
Derivative Instrument Liabilities	(1,186)	(733)
Commodities | Recurring basis | Quoted Prices in Active Markets (Level I) | Power
Fair Value Hierarchy
Derivative Instrument Assets	1,054	515
Derivative Instrument Liabilities	(1,002)	(478)
Commodities | Recurring basis | Significant Other Observable Inputs (Level II) | Power
Fair Value Hierarchy
Derivative Instrument Assets	229	142
Derivative Instrument Liabilities	(163)	(242)
Commodities | Recurring basis | Significant Unobservable Inputs (Level III) | Power
Fair Value Hierarchy
Derivative Instrument Assets	10	2
Derivative Instrument Liabilities	(21)	(13)
Foreign exchange | Recurring basis
Fair Value Hierarchy
Derivative Instrument Assets	111	34
Derivative Instrument Liabilities	(16)	(213)
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	111	34
Derivative Instrument Liabilities	(16)	(213)
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	12
Derivative Instrument Liabilities	(47)	(76)
Interest rate | Recurring basis | Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Derivative Instrument Liabilities	0	0
Interest rate | Recurring basis | Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Derivative Instrument Assets	36	12
Derivative Instrument Liabilities	(47)	(76)
Interest rate | Recurring basis | Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Derivative Instrument Liabilities	0	0
Other current assets
Fair Value Hierarchy
Derivative Instrument Assets	1,285	614
Other current assets | Total trading activity
Fair Value Hierarchy
Derivative Instrument Assets	1,266	608
Other current assets | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	9	0
Other current assets | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other current assets | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	10	6
Other current assets | Commodities
Fair Value Hierarchy
Derivative Instrument Assets	1,204	597
Other current assets | Commodities | Commodities
Fair Value Hierarchy
Derivative Instrument Assets	1,195	597
Other current assets | Commodities | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	9	0
Other current assets | Commodities | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other current assets | Commodities | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other current assets | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets	81	17
Other current assets | Foreign exchange | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets	71	11
Other current assets | Foreign exchange | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other current assets | Foreign exchange | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other current assets | Foreign exchange | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	10	6
Other long-term assets
Fair Value Hierarchy
Derivative Instrument Assets	155	91
Other long-term assets | Total trading activity
Fair Value Hierarchy
Derivative Instrument Assets	116	77
Other long-term assets | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	3	0
Other long-term assets | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	36	12
Other long-term assets | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	2
Other long-term assets | Commodities
Fair Value Hierarchy
Derivative Instrument Assets	89	62
Other long-term assets | Commodities | Commodities
Fair Value Hierarchy
Derivative Instrument Assets	86	62
Other long-term assets | Commodities | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	3	0
Other long-term assets | Commodities | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other long-term assets | Commodities | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other long-term assets | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets	30	17
Other long-term assets | Foreign exchange | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets	30	15
Other long-term assets | Foreign exchange | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other long-term assets | Foreign exchange | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other long-term assets | Foreign exchange | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	2
Other long-term assets | Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	36	12
Other long-term assets | Interest rate | Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other long-term assets | Interest rate | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other long-term assets | Interest rate | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	36	12
Other long-term assets | Interest rate | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Accounts payable and other
Fair Value Hierarchy
Derivative Instrument Liabilities	(1,143)	(871)
Accounts payable and other | Total trading activity
Fair Value Hierarchy
Derivative Instrument Liabilities	(1,124)	(742)
Accounts payable and other | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(1)	(72)
Accounts payable and other | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(18)	(26)
Accounts payable and other | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	(31)
Accounts payable and other | Commodities
Fair Value Hierarchy
Derivative Instrument Liabilities	(1,111)	(656)
Accounts payable and other | Commodities | Commodities
Fair Value Hierarchy
Derivative Instrument Liabilities	(1,110)	(584)
Accounts payable and other | Commodities | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(1)	(72)
Accounts payable and other | Commodities | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Accounts payable and other | Commodities | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Accounts payable and other | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Liabilities	(14)	(189)
Accounts payable and other | Foreign exchange | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Liabilities	(14)	(158)
Accounts payable and other | Foreign exchange | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Accounts payable and other | Foreign exchange | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Accounts payable and other | Foreign exchange | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	(31)
Accounts payable and other | Interest rate
Fair Value Hierarchy
Derivative Instrument Liabilities	(18)	(26)
Accounts payable and other | Interest rate | Interest rate
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Accounts payable and other | Interest rate | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Accounts payable and other | Interest rate | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(18)	(26)
Accounts payable and other | Interest rate | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Other long-term liabilities
Fair Value Hierarchy
Derivative Instrument Liabilities	(106)	(151)
Other long-term liabilities | Total trading activity
Fair Value Hierarchy
Derivative Instrument Liabilities	(77)	(95)
Other long-term liabilities | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	(2)
Other long-term liabilities | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(29)	(50)
Other long-term liabilities | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	(4)
Other long-term liabilities | Commodities
Fair Value Hierarchy
Derivative Instrument Liabilities	(75)	(77)
Other long-term liabilities | Commodities | Commodities
Fair Value Hierarchy
Derivative Instrument Liabilities	(75)	(75)
Other long-term liabilities | Commodities | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	(2)
Other long-term liabilities | Commodities | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Other long-term liabilities | Commodities | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Other long-term liabilities | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Liabilities	(2)	(24)
Other long-term liabilities | Foreign exchange | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Liabilities	(2)	(20)
Other long-term liabilities | Foreign exchange | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Other long-term liabilities | Foreign exchange | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Other long-term liabilities | Foreign exchange | Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	(4)
Other long-term liabilities | Interest rate
Fair Value Hierarchy
Derivative Instrument Liabilities	(29)	(50)
Other long-term liabilities | Interest rate | Interest rate
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Other long-term liabilities | Interest rate | Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	0	0
Other long-term liabilities | Interest rate | Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(29)	(50)
Other long-term liabilities | Interest rate | Net Investment Hedges
Fair Value Hierarchy
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, 2023	Dec. 31, 2022
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	$ 2	$ 10
Commodity contracts | Power
Net change in the Level III fair value category
Balance at beginning of year	(11)	(6)
Net gains (losses) included in Net income (loss)	(2)	(10)
Net gains (losses) included in OCI	0	(3)
Transfers out of Level III	2	7
Settlements	0	1
Balance at end of year	$ (11)	$ (11)

CHANGES IN OPERATING WORKING _3

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
CHANGES IN OPERATING WORKING CAPITAL
(Increase) decrease in Accounts receivable	$ (394)	$ (575)	$ (925)
(Increase) decrease in Inventories	(56)	(190)	(93)
(Increase) decrease in Other current assets	618	118	(141)
Increase (decrease) in Accounts payable and other	(206)	(83)	890
Increase (decrease) in Accrued interest	245	91	(18)
(Increase) Decrease in Operating Working Capital	$ 207	$ (639)	$ (287)

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Details) $ in Millions, $ in Millions						12 Months Ended
	Oct. 04, 2023 CAD ($)	Oct. 04, 2023 USD ($)	Jun. 14, 2023 USD ($) MWh	Mar. 15, 2023 USD ($) MWh	Nov. 30, 2021 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Business Acquisition [Line Items]
Sale of equity, noncontrolling interest	$ 9,500	$ 6,900
Net gain/(loss) on assets sold/held for sale						$ 0	$ 0	$ 30
Disposal group, disposed of by sale, not discontinued operations | Northern Courier
Business Acquisition [Line Items]
Ownership interest sold					15%
Sale consideration					$ 35
Net gain/(loss) on assets sold/held for sale					13
Gain (loss) on sale, net of tax					$ 19
Columbia Gas and Columbia Gulf
Business Acquisition [Line Items]
Consideration received as a reduction to additional paid in capital	$ 3,500	$ 3,000
Texas Wind Farms
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired			100%
Fluvanna Wind Farm
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired				100%
Acquisitions, net of cash acquired (Note 31)				$ 99
Business acquisition, energy measure | MWh				155
Blue Cloud Wind Farm
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired			100%
Acquisitions, net of cash acquired (Note 31)			$ 125
Business acquisition, energy measure | MWh			148
Columbia Gas and Columbia Gulf
Business Acquisition [Line Items]
Equity interest percentage	40%	40%
Proceeds from sale of equity	$ 5,300	$ 3,900
TCPL | Texas Wind Farms
Business Acquisition [Line Items]
Noncontrolling interest acquired			100%

COMMITMENTS, CONTINGENCIES AN_3

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Narrative (Details) $ / shares in Units, $ in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2023 CAD ($)	Dec. 31, 2023 CAD ($) Megawatt	Dec. 31, 2023 USD ($) $ / shares	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Other Commitments
Purchase commitment		$ 397		$ 362	$ 239
Capital expenditure commitment		2,100
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites		19		$ 20
Letter of credit | Irrevocable Standby Letter of Credit | Coastal GasLink | Coastal GasLink
Contingencies
Vendor standby letter of credit		117
SA Energy Group | Coastal GasLink
Contingencies
Damages sought		1,100
Pacific Pipeline Construction Ltd | Coastal GasLink
Contingencies
Damages sought	$ 428
Bonatti S.P.A | Coastal GasLink
Contingencies
Damages sought		$ 1,200
Columbia Pipelines Group | Columbia Pipeline Group shareholders
Contingencies
Damages sought			$ 400
Damages paid per share (in dollars per share) | $ / shares			$ 1
Capital expenditures
Other Commitments
Power purchase agreement, planned capacity (in megawatts) | Megawatt		800
Capital expenditures | U.S. Natural Gas Pipelines
Other Commitments
Purchase commitment		$ 300
Capital expenditures | Mexico Natural Gas Pipelines
Other Commitments
Purchase commitment		$ 1,300

COMMITMENTS, CONTINGENCIES AN_4

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - Contingent financial obligation - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Guarantees
Potential Exposure	$ 265	$ 269
Carrying Value	3	3
Sur de Texas
Guarantees
Potential Exposure	97	100
Carrying Value	0	0
Bruce Power
Guarantees
Potential Exposure	88	88
Carrying Value	0	0
Other jointly-owned entities
Guarantees
Potential Exposure	80	81
Carrying Value	$ 3	$ 3

VARIABLE INTEREST ENTITIES - Na

VARIABLE INTEREST ENTITIES - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Variable Interest Entity [Line Items]
Variable interest entity ownership percentage	100%
Equity Investments	$ 10,314	$ 9,535
Coastal GasLink | Canadian Natural Gas Pipelines
Variable Interest Entity [Line Items]
Equity Investments	$ 294	$ 0
Ownership interest percentage	35%

VARIABLE INTEREST ENTITIES - As

VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) $ in Millions, $ in Millions	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)
Current Assets
Cash and cash equivalents	$ 3,678		$ 620
Accounts receivable	4,209		3,624
Inventories	982		936
Other current assets	2,503		2,152
Total current assets	11,372		7,332
Property, plant and equipment, net	80,569		75,940
Equity Investments	10,314		9,535
Regulatory Assets (Note 14)	2,330		1,910
Goodwill	12,532	$ 9,490	12,843	$ 9,490
Total assets	125,034		114,348
Current Liabilities
Accounts payable and other	6,987		7,149
Accrued interest	913		668
Current portion of long-term debt	2,938		1,898
Total current liabilities	11,817		16,907
Regulatory Liabilities	4,806		4,520
Deferred Income Tax Liabilities	8,125		7,648
Total liabilities	86,026		80,232
VIE, Primary Beneficiary
Current Assets
Cash and cash equivalents	190		60
Accounts receivable	476		98
Inventories	90		32
Other current assets	49		14
Total current assets	805		204
Property, plant and equipment, net	27,649		3,997
Equity Investments	823		748
Regulatory Assets (Note 14)	12		0
Goodwill	439		449
Total assets	29,728		5,398
Current Liabilities
Accounts payable and other	1,135		234
Accrued interest	210		18
Current portion of long-term debt	28		31
Total current liabilities	1,373		283
Regulatory Liabilities	280		78
Other Long-Term Liabilities	56		1
Deferred Income Tax Liabilities	22		16
Long-Term Debt	11,388		2,136
Total liabilities	$ 13,119		$ 2,514

VARIABLE INTEREST ENTITIES - Ca

VARIABLE INTEREST ENTITIES - Carrying Value of Non-consolidated VIEs and Maximum Exposure (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Sep. 30, 2023	Dec. 31, 2022	Dec. 31, 2021
Balance Sheet Exposure
Equity Investments	$ 10,314		$ 9,535
Off-balance sheet
Maximum exposure to loss	10,103		12,314
Bruce Power
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	1,538		2,025
Bruce Power | VIE, not primary beneficiary
Balance Sheet Exposure
Equity Investments	6,241		5,783
Coastal GasLink
Balance Sheet Exposure
Equity Investments	294		0
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	855		3,300
Coastal GasLink | Subordinated Loan Agreement | Subordinated debt | Related party
Off-balance sheet
Other receivables	2,520		250	$ 238
Coastal GasLink | Subordinated Loan Agreement | Subordinated debt | Coastal GasLink
Off-balance sheet
Revolving credit facility, borrowing capacity	3,375	$ 2,020	1,262
Subordinated debt	855
Pipeline Equity Investments And Other | VIE, not primary beneficiary
Balance Sheet Exposure
Equity Investments	1,411		1,148
Pipeline equity investments
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	$ 58		$ 58