TransCanada Pipelines 40-F14 Feb 232022 FY Annual report (Canada)Financial data

Company Profile

Cover Page

Cover Page	12 Months Ended
Cover Page	Dec. 31, 2022 shares
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
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	1,017,961,583
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Central Index Key	0001232384
Amendment Flag	false
Document Fiscal Year Focus	2022
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	973,199,666
Entity Central Index Key	0000099070
Amendment Flag	false
Document Fiscal Year Focus	2022
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
Audit Information	Dec. 31, 2022
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues	$ 14,977	$ 13,387	$ 12,999
Income from Equity Investments (Note 11)	1,054	898	1,019
Impairment of equity investment (Notes 7 and 11)	(3,048)	0	0
Operating and Other Expenses
Plant operating costs and other	4,932	4,098	3,878
Commodity purchases resold	534	87	0
Property taxes	848	774	727
Depreciation and amortization	2,584	2,522	2,590
Goodwill and asset impairment charges and other (Notes 6 and 14)	453	2,775	0
Total operating and other expenses	9,351	10,256	7,195
Net Gain/(Loss) on Sale of Assets (Note 30)	0	30	(50)
Financial Charges
Interest expense (Note 20)	2,588	2,360	2,228
Allowance for funds used during construction	(369)	(267)	(349)
Foreign exchange losses on loan receivable from affiliate (Note 12)	185	(10)	(28)
Interest income and other	(146)	(190)	(185)
Total financial charges	2,258	1,893	1,666
Income before Income Taxes	1,374	2,166	5,107
Income Tax Expense (Note 19)
Current	415	305	252
Deferred	174	(185)	(58)
Income Tax Expense	589	120	194
Net Income	785	2,046	4,913
Net income attributable to non-controlling interests (Note 23)	37	91	297
Net Income Attributable to Controlling Interests	748	1,955	4,616
Preferred share dividends	107	140	159
Net Income Attributable to Common Shares	$ 641	$ 1,815	$ 4,457
Net Income per Common Share (Note 24)
Basic (in dollars per share)	$ 0.64	$ 1.87	$ 4.74
Diluted (in dollars per share)	0.64	1.86	4.74
Dividends Declared per Common Share (in dollars per share)	$ 3.60	$ 3.48	$ 3.24
Weighted Average Number of Common Shares (millions) (Note 24)
Basic (in shares)	995	973	940
Diluted (in shares)	996	974	940
Canadian Natural Gas Pipelines
Revenues	$ 4,764	$ 4,519	$ 4,469
U.S. Natural Gas Pipelines
Revenues	5,933	5,233	5,031
Mexico Natural Gas Pipelines
Revenues	688	605	716
Liquids Pipelines
Revenues	2,668	2,306	2,371
Power and Energy Solutions
Revenues	$ 924	$ 724	$ 412

Consolidated statement of compr

Consolidated statement of comprehensive income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Net Income	$ 785	$ 2,046	$ 4,913
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations	1,494	(108)	(609)
Change in fair value of net investment hedges	(36)	(2)	36
Change in fair value of cash flow hedges	(39)	(10)	(583)
Reclassification to net income of gains and losses on cash flow hedges	42	55	489
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	63	158	12
Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans	6	14	17
Other comprehensive income/(loss) on equity investments	867	535	(280)
Other comprehensive income/(loss) (Note 26)	2,397	642	(918)
Comprehensive Income	3,182	2,688	3,995
Comprehensive income attributable to non-controlling interests	45	81	259
Comprehensive Income Attributable to Controlling Interests	3,137	2,607	3,736
Preferred share dividends	107	140	159
Comprehensive Income Attributable to Common Shares	$ 3,030	$ 2,467	$ 3,577

Consolidated statement of cash

Consolidated statement of cash flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash Generated from Operations
Net income	$ 785	$ 2,046	$ 4,913
Depreciation and amortization	2,584	2,522	2,590
Goodwill and asset impairment charges and other (Notes 6 and 14)	453	2,775	0
Deferred income taxes (Note 19)	174	(185)	(58)
Income from equity investments (Note 11)	(1,054)	(898)	(1,019)
Impairment of equity investment (Notes 7 and 11)	3,048	0	0
Distributions received from operating activities of equity investments (Note 11)	1,025	975	1,123
Employee post-retirement benefits funding, net of expense (Note 27)	(29)	(5)	(19)
Net (gain)/loss on sale of assets (Note 30)	0	(30)	50
Equity allowance for funds used during construction	(248)	(191)	(235)
Unrealized losses/(gains) on financial instruments	135	194	(103)
Expected credit loss provision	163	0	0
Foreign exchange losses on loan receivable from affiliate (Note 12)	28	41	86
Other	(50)	(67)	57
Increase in operating working capital (Note 29)	(639)	(287)	(327)
Net cash provided by operations	6,375	6,890	7,058
Investing Activities
Capital expenditures (Note 4)	(6,678)	(5,924)	(8,013)
Capital projects in development (Note 4)	(49)	0	(122)
Contributions to equity investments (Notes 4, 7 and 11)	(3,433)	(1,210)	(765)
Keystone XL contractual recoveries (Note 6)	571	0	0
Proceeds from sales of assets, net of transaction costs	0	35	3,407
Loans to affiliate issued, net (Notes 7 and 12)	(11)	(239)	0
Other distributions from equity investments (Note 11)	2,632	73	0
Deferred amounts and other	(41)	(447)	(559)
Net cash used in investing activities	(7,009)	(7,712)	(6,052)
Financing Activities
Notes payable issued/(repaid), net	766	1,003	(220)
Long-term debt issued, net of issue costs	2,508	10,730	5,770
Long-term debt repaid	(1,338)	(7,758)	(3,977)
Junior subordinated notes issued, net of issue costs	1,008	495	0
Gain/(loss) on settlement of financial instruments	23	(10)	(130)
Redeemable non-controlling interest repurchased (Note 6)	0	(633)	0
Contributions from redeemable non-controlling interest (Note 6)	0	0	1,033
Dividends on common shares	(3,192)	(3,317)	(2,987)
Dividends on preferred shares	(106)	(141)	(159)
Distributions to non-controlling interests	(44)	(74)	(221)
Distributions on Class C Interests (Note 6)	(43)	(16)	0
Common shares issued, net of issue costs	1,905	148	91
Preferred shares redeemed (Note 25)	(1,000)	(500)	0
Acquisition of TC PipeLines, LP transaction costs (Note 23)	0	(15)	0
Net cash provided by/(used in) financing activities	487	(88)	(800)
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	94	53	(19)
(Decrease)/Increase in Cash and Cash Equivalents	(53)	(857)	187
Cash and Cash Equivalents, Beginning of year	673	1,530	1,343
Cash and Cash Equivalents, End of year	$ 620	$ 673	$ 1,530

Consolidated balance sheet

Consolidated balance sheet $ in Millions, $ in Millions	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Current Assets
Cash and cash equivalents	$ 620	$ 673
Accounts receivable	3,624	3,092
Loans receivable from affiliates (Note 12)	0	1,217
Inventories	936	724
Other current assets (Note 8)	2,152	1,717
Total current assets	7,332	7,423
Plant, Property and Equipment (Note 9)	75,940	70,182
Net Investment in Leases (Note 10)	1,895	0
Equity investments	9,535	8,441
Long-Term Loans Receivable from Affiliate (Notes 7 and 12)	0	238
Restricted Investments	2,108	2,182
Regulatory Assets (Note 13)	1,910	1,767
Goodwill (Note 14)	12,843	12,582
Other Long-Term Assets (Note 15)	2,785	1,403
Total assets	114,348	104,218
Current Liabilities
Notes payable (Note 16)	6,262	5,166
Accounts payable and other (Note 17)	7,149	5,099
Dividends payable	930	879
Accrued interest	668	577
Current portion of long-term debt (Note 20)	1,898	1,320
Total current liabilities	16,907	13,041
Regulatory Liabilities (Note 13)	4,520	4,300
Other Long-Term Liabilities (Note 18)	1,017	1,059
Deferred Income Tax Liabilities (Note 19)	7,648	6,142
Long-Term Debt (Note 20)	39,645	37,341
Junior Subordinated Notes (Note 21)	10,495	8,939
Total liabilities	80,232	70,822
EQUITY
Common shares, no par value (Note 24)	28,995	26,716
Preferred shares (Note 25)	2,499	3,487
Additional paid-in capital	722	729
Retained earnings	819	3,773
Accumulated other comprehensive income/(loss) (Note 26)	955	(1,434)
Controlling Interests	33,990	33,271
Non-controlling interests (Note 23)	126	125
Total Equity	34,116	33,396
Total Liabilities and Equity	$ 114,348	$ 104,218

Consolidated balance sheet (Par

Consolidated balance sheet (Parenthetical) - shares shares in Millions	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Common shares issued (in shares)	1,018	981
Common shares outstanding (in shares)	1,018	981

Consolidated statement of equit

Consolidated statement of equity - CAD ($) $ in Millions	Total	Equity Attributable to Controlling Interests	Common shares	Preferred Shares (Note 25)	Additional Paid-In Capital	Retained Earnings	AOCI Attributable to Parent	Equity Attributable to Non-Controlling Interests
Balance at beginning of year at Dec. 31, 2019			$ 24,387	$ 3,980		$ 3,955	$ (1,559)	$ 1,634
Shares issued:
Exercise of stock options			101
Issuance of stock options, net of exercises					$ 2
Net income attributable to controlling interests	$ 4,616					4,616
Common share dividends						(3,045)
Preferred share dividends						(159)
Other comprehensive income/(loss) attributable to controlling interests	(918)						(880)
Net income attributable to non-controlling interests	(297)							307
Other comprehensive income/(loss) attributable to non-controlling interests								(38)
Distributions declared to non-controlling interests								(221)
Balance at end of year at Dec. 31, 2020	33,080	$ 31,398	24,488	3,980	2	5,367	(2,439)	1,682
Shares issued:
Acquisition of TC PipeLines, LP, net of transaction costs (Note 23)	2,063		2,063		(398)		353	(1,563)
Exercise of stock options			165
Keystone XL project-level credit facility retirement and issuance of Class C Interests (Note 6)	737				737
Repurchase of redeemable non-controlling interest (Note 6)					394
Issuance of stock options, net of exercises					(6)
Net income attributable to controlling interests	1,955					1,955
Common share dividends						(3,409)
Preferred share dividends						(133)
Redemption of shares				(493)		(7)
Other comprehensive income/(loss) attributable to controlling interests	642						652
Net income attributable to non-controlling interests	(91)							90
Other comprehensive income/(loss) attributable to non-controlling interests								(10)
Distributions declared to non-controlling interests								(74)
Balance at end of year at Dec. 31, 2021	33,396	33,271	26,716	3,487	729	3,773	(1,434)	125
Shares issued:
Under public offering, net of issue costs			1,754
Dividend reinvestment and share purchase plan			342
Exercise of stock options			183
Issuance of stock options, net of exercises					(7)
Net income attributable to controlling interests	748					748
Common share dividends						(3,595)
Preferred share dividends						(95)
Redemption of shares				(988)		(12)
Other comprehensive income/(loss) attributable to controlling interests	2,397						2,389
Net income attributable to non-controlling interests	(37)							37
Other comprehensive income/(loss) attributable to non-controlling interests								8
Distributions declared to non-controlling interests								(44)
Balance at end of year at Dec. 31, 2022	$ 34,116	$ 33,990	$ 28,995	$ 2,499	$ 722	$ 819	$ 955	$ 126

DESCRIPTION OF TC ENERGY'S BUSI

DESCRIPTION OF TC ENERGY'S BUSINESS	12 Months Ended
DESCRIPTION OF TC ENERGY'S BUSINESS	Dec. 31, 2022
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 40,792 km (25,347 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 50,164 km (31,170 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 2,775 km (1,723 miles) of regulated natural gas pipelines currently in operation. Liquids Pipelines The Liquids Pipelines segment primarily consists of the Company's investments in 4,856 km (3,019 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 For the period ended December 31, 2022, the Power and Storage segment has been renamed the Power and Energy Solutions segment, which primarily consists of the Company's investments in approximately 4,300 MW of power generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These assets are located in Alberta, Ontario, Québec and New Brunswick. 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
ACCOUNTING POLICIES	Dec. 31, 2022
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: • assessment of goodwill impairment indicators and fair value of reporting units that contain goodwill (Note 14) • capital cost estimates to complete the Coastal GasLink pipeline used to measure TC Energy’s maximum exposure to loss resulting from its involvement with Coastal GasLink Limited Partnership (Coastal GasLink LP) and in measuring the fair value of TC Energy’s equity investment in Coastal GasLink LP (Notes 7 and 32). 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 (Note 6) • recoverability and depreciation rates of plant, property and equipment (Note 9) • allocation of consideration to lease and non-lease components in a contract that contains a lease (Note 10) • assumptions used to measure the carrying amount of (Note 10) and expected credit losses (Note 28) on net investment in leases and certain contract assets • fair value of equity investments not otherwise noted above (Note 11) • carrying value of regulatory assets and liabilities (Note 13) • assumptions used to measure the environmental remediation liability from the Keystone pipeline rupture (Note 17) • recognition of asset retirement obligations (Note 18) • provisions for income taxes, including valuation allowances and releases (Note 19) • assumptions used to measure retirement and other post-retirement benefit obligations (Note 27) • fair value of financial instruments (Note 28) • fair value of assets and liabilities acquired in a business combination (Note 30) • provisions for commitments, contingencies and guarantees (Note 31). TC Energy continues to assess the impact of climate change on the consolidated financial statements. The Company has announced internal greenhouse gas reduction targets and closely monitors regulatory initiatives that may impact its existing businesses. There were also recent 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 and accrued environmental costs. 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. 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 income 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. 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 on the Consolidated statement of income, and is presented on the Consolidated balance sheet as a reduction to the carrying value of the related financial asset. Restricted Investments The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are classified as available for sale and are recorded at fair value on the Consolidated balance sheet. As a result of the CER’s Land Matters Consultation Initiative (LMCI), TC Energy is required to collect funds to cover estimated future pipeline abandonment costs for larger CER-regulated Canadian pipelines. Funds collected are placed in trusts that hold and invest the funds and are accounted for as restricted investments (LMCI restricted investments). LMCI restricted investments may only be used to fund the abandonment of the CER-regulated pipeline facilities, therefore, a corresponding regulatory liability is recorded on the Consolidated balance sheet. The Company also has other restricted investments that have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. Income Taxes The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in net income in the period in which they occur, except for changes in balances related to regulated natural gas pipelines which are deferred until they are refunded or recovered in tolls, as permitted by the regulator. Deferred income tax assets and liabilities are classified as non-current on the Consolidated balance sheet. The Company’s exposure to uncertain tax positions is evaluated and a provision is made where it is more likely than not that this exposure will materialize. Canadian income taxes are not provided for on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Any interest and/or penalty incurred related to tax is reflected in income tax expense. Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to Plant operating costs and other in the Consolidated statement of income. In determining the fair value of ARO, the following assumptions are used: • the exp

ACCOUNTING CHANGES

ACCOUNTING CHANGES	12 Months Ended
ACCOUNTING CHANGES	Dec. 31, 2022
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES Changes in Accounting Policies for 2022 Reference Rate Reform In March 2020, FASB issued optional guidance with respect to the expected cessation of certain reference interest rates. The guidance provides optional expedients for contracts and hedging relationships that are affected by reference rate reform if certain criteria are met. In December 2022, FASB issued an update to defer the sunset date of the guidance to December 31, 2024. For eligible hedging relationships, the Company has applied the optional expedient allowing an entity to assume that the hedged forecasted transaction in a cash flow hedge is probable of occurring. The Company expects to use practical expedients available in the guidance to treat contract modifications as events that do not require contract remeasurement or reassessment of previous accounting determinations. As such, these changes are not expected to have a material impact on the Company's consolidated financial statements. Government Assistance In November 2021, the FASB issued new guidance that expands annual disclosure requirements for entities that account for a transaction with a government by applying a grant or contribution accounting model by analogy to other accounting guidance. Entities are required to disclose the nature of the transactions, the related accounting policies used to account for the transactions, the effect of the transactions on an entity’s financial statements and any significant terms and conditions of the transaction. This new guidance is effective for annual disclosure requirements at December 31, 2022 and can be applied either prospectively or retrospectively, with early application permitted. The Company adopted the guidance effective January 1, 2022 on a prospective basis and it did not have a material impact on the Company's consolidated financial statements. Contract Assets and Liabilities from Contracts with Customers In October 2021, the FASB issued new guidance that amends the accounting for contract assets and liabilities from contracts with customers acquired in a business combination. At the acquisition date, an acquirer should account for the contract assets and liabilities in accordance with guidance on revenue from contracts with customers. This new guidance is effective January 1, 2023 and is applied prospectively with early adoption permitted. Early adoption requires the application of the amendments retrospectively to all business combinations with an acquisition date in the year of early adoption. The Company elected to adopt the new guidance effective January 1, 2022 and it did not have any impact on the Company's consolidated financial statements.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
SEGMENTED INFORMATION	Dec. 31, 2022
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION year ended December 31, 2022 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Energy Solutions Corporate 1 Total (millions of Canadian $) 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 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 (Losses)/Earnings (1,440) 2,617 491 1,123 833 8 3,632 Interest expense (2,588) Allowance for funds used during construction 369 Foreign exchange loss, net 3 (185) Interest income and other 146 Income before Income Taxes 1,374 Income tax expense (589) Net Income 785 Net income attributable to non-controlling interests (37) Net Income Attributable to Controlling Interests 748 Preferred share dividends (107) Net Income Attributable to Common Shares 641 Capital Spending Capital expenditures 3,274 2,137 1,027 106 93 41 6,678 Capital projects in development — — — — 49 — 49 Contributions to equity investments 4 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 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 loss, net by the corresponding foreign exchange losses and gains on the affiliate receivable balance until March 15, 2022, when it was fully repaid upon maturity. Refer to Note 12, Loans receivable from affiliates, for additional information. 4 Contributions to equity investments in the Corporate segment of $1.2 billion are offset by the equivalent amount in Other distributions from equity investments, although they are reported on a gross basis in the Company’s Consolidated statement of cash flows. Refer to Note 12, Loans receivable from affiliates, for additional information. year ended December 31, 2021 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Energy Solutions Corporate 1 Total (millions of Canadian $) 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 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) Asset impairment charge and other — — — (2,775) — — (2,775) Gain 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 gain, net 3 10 Interest income and other 190 Income before Income Taxes 2,166 Income tax expense (120) Net Income 2,046 Net income attributable to non-controlling interests (91) Net Income Attributable to Controlling Interests 1,955 Preferred share dividends (140) Net Income Attributable to Common Shares 1,815 Capital Spending 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 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 gain, net by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 12, Loans receivable from affiliates, for additional information. year ended December 31, 2020 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Energy Solutions Corporate 1 Total (millions of Canadian $) Revenues 4,469 5,031 716 2,371 412 — 12,999 Intersegment revenues — 165 — — 20 (185) 2 — 4,469 5,196 716 2,371 432 (185) 12,999 Income from equity investments 12 264 127 75 455 86 3 1,019 Plant operating costs and other (1,631) (1,485) (57) (654) (220) 169 2 (3,878) Property taxes (284) (337) — (101) (5) — (727) Depreciation and amortization (1,273) (801) (117) (332) (67) — (2,590) Net gain/(loss) on sale of assets 364 — — — (414) — (50) Segmented Earnings 1,657 2,837 669 1,359 181 70 6,773 Interest expense (2,228) Allowance for funds used during construction 349 Foreign exchange gain, net 3 28 Interest income and other 185 Income before Income Taxes 5,107 Income tax expense (194) Net Income 4,913 Net income attributable to non-controlling interests (297) Net Income Attributable to Controlling Interests 4,616 Preferred share dividends (159) Net Income Attributable to Common Shares 4,457 Capital Spending Capital expenditures 3,503 2,785 173 1,315 179 58 8,013 Capital projects in development — — — 122 — — 122 Contributions to equity investments 105 — — 5 655 — 765 3,608 2,785 173 1,442 834 58 8,900 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 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 gain, net by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 12, Loans receivable from affiliates, for additional information. at December 31 2022 2021 (millions of Canadian $) Total Assets by Segment Canadian Natural Gas Pipelines 27,456 25,452 U.S. Natural Gas Pipelines 50,038 45,502 Mexico Natural Gas Pipelines 9,231 7,547 Liquids Pipelines 15,587 14,951 Power and Energy Solutions 8,272 6,563 Corporate 3,764 4,203 114,348 104,218 Geographic Information year ended December 31 2022 2021 2020 (millions of Canadian $) Revenues Canada – domestic 4,942 4,603 4,392 Canada – export 1,322 1,226 1,059 United States 8,025 6,953 6,832 Mexico 688 605 716 14,977 13,387 12,999 at December 31 2022 2021 (millions of Canadian $) Plant, Property and Equipment Canada 27,232 24,890 United States 43,505 39,335 Mexico 5,203 5,957 75,940 70,182

REVENUES

REVENUES	12 Months Ended
REVENUES	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
REVENUES	REVENUES Disaggregation of Revenues 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 development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy as at December 31, 2022. Refer to Note 30, Acquisitions and dispositions, for additional information. 2 Includes $37 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. 3 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. 4 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information on income from operating lease arrangements and financial instruments, respectively. 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 13, 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 development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy as at December 31, 2021. Refer to Note 30, Acquisitions and dispositions, for additional information. 2 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information on income from operating lease arrangements and financial instruments, respectively. 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 13, Rate-regulated businesses, for additional information. year ended December 31, 2020 Canadian U.S. Mexico Liquids Pipelines Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,408 4,301 607 2,206 — 11,522 Power generation — — — — 192 192 Natural gas storage and other 1 61 654 109 3 106 933 4,469 4,955 716 2,209 298 12,647 Other revenues 2,3 — 76 — 162 114 352 4,469 5,031 716 2,371 412 12,999 1 Includes $138 million of fee revenues from affiliates, of which $77 million was related to the construction of the Sur de Texas pipeline which is 60 per cent owned by TC Energy and $61 million was related to development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy as at December 31, 2020. Refer to Note 30, Acquisitions and dispositions, for additional information. 2 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information on income from operating lease arrangements and financial instruments, respectively. 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 13, Rate-regulated businesses, for additional information. Contract Balances at December 31 2022 2021 Affected line item on the (millions of Canadian $) Receivables from contracts with customers 1,907 1,627 Accounts receivable Contract assets (Note 8) 155 202 Other current assets Long-term contract assets (Note 15) 355 249 Other long-term assets Contract liabilities 1 (Note 17) 62 90 Accounts payable and other Long-term contract liabilities (Note 18) 32 184 Other long-term liabilities 1 During the year ended December 31, 2022, $51 million (2021 – $95 million) of revenues were recognized that were included in 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. In the prior year, contract liabilities and long-term contract liabilities primarily related to force majeure fixed capacity payments received on long-term capacity arrangements in Mexico. During the year ended December 31, 2022, and under the terms of the consolidated Transportation Service Agreement (TSA), the contract liability relating to the in-service TGNH pipelines was netted against certain contract asset balances and settled against the initial recording of the net investment in leases on the Consolidated balance sheet. Future Revenues from Remaining Performance Obligations As at December 31, 2022, future revenues from long-term pipeline capacity arrangements and transportation as well as natural gas storage and other contracts extending through 2055 are approximately $23.3 billion, of which approximately $3.8 billion is expected to be recognized in 2023. 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
KEYSTONE XL	Dec. 31, 2022
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 2022, the Company received $571 million towards its contractual recoveries, resulting in a remaining balance of $130 million at December 31, 2022. 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. The Company paid $24 million in 2022 (2021 – $192 million) towards contractual and legal obligations related to termination activities. At December 31, 2022, the remaining balance accrued was $48 million. For the year ended December 31, 2022, the Company sold plant and equipment with a carrying value of approximately $25 million (2021 – $16 million), resulting in a gain of $64 million (2021 – nil). The Company expects to dispose of the remaining assets in 2023. In 2022, as part of the Keystone XL impairment charge and other, the Company recognized a $96 million U.S. minimum tax related 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) and in accordance with the terms of the guarantee, the Government of Alberta repaid the full outstanding balance in June 2021 and it was subsequently terminated. 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. 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 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. For the year ended December 31, 2022, the Company made Class C distributions to the Government of Alberta of $43 million (2021 – $16 million). The changes in Redeemable non-controlling interest classified in mezzanine equity were as follows: (millions of Canadian $) Balance at January 1, 2021 393 Net income attributable to redeemable non-controlling interest 1 Class A Interests repurchased (394) Balance at December 31, 2021 —

COASTAL GASLINK

COASTAL GASLINK	12 Months Ended
COASTAL GASLINK	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
COASTAL GASLINK	COASTAL GASLINK Impairment of Equity Investment in Coastal GasLink LP July 2022 Amended Coastal GasLink Agreements On July 28, 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 and required TC Energy to make a contractual equity contribution to Coastal GasLink LP in the amount of $1.9 billion, which did not result in a change in the Company’s 35 per cent ownership. Refer to Note 32, Variable interest entities, for additional information. The $1.9 billion contractual equity contribution was accrued and initially recognized in Equity investments on the Consolidated balance sheet at the time of signing the July 2022 agreements and is being paid in installments over the period August 2022 to February 2023. At December 31, 2022, $0.5 billion of this equity contribution remained in Accounts payable and other on the Consolidated balance sheet. Under the terms of the July 2022 agreements, any additional equity financing required by Coastal GasLink LP to fund construction of the pipeline beyond the $1.9 billion equity contribution will initially be financed through a subordinated loan agreement between TC Energy and Coastal GasLink LP. Any amounts outstanding on this loan will be repaid by Coastal GasLink LP to TC Energy, once final costs are known, which will be determined after the pipeline is placed in 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 but will not result in a change to the Company’s 35 per cent ownership. Capital Cost Update and Impairment In the fourth quarter of 2022, the Company announced that it expected a material increase in project costs and to the Company’s corresponding funding requirements. On February 1, 2023, TC Energy announced that the revised capital cost of the Coastal GasLink pipeline project was expected to be approximately $14.5 billion. While this estimate includes contingencies for certain factors that may be outside the control of Coastal GasLink LP, such as challenging conditions in the Western Canadian labour market, shortages of skilled labour, the impacts of contractor underperformance, as well as drought conditions and erosion and sediment control challenges, as with any complex construction project, the final capital cost is subject to certain risks and uncertainties. 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 determined that this was an other-than-temporary impairment of its equity investment in Coastal GasLink LP and a pre-tax impairment charge of $3,048 million ($2,643 million after tax) was recognized in fourth quarter 2022 in Impairment of equity investment in the Consolidated statement of income in the Canadian Natural Gas Pipelines segment. The pre-impairment carrying value of the investment in Coastal GasLink LP at December 31, 2022 consisted of amounts in Equity investments ($2,798 million) and Loans receivable from affiliates ($250 million), which were reduced to a nil balance. TC Energy expects to fund an additional $3.3 billion related to the revised estimated capital cost to complete the Coastal GasLink pipeline, and a significant portion of the Company’s future investment in Coastal GasLink LP is expected to be impaired. The Company will continue to assess for other-than-temporary declines in the fair value of this investment, and the extent of any future impairment charges will depend on the outcome of the valuation assessment performed at the respective reporting date. The fair value of TC Energy’s investment in Coastal GasLink LP at December 31, 2022 was estimated using a 40-year discounted cash flow model. Cash inflows in the model were estimated using contractually agreed upon terms and extension provisions in the TSAs between Coastal GasLink LP and the LNG Canada participants. For cash outflows in the model, the increase in estimated capital cost and the Company’s corresponding funding requirements have the most significant impact on the determination of the fair value of TC Energy's investment in Coastal GasLink LP. The cash flow analysis included a capital cost estimate for the Coastal GasLink pipeline of $14.5 billion. Any change from this capital cost estimate will have an approximate dollar-for-dollar impact on the Company’s future funding requirements, subject to any final cost sharing between the Coastal GasLink LP partners, and will impact the estimated fair value of, and the Company’s recovery of, its equity investment in Coastal GasLink LP in future periods. Other assumptions included in the discounted cash flow model include discount rate, long-term project financing plans and estimated completion date. Changes to these other assumptions would not reasonably expect to change the impairment recorded in the fourth quarter of 2022. A deferred income tax recovery was recognized on the pre-tax impairment charge, net of certain unrealized tax losses not recognized. Refer to Note 19, Income taxes, for additional information. 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, which is estimated to be $3.3 billion. As at December 31, 2022, the total capacity committed by TC Energy under this subordinated loan agreement was $1.3 billion. The committed capacity under this loan is expected to increase in the future as required to support additional financing requirements. Any amounts outstanding will be repaid by Coastal GasLink LP to TC Energy, once final costs are known, which will be determined after the pipeline is placed in 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, in accordance with the July 2022 agreements, these additional equity contributions will be predominantly funded by TC Energy but will not result in a change to the Company’s 35 per cent ownership. As noted above, the $250 million balance outstanding on this loan at December 31, 2022 was reduced to nil as part of the impairment charge recognized in fourth quarter 2022. The table below reflects the changes in this loan balance for the year ended December 31, 2022. (millions of Canadian $) Outstanding balance as at December 31, 2021 238 Issuances 1 112 Repayments 1 (100) Outstanding balance at December 31, 2022 250 Impairment (250) Carrying value at December 31, 2022 — 1 Presented on a net basis on the Company's Consolidated statement of cash flows. (millions of Canadian $) Ownership Interest at December 31, 2022 Income from Equity Equity year ended December 31 at December 31 2022 2021 2020 2022 2021 Canadian Natural Gas Pipelines TQM 1 50.0 % 17 12 12 165 118 Coastal GasLink 1 35.0 % 1 — — — 386 U.S. Natural Gas Pipelines Northern Border 50.0 % 92 80 100 516 505 Millennium 47.5 % 103 91 96 500 474 Iroquois 50.0 % 77 55 52 237 392 Other Various 20 18 16 122 137 Mexico Natural Gas Pipelines Sur de Texas 60.0 % 150 160 213 1,050 835 Liquids Pipelines Grand Rapids 1 50.0 % 54 54 53 964 980 Port Neches Link LLC 2 95.0 % — — — 149 103 HoustonLink Pipeline 1 50.0 % 1 1 — 19 18 Northern Courier 1,3 nil — 16 22 — — Power and Energy Solutions Bruce Power 1 48.3 % 537 411 439 5,783 4,493 Other Various 2 — 16 30 — 1,054 898 1,019 9,535 8,441 1 Classified as a non-consolidated VIE. Refer to Note 32, Variable interest entities, for additional information. 2 Classified as a non-consolidated VIE in 2021. Refer to Note 32, Variable interest entities, for additional information. 3 In November 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 30, Acquisitions and dispositions, for additional information. Impairment of Equity Investment On February 1, 2023, Coastal GasLink LP announced that the revised capital cost of the Coastal GasLink pipeline project is expected to be approximately $14.5 billion. The increase in the expected capital cost of the project caused TC Energy to re-evaluate its investment in Coastal GasLink LP, resulting in a pre-tax impairment charge of $3,048 million ($2,643 million after tax) recorded in fourth quarter 2022. Refer to Note 7, 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, 2022, 2021 and 2020 were as follows: year ended December 31 2022 2021 2020 (millions of Canadian $) Distributions Sur de Texas debt repayments 1,2 2,404 73 — Distributions received from operating activities of equity investments 1,025 975 1,123 Other 1 228 — — 3,657 1,048 1,123 Contributions Contributions to Coastal GasLink 1 1,414 92 101 Sur de Texas debt financing 1,2 1,199 — — Contributions made to other equity investments 1 820 1,118 664 3,433 1,210 765 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 12, Loans receivable from affiliates, for further information on 2022 refinancing activities with the Sur de Texas joint venture. Summarized Financial Information of Equity Investments year ended December 31 2022 2021 2020 (millions of Canadian $) Income Revenues 5,891 5,447 5,838 Operating and other expenses (3,390) (3,293) (3,341) Net income 2,147 1,859 2,047 Net income attributable to TC Energy 1,054 898 1,019 at December 31 2022 2021 (millions of Canadian $) Balance Sheet Current assets 3,414 3,498 Non-current assets 37,713 30,165 Current liabilities (2,856) (2,540) Non-current liabilities (17,690) (16,400) At December 31, 2022, the cumulative carrying value of the Company’s equity investments was $299 million lower than the cumulative underlying equity in the net assets primarily due to the 2022 impairment of the equity investment in Coastal GasLink LP, partially offset by fair value adjustments at the time of acquisition or partial monetization as well as interest capitalized during construction. Refer to Note 7, Coastal GasLink, for additional information. At December 31, 2021, the cumulative carrying value of the Company’s equity investments was $1,109 million higher than the cumulative underlying equity in the net assets primarily due to fair value adjustments at the time of acquisition or partial monetization as well as interest capitalized during construction.

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
OTHER CURRENT ASSETS	Dec. 31, 2022
Other Assets [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS at December 31 2022 2021 (millions of Canadian $) Fair value of derivative contracts (Note 28) 614 169 Current portion of Keystone environmental provision recovery (Note 17 ) 410 — Current portion of net investment in leases (Note 10 ) 291 — Contract assets (Note 5) 155 202 Keystone XL assets held for sale 122 138 Prepaid expenses 118 112 Cash provided as collateral 106 273 Keystone XL contractual recoveries (Note 6) 86 640 Regulatory assets (Note 13) 67 53 Other 183 130 2,152 1,717

PLANT, PROPERTY AND EQUIPMENT

PLANT, PROPERTY AND EQUIPMENT	12 Months Ended
PLANT, PROPERTY AND EQUIPMENT	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
PLANT, PROPERTY AND EQUIPMENT	PLANT, PROPERTY AND EQUIPMENT at December 31 2022 2021 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 18,119 6,285 11,834 14,892 5,751 9,141 Compression 6,265 2,224 4,041 6,191 2,065 4,126 Metering and other 1,518 769 749 1,458 705 753 25,902 9,278 16,624 22,541 8,521 14,020 Under construction 1,552 — 1,552 2,285 — 2,285 27,454 9,278 18,176 24,826 8,521 16,305 Canadian Mainline Pipeline 10,472 7,852 2,620 10,423 7,698 2,725 Compression 4,328 3,247 1,081 4,165 3,125 1,040 Metering and other 692 285 407 652 264 388 15,492 11,384 4,108 15,240 11,087 4,153 Under construction 269 — 269 139 — 139 15,761 11,384 4,377 15,379 11,087 4,292 Other Canadian Natural Gas Pipelines 1 Other 1,984 1,624 360 1,937 1,567 370 Under construction 455 — 455 58 — 58 2,439 1,624 815 1,995 1,567 428 45,654 22,286 23,368 42,200 21,175 21,025 U.S. Natural Gas Pipelines Columbia Gas Pipeline 12,471 1,069 11,402 11,205 799 10,406 Compression 5,190 495 4,695 4,522 381 4,141 Metering and other 4,026 346 3,680 3,657 257 3,400 21,687 1,910 19,777 19,384 1,437 17,947 Under construction 659 — 659 433 — 433 22,346 1,910 20,436 19,817 1,437 18,380 ANR Pipeline 2,066 641 1,425 1,820 557 1,263 Compression 3,785 734 3,051 2,559 565 1,994 Metering and other 1,666 440 1,226 1,391 422 969 7,517 1,815 5,702 5,770 1,544 4,226 Under construction 328 — 328 833 — 833 7,845 1,815 6,030 6,603 1,544 5,059 at December 31 2022 2021 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Other U.S. Natural Gas Pipelines Columbia Gulf 3,511 224 3,287 2,749 178 2,571 GTN 2,964 1,239 1,725 2,701 1,071 1,630 Great Lakes 2,367 1,387 980 2,162 1,255 907 Other 2 1,928 760 1,168 1,755 657 1,098 10,770 3,610 7,160 9,367 3,161 6,206 Under construction 328 — 328 533 — 533 11,098 3,610 7,488 9,900 3,161 6,739 41,289 7,335 33,954 36,320 6,142 30,178 Mexico Natural Gas Pipelines 3 Pipeline 2,299 348 1,951 2,957 476 2,481 Compression 374 59 315 480 80 400 Metering and other 487 113 374 626 155 471 3,160 520 2,640 4,063 711 3,352 Under construction 2,547 — 2,547 2,590 — 2,590 5,707 520 5,187 6,653 711 5,942 Liquids Pipelines Keystone Pipeline System Pipeline 9,777 2,056 7,721 9,209 1,758 7,451 Pumping equipment 1,064 288 776 1,020 252 768 Tanks and other 3,723 859 2,864 3,534 737 2,797 14,564 3,203 11,361 13,763 2,747 11,016 Under construction 96 — 96 72 — 72 14,660 3,203 11,457 13,835 2,747 11,088 Intra-Alberta Pipelines 199 19 180 199 14 185 14,859 3,222 11,637 14,034 2,761 11,273 Power and Energy Solutions Natural Gas Power Generation 1,260 642 618 1,267 605 662 Natural Gas Storage and Other 820 238 582 797 216 581 2,080 880 1,200 2,064 821 1,243 Under construction 80 — 80 5 — 5 2,160 880 1,280 2,069 821 1,248 Corporate 900 386 514 836 320 516 110,569 34,629 75,940 102,112 31,930 70,182 1 Includes Foothills, Ventures LP and Great Lakes Canada. 2 Includes Portland, North Baja, Tuscarora, Crossroads and mineral rights.

LEASES

LEASES	12 Months Ended
LEASES	Dec. 31, 2022
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 $) 2022 2021 Operating lease cost 1 106 105 Sublease income (5) (8) Net operating lease cost 101 97 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 $) 2022 2021 Cash paid for amounts included in the measurement of operating lease liabilities 67 69 ROU assets obtained in exchange for new operating lease liabilities 49 7 at December 31 2022 2021 Weighted average remaining lease term 8 years 9 years Weighted average discount rate 3.5 % 3.5 % Maturities of operating lease liabilities are as follows: (millions of Canadian $) 2022 2021 Less than one year 68 63 One to two years 65 60 Two to three years 62 58 Three to four years 60 55 Four to five years 54 54 More than five years 187 213 Total operating lease payments 496 503 Imputed interest (63) (74) Operating lease liabilities 433 429 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2022 2021 Accounts payable and other 54 49 Other long-term liabilities (Note 18) 379 380 433 429 As at December 31, 2022, the carrying value of the ROU assets recorded under operating leases was $415 million (2021 – $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, 2022 was $118 million (2021 – $126 million; 2020 – $130 million). Future lease payments to be received under operating leases are as follows: (millions of Canadian $) 2022 2021 Less than one year 113 113 One to two years 111 111 Two to three years 94 110 Three to four years 70 94 Four to five years — 70 388 498 The cost and accumulated depreciation for facilities accounted for as operating leases was $802 million and $360 million, respectively, at December 31, 2022 (2021 – $812 million and $340 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, 2022, included the Tamazunchale pipeline, the north section 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. At lease commencement, the Company recognized an aggregate net investment in sales-type leases. The TGNH pipelines are rate-regulated and the tolls are designed to recover the cost of providing service. On this basis, the Company applied judgment to determine that, at the inception of the lease arrangement, the fair value of the underlying assets approximated the carrying value and the residual value approximated the remaining carrying value at the end of the lease term. The following table lists the components of the aggregate Net investment in leases reflected on the Company's Consolidated balance sheet: (millions of Canadian $) December 31, 2022 Net Investment in Leases Minimum lease payments 9,457 Unearned lease income (7,132) Lease receivable 2,325 Expected credit loss provision 1 (150) Present value of unguaranteed residual value 11 2,186 Current portion included in Other current assets (Note 8) (291) 1,895 1 Includes $1 million of foreign currency translation losses. Future lease payments to be received under the existing sales-type leases are as follows: (millions of Canadian $) December 31, 2022 Less than one year 291 One to two years 291 Two to three years 291 Three to four years 291 Four to five years 291 More than five years 8,002 9,457 Future lease payments will increase as assets associated with sales-type leases come into service. For the year ended December 31, 2022, the Company recorded $127 million of sales-type lease income in Mexico Natural Gas Pipelines revenues. For the year ended December 31, 2022, the Company recorded a $149 million (2021 and 2020 – nil) ECL provision in Plant operating costs and other relating to net investment in leases. Refer to Note 28, Risk management and financial instruments, for additional information.
LEASES	LEASES As a Lessee The Company has operating leases for corporate offices, other various premises, equipment and land. Some leases have an option to renew for periods of one Operating lease cost was as follows: year ended December 31 (millions of Canadian $) 2022 2021 Operating lease cost 1 106 105 Sublease income (5) (8) Net operating lease cost 101 97 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 $) 2022 2021 Cash paid for amounts included in the measurement of operating lease liabilities 67 69 ROU assets obtained in exchange for new operating lease liabilities 49 7 at December 31 2022 2021 Weighted average remaining lease term 8 years 9 years Weighted average discount rate 3.5 % 3.5 % Maturities of operating lease liabilities are as follows: (millions of Canadian $) 2022 2021 Less than one year 68 63 One to two years 65 60 Two to three years 62 58 Three to four years 60 55 Four to five years 54 54 More than five years 187 213 Total operating lease payments 496 503 Imputed interest (63) (74) Operating lease liabilities 433 429 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2022 2021 Accounts payable and other 54 49 Other long-term liabilities (Note 18) 379 380 433 429 As at December 31, 2022, the carrying value of the ROU assets recorded under operating leases was $415 million (2021 – $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, 2022 was $118 million (2021 – $126 million; 2020 – $130 million). Future lease payments to be received under operating leases are as follows: (millions of Canadian $) 2022 2021 Less than one year 113 113 One to two years 111 111 Two to three years 94 110 Three to four years 70 94 Four to five years — 70 388 498 The cost and accumulated depreciation for facilities accounted for as operating leases was $802 million and $360 million, respectively, at December 31, 2022 (2021 – $812 million and $340 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, 2022, included the Tamazunchale pipeline, the north section 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. At lease commencement, the Company recognized an aggregate net investment in sales-type leases. The TGNH pipelines are rate-regulated and the tolls are designed to recover the cost of providing service. On this basis, the Company applied judgment to determine that, at the inception of the lease arrangement, the fair value of the underlying assets approximated the carrying value and the residual value approximated the remaining carrying value at the end of the lease term. The following table lists the components of the aggregate Net investment in leases reflected on the Company's Consolidated balance sheet: (millions of Canadian $) December 31, 2022 Net Investment in Leases Minimum lease payments 9,457 Unearned lease income (7,132) Lease receivable 2,325 Expected credit loss provision 1 (150) Present value of unguaranteed residual value 11 2,186 Current portion included in Other current assets (Note 8) (291) 1,895 1 Includes $1 million of foreign currency translation losses. Future lease payments to be received under the existing sales-type leases are as follows: (millions of Canadian $) December 31, 2022 Less than one year 291 One to two years 291 Two to three years 291 Three to four years 291 Four to five years 291 More than five years 8,002 9,457 Future lease payments will increase as assets associated with sales-type leases come into service. For the year ended December 31, 2022, the Company recorded $127 million of sales-type lease income in Mexico Natural Gas Pipelines revenues. For the year ended December 31, 2022, the Company recorded a $149 million (2021 and 2020 – nil) ECL provision in Plant operating costs and other relating to net investment in leases. Refer to Note 28, Risk management and financial instruments, for additional information.
LEASES	LEASES As a Lessee The Company has operating leases for corporate offices, other various premises, equipment and land. Some leases have an option to renew for periods of one Operating lease cost was as follows: year ended December 31 (millions of Canadian $) 2022 2021 Operating lease cost 1 106 105 Sublease income (5) (8) Net operating lease cost 101 97 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 $) 2022 2021 Cash paid for amounts included in the measurement of operating lease liabilities 67 69 ROU assets obtained in exchange for new operating lease liabilities 49 7 at December 31 2022 2021 Weighted average remaining lease term 8 years 9 years Weighted average discount rate 3.5 % 3.5 % Maturities of operating lease liabilities are as follows: (millions of Canadian $) 2022 2021 Less than one year 68 63 One to two years 65 60 Two to three years 62 58 Three to four years 60 55 Four to five years 54 54 More than five years 187 213 Total operating lease payments 496 503 Imputed interest (63) (74) Operating lease liabilities 433 429 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2022 2021 Accounts payable and other 54 49 Other long-term liabilities (Note 18) 379 380 433 429 As at December 31, 2022, the carrying value of the ROU assets recorded under operating leases was $415 million (2021 – $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, 2022 was $118 million (2021 – $126 million; 2020 – $130 million). Future lease payments to be received under operating leases are as follows: (millions of Canadian $) 2022 2021 Less than one year 113 113 One to two years 111 111 Two to three years 94 110 Three to four years 70 94 Four to five years — 70 388 498 The cost and accumulated depreciation for facilities accounted for as operating leases was $802 million and $360 million, respectively, at December 31, 2022 (2021 – $812 million and $340 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, 2022, included the Tamazunchale pipeline, the north section 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. At lease commencement, the Company recognized an aggregate net investment in sales-type leases. The TGNH pipelines are rate-regulated and the tolls are designed to recover the cost of providing service. On this basis, the Company applied judgment to determine that, at the inception of the lease arrangement, the fair value of the underlying assets approximated the carrying value and the residual value approximated the remaining carrying value at the end of the lease term. The following table lists the components of the aggregate Net investment in leases reflected on the Company's Consolidated balance sheet: (millions of Canadian $) December 31, 2022 Net Investment in Leases Minimum lease payments 9,457 Unearned lease income (7,132) Lease receivable 2,325 Expected credit loss provision 1 (150) Present value of unguaranteed residual value 11 2,186 Current portion included in Other current assets (Note 8) (291) 1,895 1 Includes $1 million of foreign currency translation losses. Future lease payments to be received under the existing sales-type leases are as follows: (millions of Canadian $) December 31, 2022 Less than one year 291 One to two years 291 Two to three years 291 Three to four years 291 Four to five years 291 More than five years 8,002 9,457 Future lease payments will increase as assets associated with sales-type leases come into service. For the year ended December 31, 2022, the Company recorded $127 million of sales-type lease income in Mexico Natural Gas Pipelines revenues. For the year ended December 31, 2022, the Company recorded a $149 million (2021 and 2020 – nil) ECL provision in Plant operating costs and other relating to net investment in leases. Refer to Note 28, Risk management and financial instruments, for additional information.

EQUITY INVESTMENTS

EQUITY INVESTMENTS	12 Months Ended
EQUITY INVESTMENTS	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	COASTAL GASLINK Impairment of Equity Investment in Coastal GasLink LP July 2022 Amended Coastal GasLink Agreements On July 28, 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 and required TC Energy to make a contractual equity contribution to Coastal GasLink LP in the amount of $1.9 billion, which did not result in a change in the Company’s 35 per cent ownership. Refer to Note 32, Variable interest entities, for additional information. The $1.9 billion contractual equity contribution was accrued and initially recognized in Equity investments on the Consolidated balance sheet at the time of signing the July 2022 agreements and is being paid in installments over the period August 2022 to February 2023. At December 31, 2022, $0.5 billion of this equity contribution remained in Accounts payable and other on the Consolidated balance sheet. Under the terms of the July 2022 agreements, any additional equity financing required by Coastal GasLink LP to fund construction of the pipeline beyond the $1.9 billion equity contribution will initially be financed through a subordinated loan agreement between TC Energy and Coastal GasLink LP. Any amounts outstanding on this loan will be repaid by Coastal GasLink LP to TC Energy, once final costs are known, which will be determined after the pipeline is placed in 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 but will not result in a change to the Company’s 35 per cent ownership. Capital Cost Update and Impairment In the fourth quarter of 2022, the Company announced that it expected a material increase in project costs and to the Company’s corresponding funding requirements. On February 1, 2023, TC Energy announced that the revised capital cost of the Coastal GasLink pipeline project was expected to be approximately $14.5 billion. While this estimate includes contingencies for certain factors that may be outside the control of Coastal GasLink LP, such as challenging conditions in the Western Canadian labour market, shortages of skilled labour, the impacts of contractor underperformance, as well as drought conditions and erosion and sediment control challenges, as with any complex construction project, the final capital cost is subject to certain risks and uncertainties. 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 determined that this was an other-than-temporary impairment of its equity investment in Coastal GasLink LP and a pre-tax impairment charge of $3,048 million ($2,643 million after tax) was recognized in fourth quarter 2022 in Impairment of equity investment in the Consolidated statement of income in the Canadian Natural Gas Pipelines segment. The pre-impairment carrying value of the investment in Coastal GasLink LP at December 31, 2022 consisted of amounts in Equity investments ($2,798 million) and Loans receivable from affiliates ($250 million), which were reduced to a nil balance. TC Energy expects to fund an additional $3.3 billion related to the revised estimated capital cost to complete the Coastal GasLink pipeline, and a significant portion of the Company’s future investment in Coastal GasLink LP is expected to be impaired. The Company will continue to assess for other-than-temporary declines in the fair value of this investment, and the extent of any future impairment charges will depend on the outcome of the valuation assessment performed at the respective reporting date. The fair value of TC Energy’s investment in Coastal GasLink LP at December 31, 2022 was estimated using a 40-year discounted cash flow model. Cash inflows in the model were estimated using contractually agreed upon terms and extension provisions in the TSAs between Coastal GasLink LP and the LNG Canada participants. For cash outflows in the model, the increase in estimated capital cost and the Company’s corresponding funding requirements have the most significant impact on the determination of the fair value of TC Energy's investment in Coastal GasLink LP. The cash flow analysis included a capital cost estimate for the Coastal GasLink pipeline of $14.5 billion. Any change from this capital cost estimate will have an approximate dollar-for-dollar impact on the Company’s future funding requirements, subject to any final cost sharing between the Coastal GasLink LP partners, and will impact the estimated fair value of, and the Company’s recovery of, its equity investment in Coastal GasLink LP in future periods. Other assumptions included in the discounted cash flow model include discount rate, long-term project financing plans and estimated completion date. Changes to these other assumptions would not reasonably expect to change the impairment recorded in the fourth quarter of 2022. A deferred income tax recovery was recognized on the pre-tax impairment charge, net of certain unrealized tax losses not recognized. Refer to Note 19, Income taxes, for additional information. 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, which is estimated to be $3.3 billion. As at December 31, 2022, the total capacity committed by TC Energy under this subordinated loan agreement was $1.3 billion. The committed capacity under this loan is expected to increase in the future as required to support additional financing requirements. Any amounts outstanding will be repaid by Coastal GasLink LP to TC Energy, once final costs are known, which will be determined after the pipeline is placed in 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, in accordance with the July 2022 agreements, these additional equity contributions will be predominantly funded by TC Energy but will not result in a change to the Company’s 35 per cent ownership. As noted above, the $250 million balance outstanding on this loan at December 31, 2022 was reduced to nil as part of the impairment charge recognized in fourth quarter 2022. The table below reflects the changes in this loan balance for the year ended December 31, 2022. (millions of Canadian $) Outstanding balance as at December 31, 2021 238 Issuances 1 112 Repayments 1 (100) Outstanding balance at December 31, 2022 250 Impairment (250) Carrying value at December 31, 2022 — 1 Presented on a net basis on the Company's Consolidated statement of cash flows. (millions of Canadian $) Ownership Interest at December 31, 2022 Income from Equity Equity year ended December 31 at December 31 2022 2021 2020 2022 2021 Canadian Natural Gas Pipelines TQM 1 50.0 % 17 12 12 165 118 Coastal GasLink 1 35.0 % 1 — — — 386 U.S. Natural Gas Pipelines Northern Border 50.0 % 92 80 100 516 505 Millennium 47.5 % 103 91 96 500 474 Iroquois 50.0 % 77 55 52 237 392 Other Various 20 18 16 122 137 Mexico Natural Gas Pipelines Sur de Texas 60.0 % 150 160 213 1,050 835 Liquids Pipelines Grand Rapids 1 50.0 % 54 54 53 964 980 Port Neches Link LLC 2 95.0 % — — — 149 103 HoustonLink Pipeline 1 50.0 % 1 1 — 19 18 Northern Courier 1,3 nil — 16 22 — — Power and Energy Solutions Bruce Power 1 48.3 % 537 411 439 5,783 4,493 Other Various 2 — 16 30 — 1,054 898 1,019 9,535 8,441 1 Classified as a non-consolidated VIE. Refer to Note 32, Variable interest entities, for additional information. 2 Classified as a non-consolidated VIE in 2021. Refer to Note 32, Variable interest entities, for additional information. 3 In November 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 30, Acquisitions and dispositions, for additional information. Impairment of Equity Investment On February 1, 2023, Coastal GasLink LP announced that the revised capital cost of the Coastal GasLink pipeline project is expected to be approximately $14.5 billion. The increase in the expected capital cost of the project caused TC Energy to re-evaluate its investment in Coastal GasLink LP, resulting in a pre-tax impairment charge of $3,048 million ($2,643 million after tax) recorded in fourth quarter 2022. Refer to Note 7, 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, 2022, 2021 and 2020 were as follows: year ended December 31 2022 2021 2020 (millions of Canadian $) Distributions Sur de Texas debt repayments 1,2 2,404 73 — Distributions received from operating activities of equity investments 1,025 975 1,123 Other 1 228 — — 3,657 1,048 1,123 Contributions Contributions to Coastal GasLink 1 1,414 92 101 Sur de Texas debt financing 1,2 1,199 — — Contributions made to other equity investments 1 820 1,118 664 3,433 1,210 765 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 12, Loans receivable from affiliates, for further information on 2022 refinancing activities with the Sur de Texas joint venture. Summarized Financial Information of Equity Investments year ended December 31 2022 2021 2020 (millions of Canadian $) Income Revenues 5,891 5,447 5,838 Operating and other expenses (3,390) (3,293) (3,341) Net income 2,147 1,859 2,047 Net income attributable to TC Energy 1,054 898 1,019 at December 31 2022 2021 (millions of Canadian $) Balance Sheet Current assets 3,414 3,498 Non-current assets 37,713 30,165 Current liabilities (2,856) (2,540) Non-current liabilities (17,690) (16,400) At December 31, 2022, the cumulative carrying value of the Company’s equity investments was $299 million lower than the cumulative underlying equity in the net assets primarily due to the 2022 impairment of the equity investment in Coastal GasLink LP, partially offset by fair value adjustments at the time of acquisition or partial monetization as well as interest capitalized during construction. Refer to Note 7, Coastal GasLink, for additional information. At December 31, 2021, the cumulative carrying value of the Company’s equity investments was $1,109 million higher than the cumulative underlying equity in the net assets primarily due to fair value adjustments at the time of acquisition or partial monetization as well as interest capitalized during construction.

LOANS RECEIVABLE FROM AFFILIATE

LOANS RECEIVABLE FROM AFFILIATES	12 Months Ended
LOANS RECEIVABLE FROM AFFILIATES	Dec. 31, 2022
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. 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 $) 2022 2021 2020 Interest income 1 19 87 110 Interest income and other Interest expense 2 (19) (87) (110) Income from equity investments Foreign exchange losses 1 (28) (41) (86) Foreign exchange loss/(gain), net Foreign exchange gains 1 28 41 86 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. 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 had a capacity of $100 million with an outstanding balance of nil at December 31, 2022 (2021 – $1 million) reflected in Loans receivable from affiliates under Current assets on the Company's Consolidated balance sheet. Subordinated Loan Agreement In 2021, TC Energy entered into a subordinated loan agreement with Coastal GasLink LP. This loan agreement was amended on July 28, 2022. Refer to Note 7, Coastal GasLink, for additional information.

RATE-REGULATED BUSINESSES

RATE-REGULATED BUSINESSES	12 Months Ended
RATE-REGULATED BUSINESSES	Dec. 31, 2022
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 continues to assess designated projects under the CER Act. The CER regulates the construction and operation of facilities and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems under federal jurisdiction. 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 regulators generally allow 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 currently operates under the terms of the 2020-2024 Revenue Requirement Settlement which includes an 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 between the NGTL System and its customers. Canadian Mainline The Canadian Mainline currently operates under the terms of the 2015-2030 Tolls Application approved in 2014 (the 2014 Decision). The terms in the 2015-2020 six-year settlement of the 2014 Decision, which ended December 31, 2020, included an ROE of 10.1 per cent on 40 per cent deemed common equity, an incentive mechanism that had both upside and downside risk and a $20 million after-tax annual TC Energy contribution to reduce the revenue requirement. Toll stabilization was achieved through the use of deferral accounts, namely the bridging amortization account and the long-term adjustment account (LTAA), to capture the surplus or shortfall between the Company's revenues and cost of service for each year over the 2015-2020 six-year fixed-toll term of the 2014 Decision. The 2014 Decision also directed TC Energy to file an application to review tolls for the 2018-2020 period. In December 2018, a decision was received on the 2018-2020 Tolls Review which included an accelerated amortization of the December 31, 2017 LTAA balance and an increase to the composite depreciation rate from 3.2 per cent to 3.9 per cent. In April 2020, the CER approved the six-year unanimous negotiated settlement (2021-2026 Mainline Settlement) effective January 1, 2021. Similar to the previous settlement, the 2021-2026 Mainline Settlement maintains a base equity return of 10.1 per cent on 40 per cent deemed common equity and includes an incentive to either achieve cost efficiencies and/or increase revenues on the pipeline with a beneficial sharing mechanism to both the shippers and TC Energy. An estimate of the remaining LTAA balance at the end of 2020 was included as an adjustment in the calculation of Mainline fixed tolls and amortized over the settlement term. Similar to the LTAA, the short-term adjustment accounts (STAA) captures the surplus or shortfall between system revenues and cost of service each year under the 2021-2026 Mainline Settlement and the Company will commence amortization over the remaining settlement term when predetermined thresholds per the settlement agreement are met. U.S. Regulated Operations TC Energy's U.S. regulated natural gas pipelines operate under the provisions of the Natural Gas Act (NGA) of 1938, 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 on February 25, 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, on January 28, 2022, ANR Pipeline filed a Section 4 Rate Case with FERC requesting an increase to maximum transportation rates. On December 14, 2022 ANR Pipeline filed a Stipulation and Agreement of Settlement (ANR Settlement) with FERC. The ANR Settlement reflects the agreement of ANR Pipeline and its shippers and FERC staff to resolve all outstanding issues pertaining to the original rate case filing on January 28, 2022. The ANR Settlement was uncontested and is currently awaiting final FERC approval which is expected in early 2023. Columbia Gulf Columbia Gulf reached a rate settlement with its customers, which was approved by FERC in December 2019, increasing Columbia Gulf’s recourse rates which took effect on August 1, 2020. This settlement established a rate case and tariff filing moratorium, which expired on August 1, 2022, and Columbia Gulf is required to file a general rate case under Section 4 of the NGA no later than January 31, 2027, with new rates to be effective August 1, 2027. 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. On March 18, 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 1, 2022. The 2022 Great Lakes Settlement, approved by FERC on April 26, 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 1, 2019. Under the terms of this settlement, Tuscarora is 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 on July 29, 2022, requesting an increase to its maximum rates effective February 1, 2023, 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 2022 2021 Remaining Recovery/ Settlement Period (years) (millions of Canadian $) Regulatory Assets Deferred income taxes 1 1,817 1,509 n/a Pensions and other post-retirement benefits 1,2 28 203 n/a Foreign exchange on long-term debt 1,3 19 3 1-7 Operating and debt-service regulatory assets 4 2 1 1 Other 111 104 n/a 1,977 1,820 Less: Current portion included in Other current assets (Note 8) 67 53 1,910 1,767 Regulatory Liabilities Pipeline abandonment trust balances 5 2,014 2,086 n/a Deferred income taxes – U.S. Tax Reform 6 1,197 1,141 n/a Canadian Mainline bridging amortization account 7 429 483 8 Cost of removal 8 337 254 n/a Canadian Mainline short-term adjustment and toll-stabilization accounts 7,9 284 60 n/a Canadian Mainline long-term adjustment account 7,10 149 186 4 Deferred income taxes 1 181 139 n/a Operating and debt-service regulatory liabilities 4 50 32 1 ANR post-employment and retirement benefits other than pension 11 43 40 n/a Pensions and other post-retirement benefits 2 10 13 n/a Other 99 66 n/a 4,793 4,500 Less: Current portion included in Accounts payable and other (Note 17) 273 200 4,520 4,300 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 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. 3 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. 4 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. 5 This balance represents the amounts collected in tolls from shippers 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 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. 9 Under the terms of the 2021-2026 Mainline Settlement, the STAA account will commence amortization when predetermined thresholds are met, over the term outlined per the settlement agreement. 10 Under the terms of the 2021-2026 Mainline Settlement, $223 million is amortized over the six-year settlement term.

GOODWILL

GOODWILL	12 Months Ended
GOODWILL	Dec. 31, 2022
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 2022 2021 (millions) Canadian US Canadian dollars US Columbia Pipeline Group, Inc. 9,948 7,351 9,303 7,351 ANR 2,634 1,946 2,464 1,946 Great Lakes 165 122 725 573 North Baja 65 48 61 48 Tuscarora 31 23 29 23 12,843 9,490 12,582 9,941 Changes in Goodwill were as follows: (millions of Canadian $) U.S. Natural Balance at January 1, 2021 12,679 Foreign exchange rate changes (97) Balance at December 31, 2021 1 12,582 Great Lakes impairment charge (571) Foreign exchange rate changes 832 Balance at December 31, 2022 1 12,843 1 Represents gross amount of goodwill as at December 31, 2022 of $14,578 million (2021 – $13,746 million), net of accumulated impairment of $1,735 million (2021 – $1,164 million). As part of the annual goodwill impairment assessment at December 31, 2022, the Company evaluated qualitative factors impacting the fair value of the underlying reporting units for all reporting units other than the ANR reporting unit. It was determined that it was more likely than not that the fair value of these reporting units exceeded their carrying amounts, including goodwill. ANR The Company elected to proceed directly to a quantitative annual impairment test at December 31, 2022 for the $2,634 million (US$1,946 million) of goodwill related to the ANR reporting unit following the passage of time from the previous test at December 31, 2016, and subsequent to the ANR settlement-in-principle in 2022. It was determined that the fair value of ANR exceeded its carrying value, including goodwill at December 31, 2022. Great Lakes During first quarter 2022, TC Energy elected to pursue an unanticipated opportunity to extend the existing recourse rates on Great Lakes. This prompted the Company to re-evaluate the impact of maintaining recourse rates at the current level as opposed to moving forward with the previously presumed Great Lakes rate case process in 2022. On March 18, 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. While the settlement created short-term rate certainty, it prompted a re-evaluation of Great Lakes’ long-term free cash flows. With recourse rates maintained at the current level for the next three years, the expectation of increased contracting, growth and other near-term commercial and regulatory opportunities were negatively impacted. Management performed a quantitative impairment test that evaluated a range of assumptions through a discounted cash flow 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) 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 is US$122 million at December 31, 2022 (December 31, 2021 – US$573 million). 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 Company elected to allocate the goodwill impairment charge first to goodwill that is non-deductible for income tax purposes, with any remaining charge allocated to tax-deductible goodwill. 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. 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
OTHER LONG-TERM ASSETS	Dec. 31, 2022
Intangible Assets, Net (Excluding Goodwill) [Abstract]
OTHER LONG-TERM ASSETS	OTHER LONG-TERM ASSETS at December 31 2022 2021 (millions of Canadian $) Deferred income tax assets (Note 19) 1,070 509 Employee post-retirement benefits (Note 27) 563 312 Long-term contract assets (Note 5) 355 249 Keystone environmental provision recovery (Note 17) 240 — Capital projects in development 99 42 Fair value of derivative contracts (Note 28) 91 48 Keystone XL contractual recoveries (Note 6) 44 50 Other 323 193 2,785 1,403

NOTES PAYABLE

NOTES PAYABLE	12 Months Ended
NOTES PAYABLE	Dec. 31, 2022
Short-Term Debt [Abstract]
NOTES PAYABLE	NOTES PAYABLE 2022 2021 (millions of Canadian $, unless otherwise noted) Outstanding at December 31 Weighted Outstanding at December 31 Weighted Canada 1 5,971 4.9 % 4,953 0.4 % U.S. (2022 – nil; 2021 – US$54) — — 68 0.3 % Mexico (2022 – US$215; 2021 – US$115) 2 291 6.0 % 145 1.7 % 6,262 5,166 1 At December 31, 2022, Notes payable consisted of Canadian dollar-denominated notes of $2,810 million (2021 – $1,989 million) and U.S. dollar-denominated notes of US$2,336 million (2021 – US$2,341 million). 2 The demand senior unsecured revolving credit facility for the Company's Mexico subsidiary can be drawn in either Mexican pesos or U.S. dollars, up to the total facility amount of MXN$5.0 billion or the U.S. dollar equivalent. On November 22, 2022, TransCanada PipeLines Limited (TCPL) entered into a 364-day $1.5 billion senior unsecured term loan bearing interest at a floating rate. At December 31, 2022 and 2021, Notes payable reflects short-term borrowings in Canada by TCPL, in the U.S. by TransCanada PipeLine USA Ltd. (TCPL USA) and in Mexico by a wholly-owned Mexican subsidiary. At December 31, 2022, total committed revolving and demand credit facilities were $12.9 billion (2021 – $12.4 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) 2022 2021 Borrowers Description Matures Total Facilities Unused Capacity 1 Total Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities 2 : TCPL Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes December 2027 3.0 1.7 3.0 TCPL / TCPL USA / Columbia / TransCanada American Investments Ltd. Supports TCPL's and TCPL USA's U.S. dollar commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL December 2023 US 3.0 US 0.6 US 4.5 TCPL / TCPL USA / Columbia / TransCanada American Investments Ltd. Supports TCPL's and TCPL USA's U.S. dollar commercial paper programs and for general and corporate purposes of the borrowers, guaranteed by TCPL December 2025 US 2.5 US 2.5 US 1.0 Demand senior unsecured revolving credit facilities 2 : TCPL / TCPL USA Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL Demand 2.1 3 1.0 2.1 3 Mexico subsidiary For Mexico general corporate purposes, guaranteed by TCPL Demand MXN 5.0 3 MXN 0.8 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, 2022, the Company was in compliance with all financial covenants. 3 Or the U.S. dollar equivalent. For the year ended December 31, 2022, the cost to maintain the above facilities was $14 million (2021 – $17 million; 2020 – $21 million).

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
ACCOUNTS PAYABLE AND OTHER	Dec. 31, 2022
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER at December 31 2022 2021 (millions of Canadian $) Trade payables 4,330 4,183 Fair value of derivative contracts (Note 28) 871 221 Keystone environmental provision 650 — Coastal GasLink contractual contribution (Notes 7, 11 and 32) 537 — Regulatory liabilities (Note 13) 273 200 Contract liabilities (Note 5) 62 90 Class C Interests (Note 6) 37 75 Other 389 330 7,149 5,099 Keystone Environmental Provision In December 2022, a pipeline rupture occurred in Washington County, Kansas on the Cushing Extension section of the Keystone Pipeline System. At December 31, 2022, the Company accrued an environmental remediation liability of $650 million, before expected insurance recoveries, and not including potential fines and penalties which are currently indeterminable. This amount represents the Company’s estimate of costs relating to emergency response, environmental remediation and cleanup activities required to fully remediate the site and has been recorded on an undiscounted basis. The accrual is based on certain assumptions such as the scope of remediation efforts that are subject to revision in future periods which could result in future modifications of this accrual. Therefore, it is reasonably possible that the Company will incur additional costs beyond the amounts accrued. TC Energy has accrued the minimum estimated cost of environmental remediation; however, the Company is currently unable to estimate a maximum range of possible costs. TC Energy has appropriate insurance policies in place and it is probable that the majority of estimated environmental remediation costs will be eligible for recovery under the Company’s existing insurance coverage. The Company has recorded an asset of $410 million in Other current assets and $240 million in Other long-term assets, representing the expected recovery of the estimated environmental remediation costs. Estimated insured amounts expected to be recovered from insurers are presented in the same income statement line as the environmental remediation costs. To the extent costs beyond the amounts accrued are incurred, they will be evaluated under the Company’s existing insurance policies. The Company expects remediation activities to be substantially completed within a year.

OTHER LONG-TERM LIABILITIES

OTHER LONG-TERM LIABILITIES	12 Months Ended
OTHER LONG-TERM LIABILITIES	Dec. 31, 2022
Deferred Costs, Noncurrent [Abstract]
OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES at December 31 2022 2021 (millions of Canadian $) Operating lease obligations (Note 10) 379 380 Fair value of derivative contracts (Note 28) 151 47 Employee post-retirement benefits (Note 27) 111 174 Asset retirement obligations 79 61 Long-term contract liabilities (Note 5) 32 184 Other 265 213 1,017 1,059

INCOME TAXES

INCOME TAXES	12 Months Ended
INCOME TAXES	Dec. 31, 2022
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Geographic Components of Income before Income Taxes year ended December 31 2022 2021 2020 (millions of Canadian $) Canada (2,154) (292) 691 Foreign 3,528 2,458 4,416 Income before Income Taxes 1,374 2,166 5,107 Provision for Income Taxes year ended December 31 2022 2021 2020 (millions of Canadian $) Current Canada 43 29 (54) Foreign 372 276 306 415 305 252 Deferred Canada (467) (327) (224) Foreign 641 142 166 174 (185) (58) Income Tax Expense 589 120 194 Reconciliation of Income Tax Expense year ended December 31 2022 2021 2020 (millions of Canadian $) Income before income taxes 1,374 2,166 5,107 Federal and provincial statutory tax rate 23.0 % 23.0 % 24.0 % Expected income tax expense 316 498 1,226 Foreign income tax rate differentials (271) (230) (258) Income tax differential related to regulated operations (174) (139) (228) Income from non-controlling interests and equity investments (54) (70) (141) Valuation allowance/(releases) 199 (8) (400) Non-taxable capital (gains) and losses 173 — (62) Settlement of Mexico prior years' income tax assessments 196 — — U.S. minimum tax 96 — — Non-deductible goodwill impairment 91 — — Impact of Mexico inflationary adjustments 24 32 7 Other (7) 37 50 Income Tax Expense 589 120 194 Deferred Income Tax Assets and Liabilities at December 31 2022 2021 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,519 1,163 Regulatory and other deferred amounts 571 537 Unrealized foreign exchange losses on long-term debt 333 130 Other 193 46 2,616 1,876 Less: Valuation allowance 640 229 1,976 1,647 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment 6,686 5,616 Equity investments 1,152 1,219 Taxes on future revenue requirement 397 333 Financial instruments 126 — Other 193 112 8,554 7,280 Net Deferred Income Tax Liabilities 6,578 5,633 The above deferred tax amounts have been classified on the Consolidated balance sheet as follows: at December 31 2022 2021 (millions of Canadian $) Deferred Income Tax Assets Other long-term assets (Note 15) 1,070 509 Deferred Income Tax Liabilities Deferred income tax liabilities 7,648 6,142 Net Deferred Income Tax Liabilities 6,578 5,633 At December 31, 2022, the Company has recognized the benefit of non-capital loss carryforwards of $5,429 million (2021 – $4,067 million) for federal and provincial purposes in Canada, which expire from 2030 to 2042. The Company has not yet recognized the benefit of capital loss carryforwards of $251 million (2021 – $21 million) for federal and provincial purposes in Canada which have no expiry date. The Company also has Ontario corporate minimum tax (CMT) credits of $126 million (2021 – $113 million), which expire from 2026 to 2042. As of December 31, 2022, the Company has not recognized the benefit of CMT credits of $22 million (2021 – nil). At December 31, 2022, the Company has fully utilized the benefit of net operating loss carryforwards (2021 – US$446 million) for federal purposes in the U.S. At December 31, 2022, the Company has recognized the benefit of net operating loss carryforwards of US$69 million (2021 – US$10 million) in Mexico, which expire from 2024 to 2032. TC Energy recorded an income tax valuation allowance of $640 million and $229 million against the deferred income tax asset balances at December 31, 2022 and 2021, respectively. The increase in the valuation allowance is primarily a result of the foreign exchange movement on unrecognized capital losses and the unrealized capital losses on the Coastal GasLink equity investment. At December 31, 2022, the Company recorded $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, 2022. 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, 2022, the Company determined there was sufficient positive evidence to conclude that it is more likely than not that the net deferred tax assets will be realized. At December 31, 2020, the Company recorded $400 million in valuation allowance releases primarily a result of the final investment decision to proceed with the construction of the Keystone XL pipeline, the sale of the Ontario natural gas-fired power plants and the sale of a 65 per cent equity interest in Coastal GasLink LP. Refer to Note 30, Acquisitions and dispositions, for additional information on the sale of the Ontario natural gas-fired power plants and Coastal GasLink LP equity sale. 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, 2022 by approximately $1,216 million (2021 – $896 million) if there had been a provision for these taxes. Income Tax Payments Income tax payments of $394 million, net of refunds, were made in 2022 (2021 – payments, net of refunds, of $371 million; 2020 – payments, net of refunds, of $252 million). Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2022 2021 2020 (millions of Canadian $) Unrecognized tax benefit at beginning of year 80 52 29 Gross increases – tax positions in prior years 6 5 26 Gross decreases – tax positions in prior years — (1) (2) Gross increases – tax positions in current year 7 26 1 Lapse of statutes of limitations (2) (2) (2) Unrecognized Tax Benefit at End of Year 91 80 52 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, 2022 reflects $6 million interest expense (2021 – $1 million; 2020 – $4 million). At December 31, 2022, the Company had accrued $18 million in interest expense (2021 – $12 million; 2020 – $11 million). The Company incurred no penalties associated with income tax uncertainties related to Income tax expense for the years ended December 31, 2022, 2021 and 2020 and no penalties were accrued as at December 31, 2022, 2021 and 2020. 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 2014. 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 2014, except as further described below. 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
LONG-TERM DEBT	Dec. 31, 2022
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Outstanding amounts 2022 2021 Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Medium Term Notes Canadian 2023 to 2052 13,966 4.5 % 12,491 4.2 % Senior Unsecured Notes U.S. (2022 – US$15,542; 2021 – US$16,542) 2023 to 2049 21,032 4.9 % 20,936 4.8 % 34,998 33,427 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2022 and 2021 – US$200) 2023 271 7.9 % 254 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2022 and 2021 – US$33) 2026 44 7.5 % 41 7.5 % 919 899 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes 2 U.S. (2022 and 2021 – US$1,500) 2025 to 2045 2,030 4.9 % 1,898 4.9 % ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2022 – US$1,172; 2021 – US$372) 2024 to 2037 1,587 4.1 % 472 5.3 % TC PIPELINES, LP Senior Unsecured Notes U.S. (2022 and 2021 – US$850) 2025 to 2027 1,150 4.2 % 1,076 4.2 % GAS TRANSMISSION NORTHWEST LLC Senior Unsecured Notes U.S. (2022 and 2021 – US$325) 2030 to 2035 440 4.3 % 411 4.3 % Outstanding amounts 2022 2021 Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Unsecured Notes U.S. (2022 and 2021 – US$250 ) 2030 to 2031 338 2.8 % 316 2.8 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2022 – US$146; 2021 – US$167) 2028 to 2030 198 7.6 % 211 7.6 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2022 – US$34; 2021 – US$36) 2024 46 6.5 % 46 1.3 % 41,706 38,756 Current portion of long-term debt (1,898) (1,320) Unamortized debt discount and issue costs (239) (243) Fair value adjustments 3 76 148 39,645 37,341 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 Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia's obligations is required to comply with covenants under the debt indenture and, in the event of default, the guarantors would be obligated to pay the principal and related interest. 3 The fair value adjustments include $140 million (2021 – $148 million) related to the acquisition of Columbia Pipeline Group, Inc. These adjustments also include a decrease of $64 million (2021 – nil) related to hedged interest rate risk. Refer to Note 28, Risk management and financial instruments for additional information. Principal Repayments At December 31, 2022, principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2023 2024 2025 2026 2027 Principal repayments on long-term debt 1,898 2,782 2,827 2,278 3,113 Long-Term Debt Issued The Company issued long-term debt over the three years ended December 31, 2022 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED 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 % 1 April 2020 Senior Unsecured Notes April 2030 US 1,250 4.10 % April 2020 Medium Term Notes April 2027 2,000 3.80 % 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 % October 2020 Senior Unsecured Notes October 2030 US 125 2.84 % TUSCARORA GAS TRANSMISSION COMPANY August 2021 Unsecured Term Loan August 2024 US 13 Floating KEYSTONE XL SUBSIDIARIES 2 Various Project-Level Credit Facility June 2021 US 849 Floating COLUMBIA PIPELINE GROUP, INC. 3 January 2021 Unsecured Term Loan June 2022 US 4,040 Floating GAS TRANSMISSION NORTHWEST LLC June 2020 Senior Unsecured Notes June 2030 US 175 3.12 % COASTAL GASLINK PIPELINE LIMITED PARTNERSHIP 4 April 2020 Senior Secured Credit Facilities April 2027 1,603 Floating 1 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 4.186 per cent. 2 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 6, Keystone XL, for additional information. 3 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. 4 In April 2020, Coastal GasLink LP entered into secured long-term project financing credit facilities. In May 2020, TC Energy completed the sale of a 65 per cent equity interest in Coastal GasLink LP and subsequently accounts for its remaining 35 per cent interest using the equity method. Immediately preceding the equity sale, Coastal GasLink LP made an initial draw of $1.6 billion on the credit facilities, of which approximately $1.5 billion was paid to TC Energy. Refer to Note 30, Acquisitions and dispositions, for additional information. Long-Term Debt Retired/Repaid The Company retired/repaid long-term debt over the three years ended December 31, 2022 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED 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 9.875 % November 2020 Debentures 250 11.80 % October 2020 Senior Unsecured Notes US 1,000 3.80 % March 2020 1 Senior Unsecured Notes US 750 4.60 % COLUMBIA PIPELINE GROUP, INC. December 2021 Unsecured Term Loan 2 US 4,040 Floating June 2020 Senior Unsecured Notes US 750 3.30 % 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 9.625 % 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 October 2020 Unsecured Loan Facility US 99 Floating KEYSTONE XL SUBSIDIARIES 3 June 2021 Project-Level Credit Facility US 849 Floating GAS TRANSMISSION NORTHWEST LLC June 2020 Senior Unsecured Notes US 100 5.29 % 1 Related unamortized debt issue costs of $8 million were included in Interest expense in the Consolidated statement of income for the year ended December 31, 2020. 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 6, 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 2022 2021 2020 (millions of Canadian $) Interest on long-term debt 1,883 1,841 1,963 Interest on junior subordinated notes 543 453 470 Interest on short-term debt 153 10 46 Capitalized interest (27) (22) (294) Amortization and other financial charges 1 36 78 43 2,588 2,360 2,228 1 Amortization and other financial charges includes 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 $2,478 million in 2022 (2021 – $2,299 million; 2020 – $2,203 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
JUNIOR SUBORDINATED NOTES	Dec. 31, 2022
Junior Subordinated Notes [Abstract]
JUNIOR SUBORDINATED NOTES	JUNIOR SUBORDINATED NOTES 2022 2021 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate 1 Outstanding at December 31 Effective Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED US$1,000 notes issued 2007 at 6.35% 2 2067 1,353 6.2 % 1,265 4.0 % US$750 notes issued 2015 at 5.875% 3,4 2075 1,015 7.4 % 949 5.0 % US$1,200 notes issued 2016 at 6.125% 3,4 2076 1,624 8.0 % 1,519 5.8 % US$1,500 notes issued 2017 at 5.55% 3,4 2077 2,030 7.1 % 1,899 4.7 % $1,500 notes issued 2017 at 4.90% 3,4 2077 1,500 6.8 % 1,500 4.5 % US$1,100 notes issued 2019 at 5.75% 3,4 2079 1,488 7.6 % 1,392 5.4 % $500 notes issued 2021 at 4.45% 3,5 2081 500 5.7 % 500 4.0 % US$800 notes issued 2022 at 5.85% 3,5 2082 1,083 7.2 % — — 10,593 9,024 Unamortized debt discount and issue costs (98) (85) 10,495 8,939 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 billion were issued in 2007 at a fixed rate of 6.35 per cent and converted in 2017 to a floating interest rate that is reset quarterly to the three-month LIBOR plus 2.21 per cent. 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.

FOREIGN EXCHANGE LOSS_(GAIN), N

FOREIGN EXCHANGE LOSS/(GAIN), NET	12 Months Ended
FOREIGN EXCHANGE LOSS/(GAIN), NET	Dec. 31, 2022
Foreign Currency [Abstract]
FOREIGN EXCHANGE LOSS/(GAIN), NET	FOREIGN EXCHANGE LOSS/(GAIN), NET year ended December 31 2022 2021 2020 (millions of Canadian $) Derivative instruments held for trading (Note 28) 151 (37) (93) Other 34 27 65 185 (10) (28)

NON-CONTROLLING INTERESTS

NON-CONTROLLING INTERESTS	12 Months Ended
NON-CONTROLLING INTERESTS	Dec. 31, 2022
Noncontrolling Interest [Abstract]
NON-CONTROLLING INTERESTS	NON-CONTROLLING INTERESTS TC PipeLines, LP Acquisition In December 2020, the Company entered into a definitive agreement and plan of merger to acquire 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. Upon close of the transaction on March 3, 2021, 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 loss 353 Non-controlling interests (1,563) Deferred income tax liabilities (443) Other (12) Non-controlling interests Prior to the March 3, 2021 acquisition described above, the non-controlling interests in TC PipeLines, LP were 74.5 per cent (2020 – 74.5 per cent). Subsequent to this acquisition, the remaining non-controlling interest on the Consolidated balance sheet is related to the Company's 61.7 per cent investment in Portland Natural Gas Transmission System (PNGTS), which is held by TC PipeLines, LP. The Company's Net income attributable to non-controlling interests included in the Consolidated statement of income were as follows: year ended December 31 2022 2021 2020 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP — 60 284 Non-controlling interest in PNGTS 37 30 23 Redeemable non-controlling interest (Note 6) — 1 (10) 37 91 297

COMMON SHARES

COMMON SHARES	12 Months Ended
COMMON SHARES	Dec. 31, 2022
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, 2020 938,400 24,387 Exercise of options 1,664 101 Outstanding at December 31, 2020 940,064 24,488 Acquisition of TC PipeLines, LP, net of transaction costs (Note 23) 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 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. Commencing with the dividends declared on July 27, 2022, the Company reinstated the issuance of common shares from treasury at a two per cent discount. For dividends declared between January 1, 2020 and July 27, 2022, common shares purchased with reinvested cash dividends under the DRP were 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 23, Non-controlling interests, for additional information. TC Energy Corporation At-the-Market Equity Issuance Program In December 2020, the Company established an At-the-Market (ATM) program that allowed, from time to time, for the issuance of common shares from treasury at the prevailing market price when sold through the Toronto Stock Exchange, the New York Stock Exchange or any other existing trading market for TC Energy common shares in Canada or the United States. The ATM program was effective for a 25-month period to assist in managing the Company's capital structure. Under this program, the Company had the ability to issue up to $1.0 billion in common shares or the U.S. dollar equivalent. In January 2023, the ATM program expired with no common shares issued thereunder. Basic and Diluted Net Income per Common Share Net income per common share is calculated by dividing Net income 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, subsequent to July 27, 2022, common shares issuable from treasury under the DRP. Weighted Average Common Shares Outstanding (millions) 2022 2021 2020 Basic 995 973 940 Diluted 996 974 940 Stock Options Number of Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (thousands) (years) Options outstanding at January 1, 2022 7,769 $61.29 Options granted 1,396 $66.49 Options exercised (2,830) $58.09 Options forfeited/expired (226) $63.96 Options Outstanding at December 31, 2022 6,109 $63.86 4.4 Options Exercisable at December 31, 2022 3,175 $63.13 3.4 At December 31, 2022, an additional 3,656,518 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 2022 2021 2020 Weighted average fair value $8.24 $7.39 $7.73 Expected life (years) 1 5.4 5.4 5.7 Interest rate 1.6 % 0.5 % 1.5 % Volatility 2 22 % 25 % 17 % Dividend yield 5.5 % 6.0 % 4.2 % 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 $10 million in 2022 (2021 – $12 million; 2020 – $12 million). At December 31, 2022, 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 1.9 years. The following table summarizes additional stock option information: year ended December 31 2022 2021 2020 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 33 28 31 Total fair value of options that have vested 89 110 101 Total options vested 1.6 million 1.9 million 2.0 million As at December 31, 2022, the aggregate intrinsic values of the total options exercisable and the total options outstanding were each less than $1 million. 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
PREFERRED SHARES	Dec. 31, 2022
Preferred Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
PREFERRED SHARES	PREFERRED SHARES at December 31, 2022 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 2022 2021 2020 (thousands) (millions of Canadian $) Cumulative First Preferred Shares Series 1 14,577 3.479 % $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 1.694 % $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 1.949 % 5 $0.48725 $25.00 January 30, 2026 Series 6 294 294 310 Series 6 1,929 Floating 4 Floating $25.00 January 30, 2026 Series 5 48 48 32 Series 7 24,000 3.903 % $0.97575 $25.00 April 30, 2024 Series 8 589 589 589 Series 9 18,000 3.762 % $0.9405 $25.00 October 30, 2024 Series 10 442 442 442 Series 11 10,000 3.351 % $0.83775 $25.00 November 28, 2025 Series 12 244 244 244 Series 13 — — — — — — — — 493 Series 15 — — — — — — — 988 988 2,499 3,487 3,980 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 6.053 per cent for the period starting December 30, 2022 to, but excluding, March 31, 2023. The floating quarterly dividend rate for the Series 4 preferred shares is 5.413 per cent for the period starting December 30, 2022 to, but excluding, March 31, 2023. The floating quarterly dividend rate for the Series 6 preferred shares is 5.192 per cent for the period starting October 30, 2022 to, but excluding, January 30, 2023. These rates will reset each quarter going forward. 5 The fixed rate dividend for Series 5 preferred shares decreased from 2.263 per cent to 1.949 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. In February 2021, 818,876 Series 5 preferred shares were converted, on a one-for-one basis, into Series 6 preferred shares and 175,208 Series 6 preferred shares were converted, on a one-for-one basis, into Series 5 preferred shares. In June 2020, 401,590 Series 3 preferred shares were converted, on a one-for-one basis, into Series 4 preferred shares and 1,865,362 Series 4 preferred shares were converted, on a one-for-one basis, into Series 3 preferred shares.

OTHER COMPREHENSIVE INCOME _ (L

OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	12 Months Ended
	Dec. 31, 2022
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, 2022 Before Tax Amount Income Tax Recovery/(Expense) 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 and losses on cash flow hedges 63 (21) 42 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 81 (18) 63 Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans 9 (3) 6 Other comprehensive income on equity investments 1,156 (289) 867 Other Comprehensive Income 2,613 (216) 2,397 year ended December 31, 2021 Before Tax Amount Income Tax Recovery/(Expense) 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 and losses on cash flow hedges 68 (13) 55 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 208 (50) 158 Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans 20 (6) 14 Other comprehensive income on equity investments 714 (179) 535 Other Comprehensive Income 894 (252) 642 year ended December 31, 2020 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations (647) 38 (609) Change in fair value of net investment hedges 48 (12) 36 Change in fair value of cash flow hedges (771) 188 (583) Reclassification to net income of gains and losses on cash flow hedges 649 (160) 489 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 15 (3) 12 Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans 23 (6) 17 Other comprehensive loss on equity investments (373) 93 (280) Other Comprehensive Loss (1,056) 138 (918) The changes in AOCI by component were as follows: (millions of Canadian $) Currency Cash Flow Pension and Other Post-Retirement Benefit Plan Adjustments Equity Investments Total 1 AOCI balance at January 1, 2020 (730) (58) (314) (457) (1,559) Other comprehensive (loss)/income before reclassifications 2 (543) (567) 12 (292) (1,390) Amounts reclassified from AOCI — 482 17 11 510 Net current period other comprehensive (loss)/income (543) (85) 29 (281) (880) AOCI balance at December 31, 2020 (1,273) (143) (285) (738) (2,439) Other comprehensive (loss)/income before reclassifications 2 (98) (11) 158 506 555 Amounts reclassified from AOCI — 55 14 28 97 Net current period other comprehensive (loss)/income (98) 44 172 534 652 Acquisition of TC PipeLines, LP 3 362 (13) — 4 353 AOCI balance at December 31, 2021 (1,009) (112) (113) (200) (1,434) Other comprehensive income/(loss) before reclassifications 2 1,450 (39) 63 870 2,344 Amounts reclassified from AOCI 4 — 42 6 (3) 45 Net current period other comprehensive income 1,450 3 69 867 2,389 AOCI balance at December 31, 2022 441 (109) (44) 667 955 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 Other comprehensive income/(loss) before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling interest gains of $8 million (2021 – losses of $12 million; 2020 – losses of $30 million), nil (2021 – gains of $1 million; 2020 – losses of $16 million), and nil (2021 – gains of $1 million; 2020 – gains of $1 million ), respectively. 3 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 23, Non-controlling interests, for additional information. 4 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 $84 million ($64 million, net of tax) at December 31, 2022. 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. 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 2022 2021 2020 (millions of Canadian $) Cash flow hedges Commodities (47) (22) (1) Revenues (Power and Energy Solutions) Interest rate (16) (46) (28) Interest expense Interest rate — — (613) Net gain/(loss) on sale of assets 2 (63) (68) (642) Total before tax 21 13 160 Income tax expense (42) (55) (482) Net of tax 3 Pension and other post-retirement benefit plan adjustments Amortization of actuarial losses (11) (22) (23) Plant operating costs and other 4 Settlement gain 2 2 — Plant operating costs and other 4 (9) (20) (23) Total before tax 3 6 6 Income tax expense (6) (14) (17) Net of tax Equity investments Equity income 4 (37) (15) Income from equity investments (1) 9 4 Income tax expense 3 (28) (11) Net of tax 1 Amounts in parentheses indicate expenses to the Consolidated statement of income. 2 Represents a loss of $613 million ($459 million, net of tax) related to a contractually required derivative instrument used to hedge the interest rate risk associated with project-level financing of the Coastal GasLink construction. The derivative instrument was derecognized as part of the sale of a 65 per cent equity interest in Coastal GasLink LP. Refer to Note 30, Acquisitions and dispositions, for additional information. 3 Amounts reclassified from AOCI on cash flow hedges are net of non-controlling interest of nil (2021 – nil; 2020 – losses of $7 million). 4 These AOCI components are included in the computation of net benefit cost. Refer to Note 27, Employee post-retirement benefits, for additional information.

EMPLOYEE POST-RETIREMENT BENEFI

EMPLOYEE POST-RETIREMENT BENEFITS	12 Months Ended
EMPLOYEE POST-RETIREMENT BENEFITS	Dec. 31, 2022
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 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, 2022 (2021 and 2020 – 11 years). In 2022, the Company expensed $64 million (2021 and 2020 – $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 2022 2021 2020 (millions of Canadian $) DB Plans 78 105 124 Other post-retirement benefit plans 8 8 9 Savings and DC Plans 64 58 58 150 171 191 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. After the cash contributions noted above, no additional letters of credit were provided to the Canadian DB Plan in 2022 (2021 – $20 million; 2020 – $13 million). Total letters of credit provided to the Canadian DB plan at December 31, 2022 was $322 million. The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2022 and the next required valuation is at January 1, 2023. 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. other post-retirement benefits plan (OPEB). The impact of these amounts were 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's unrealized actuarial gain by $3 million which was included in OCI and increased the OPEB obligation by $3 million, resulting in no adjustment to net benefit cost in 2021. The Company's funded status at December 31 was comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2022 2021 2022 2021 Change in Benefit Obligation 1 Benefit obligation – beginning of year 4,027 4,326 419 457 Service cost 145 171 5 6 Interest cost 125 119 13 12 Employee contributions 6 6 2 1 Benefits paid (324) (372) (24) (21) Actuarial gain (949) (208) (120) (35) Curtailment — (5) — 3 Foreign exchange rate changes 51 (10) 15 (4) Benefit obligation – end of year 3,081 4,027 310 419 Change in Plan Assets Plan assets at fair value – beginning of year 4,145 4,038 431 441 Actual return on plan assets (483) 376 (89) 5 Employer contributions 2 78 105 8 8 Employee contributions 6 6 2 1 Benefits paid (324) (372) (24) (21) Foreign exchange rate changes 59 (8) 26 (3) Plan assets at fair value – end of year 3,481 4,145 354 431 Funded Status – Plan Surplus 400 118 44 12 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 Excludes a nil (2021 – $20 million) letter of credit provided to the Canadian DB Plan for funding purposes. The actuarial gain realized on the defined benefit plan obligation is primarily attributable to an increase in the weighted average discount rate from 3.05 per cent in 2021 to 5.15 per cent in 2022. The actuarial gain realized on the other post-retirement benefit plan obligation is primarily due to the increase in the weighted average discount rate from 3.10 per cent in 2021 to 5.45 per cent in 2022. 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 $) 2022 2021 2022 2021 Other long-term assets (Note 15) 400 119 163 193 Accounts payable and other — — (8) (8) Other long-term liabilities (Note 18) — (1) (111) (173) 400 118 44 12 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 $) 2022 2021 2022 2021 Projected benefit obligation 1 — (2,687) (119) (183) Plan assets at fair value — 2,686 — — Funded Status – Plan Deficit — (1) (119) (183) 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 2022 2021 (millions of Canadian $) Accumulated benefit obligation (2,880) (3,714) Plan assets at fair value 3,481 4,145 Funded Status – Plan Surplus 601 431 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, 2022 and December 31, 2021. The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: at December 31 Percentage of Target Allocations 2022 2021 2022 Fixed income securities 38 % 34 % 25% to 50% Equity securities 44 % 53 % 30% to 55% Other investments 18 % 13 % 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 $) 2022 2021 2022 2021 Fixed income securities 7 7 0.2 % 0.2 % Equity securities 3 5 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 other post-retirement benefits measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. For additional information on the fair value hierarchy, refer to Note 28, Risk management and financial instruments. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2022 2021 2022 2021 2022 2021 2022 2021 2022 2021 Asset Category Cash and Cash Equivalents 55 68 1 2 — — 56 70 1 2 Equity Securities: Canadian 117 269 — 148 — — 117 417 3 9 U.S. 897 649 — 164 — — 897 813 24 18 International 172 126 172 354 — — 344 480 9 10 Global — 111 75 313 — — 75 424 2 9 Emerging 50 25 127 120 — — 177 145 5 3 Fixed Income Securities: Canadian Bonds: Federal — — 221 226 — — 221 226 6 5 Provincial — — 249 331 — — 249 331 6 7 Municipal — — 12 16 — — 12 16 — — Corporate — — 108 147 — — 108 147 3 4 U.S. Bonds: Federal 177 433 158 15 — — 335 448 9 10 Municipal — — 1 1 — — 1 1 — — Corporate 345 67 94 143 — — 439 210 11 5 International: Government 5 6 6 7 — — 11 13 — — Corporate — — 58 73 — — 58 73 1 2 Mortgage backed 36 42 1 5 — — 37 47 1 1 Net forward contracts — — (78) — — — (78) — (2) — Other Investments: Real estate — — — — 336 283 336 283 9 6 Infrastructure — — — — 296 281 296 281 8 6 Private equity funds — — — — — 1 — 1 — — Funds held on deposit 144 150 — — — — 144 150 4 3 1,998 1,946 1,205 2,065 632 565 3,835 4,576 100 100 The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Balance at December 31, 2020 417 Purchases and sales 100 Realized and unrealized gains 48 Balance at December 31, 2021 565 Purchases and sales 52 Realized and unrealized gains 15 Balance at December 31, 2022 632 The Company's expected funding contributions in 2023 are approximately $32 million for the DB Plans, $6 million for the other post-retirement benefit plans and approximately $69 million for the savings plans and DC Plans. The Company does not expect to issue additional letters of credit to the Canadian DB Plan for the funding of solvency requirements. The following are estimated future benefit payments, which reflect expected future service: (millions of Canadian $) Pension Benefits Other Post-Retirement Benefits 2023 210 25 2024 214 24 2025 217 24 2026 221 23 2027 224 23 2028 to 2032 1,160 111 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, 2022. 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 2022 2021 2022 2021 Discount rate 5.15 % 3.05 % 5.45 % 3.10 % Rate of compensation increase 3.30 % 2.95 % — — 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 2022 2021 2020 2022 2021 2020 Discount rate 3.05 % 2.70 % 3.20 % 3.10 % 2.80 % 3.35 % Expected long-term rate of return on plan assets 6.10 % 6.15 % 6.40 % 3.25 % 3.00 % 3.50 % Rate of compensation increase 3.00 % 2.60 % 3.00 % — — — The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in determining the overall expected rate of return. The discount rate is based on market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan. A 6.10 per cent weighted-average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2023 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 $) 2022 2021 2020 2022 2021 2020 Service cost 1 145 171 155 5 6 6 Other components of net benefit cost 1 Interest cost 125 119 133 13 12 14 Expected return on plan assets (239) (234) (230) (14) (13) (14) Amortization of actuarial loss 10 23 21 1 2 2 Amortization of regulatory asset 12 27 25 1 2 2 Curtailment gain — (5) — — — — Settlement gain – AOCI (2) (2) — — — — (94) (72) (51) 1 3 4 Net Benefit Cost Recognized 51 99 104 6 9 10 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: year ended December 31 2022 2021 2020 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Net loss 38 24 147 5 358 22 Pre-tax amounts recognized in OCI were as follows: year ended December 31 2022 2021 2020 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Amortization of net loss from AOCI to net income (10) (1) (23) (2) (21) (2) Curtailment — — — 3 — — Settlement 2 — 2 — — — Funded status adjustment (101) 20 (190) (18) (18) 3 (109) 19 (211) (17) (39) 1

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	Dec. 31, 2022
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. Climate change also presents a potential financial impact to commodity prices and volumes. TC Energy's exposure to climate change-related risk 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. In addition, scenario planning against several demand outlooks and monitoring of key signposts is also considered as part of the Company's long-term corporate strategic planning process. 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. For eligible hedging relationships affected by the expected cessation of certain reference interest rates, the Company has applied the optional expedient allowing an entity to assume that the hedged forecasted transaction in a cash flow hedge is probable of occurring and, therefore, these changes are not expected to have a material impact on the consolidated financial statements. Refer to Note 3, Accounting changes, for additional information on Reference Rate Reform. 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 the functional currency for TC Energy's Mexico operations is 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 peso-denominated income tax exposure for these entities, leading to fluctuations in Income from equity investments and Income tax expense. As the Company's U.S. dollar-denominated monetary assets and liabilities in our Mexico operations continue to grow, this exposure increases. These exposures are managed using foreign exchange derivatives. 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 2022 2021 Fair 1,2 Notional Amount Fair 1,2 Notional Amount (millions of Canadian $, unless otherwise noted) U.S. dollar foreign exchange options (maturing 2023 to 2024) (22) US 3,600 (4) US 3,800 U.S. dollar cross-currency interest rate swaps (maturing 2023 to 2025) 3 (5) US 300 23 US 400 (27) US 3,900 19 US 4,200 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2022, Net income includes net realized gains of $1 million (2021 – 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 2022 2021 (millions of Canadian $, unless otherwise noted) Notional amount 32,500 (US 24,000) 30,700 (US 24,200) Fair value 30,800 (US 22,700) 35,500 (US 28,100) 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, loans receivable, net investment in leases and contract assets. 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, 2022, the Company recorded a $149 million (2021 and 2020 – nil) ECL provision with respect to the net investment in leases associated with the in-service TGNH pipelines and a $14 million (2021 and 2020 – nil) ECL provision 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, 2022 and 2021. At December 31, 2022 and 2021, 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. 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, Loans receivable from affiliates, Other current assets, Long-term loans receivable from affiliate, 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. 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 2022 2021 Carrying Amount Fair Value Carrying Fair (millions of Canadian $) Long-term debt, including current portion (Note 20) 1,2 (41,543) (39,505) (38,661) (45,615) Junior subordinated notes (Note 21) (10,495) (9,415) (8,939) (9,236) (52,038) (48,920) (47,600) (54,851) 1 Long-term debt is recorded at amortized cost, except for US$1.6 billion (2021 – nil) that is attributed to hedged risk and recorded at fair value. 2 Net income for 2022 included unrealized gains of $64 million (2021 – nil) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$1.6 billion of long-term debt at December 31, 2022 (2021 – nil). 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 2022 2021 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 — 54 — 26 Maturing within 1-5 years — 106 8 107 Maturing within 5-10 years 1,153 — 1,150 — Maturing after 10 years 77 — 84 — Fair value of equity securities 2,4 749 — 817 — 1,979 160 2,059 133 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 2022 2021 2020 (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 (losses)/gains (244) (7) 45 (2) 130 1 Net realized (losses)/gains 3 (32) — 3 — 20 1 1 Gains and 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 assets or regulatory liabilities. 2 Gains and losses on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income. 3 Realized gains and 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, 2022 Cash Flow Hedges Fair Value Hedges Net Held for Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 8) Commodities 2 — — — 597 597 Foreign exchange — — 6 11 17 — — 6 608 614 Other long-term assets (Note 15) 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 17) Commodities 2 (72) — — (584) (656) Foreign exchange — — (31) (158) (189) Interest rate — (26) — — (26) (72) (26) (31) (742) (871) Other long-term liabilities (Note 18) 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 balance sheet classification of the fair value of derivative instruments was as follows: at December 31, 2021 Cash Flow Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 8) Commodities 2 — — 122 122 Foreign exchange — 10 37 47 — 10 159 169 Other long-term assets (Note 15) Commodities 2 — — 8 8 Foreign exchange — 32 6 38 Interest rate 2 — — 2 2 32 14 48 Total Derivative Assets 2 42 173 217 Accounts payable and other (Note 17) Commodities 2 (23) — (138) (161) Foreign exchange — (4) (46) (50) Interest rate (10) — — (10) (33) (4) (184) (221) Other long-term liabilities (Note 18) Commodities 2 (4) — (6) (10) Foreign exchange — (19) (10) (29) Interest rate (8) — — (8) (12) (19) (16) (47) Total Derivative Liabilities (45) (23) (200) (268) Total Derivatives (43) 19 (27) (51) 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 $) 2022 2021 2022 2021 Long-term debt (2,101) — 64 — 1 At December 31, 2022 and 2021, 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, 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. In 2022, TC Energy updated this presentation to a net basis as it better reflects the Company's trading positions and how it manages its business. at December 31, 2021 Power Natural Gas Liquids Foreign Exchange Interest Rate Net sales/(purchases) 1 490 (52) 4 — — Millions of U.S. dollars — — — 6,636 650 Millions of Mexican pesos — — — 5,500 — Maturity dates 2022-2026 2022-2027 2022 2022-2026 2024-2026 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively. In 2022, TC Energy updated this presentation to a net basis as it better reflects the Company's trading positions and how it manages its business. Unrealized and Realized Gains and Losses on Derivative Instruments The following summary does not include hedges of the net investment in foreign operations: year ended December 31 2022 2021 2020 (millions of Canadian $) Derivative Instruments Held For Trading 1 Amount of unrealized gains/(losses) in the year Commodities 14 9 (23) Foreign exchange (Note 22 ) (149) (203) 126 Amount of realized gains/(losses) in the year Commodities 759 287 183 Foreign exchange (Note 22 ) (2) 240 (33) Derivative Instruments in Hedging Relationships 2 Amount of realized (losses)/gains in the year Commodities (73) (44) 6 Interest rate (3) (32) (16) 1 Realized and unrealized gains and 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 and losses on foreign exchange held-for-trading derivative instruments are included on a net basis in Foreign exchange (loss)/gain, net. 2 In 2022, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur (2021 – realized loss of $10 million, 2020 – nil). Derivatives in cash flow hedging relationships The components of OCI (Note 26) related to the change in fair value of derivatives in cash flow hedging relationships before tax and including the portion attributable to non-controlling interests were as follows: year ended December 31 2022 2021 2020 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI 1 Commodities (94) (35) (5) Interest rate 36 22 (766) (58) (13) (771) 1 No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI. 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 2022 2021 2020 (millions of Canadian $) Fair Value Hedges Interest rate contracts 1 Hedged items (30) — (3) Derivatives designated as hedging instruments (1) — 1 Cash Flow Hedges Reclassification of losses on derivative instruments from AOCI to Net income 2,3 Commodity contracts 4 (47) (22) (1) Interest rate contracts 1 (16) (46) (648) 1 Presented within Interest expense in the Consolidated statement of income, except for a loss of $613 million recorded in May 2020 related to a contractually required derivative instrument used to hedge the interest rate risk associated with project-level financing for the Coastal GasLink construction. This derivative instrument was derecognized as part of the sale of a 65 per cent equity interest in Coastal GasLink LP. The loss was included in Net gain/(loss) on sale of assets. Refer to Note 30, Acquisitions and dispositions, for additional information. 2 Refer to Note 26, Other comprehensive income/(loss) and accumulated other comprehensive income/(loss), for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests. 3 There are no amounts recognized in earnings that were excluded from effectiveness testing. 4 Presented within Revenues (Power and Energy Solutions) in the Consolidated statement of income. 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, 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. at December 31, 2021 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 130 (91) 39 Foreign exchange 85 (54) 31 Interest rate 2 (1) 1 217 (146) 71 Derivative Instrument Liabilities Commodities (171) 91 (80) Foreign exchange (79) 54 (25) Interest rate (18) 1 (17) (268) 146 (122) 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 $138 million and letters of credit of $68 million at December 31, 2022 (2021 – $144 million and $130 million, respectively) to its counterparties. At December 31, 2022, the Company held less than $1 million in cash collateral and $10 million in letters of credit (2021 – nil and $6 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, 2022, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $19 million (2021 – $5 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, 2022, 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 and the Company uses the most observable inputs available or, if not available, long-term broker quotes to estimate the fair value for these transactions. 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, 2022 Quoted Prices in Active Markets 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. at December 31, 2021 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 39 91 — 130 Foreign exchange — 85 — 85 Interest rate — 2 — 2 Derivative Instrument Liabilities Commodities (49) (116) (6) (171) Foreign exchange — (79) — (79) Interest rate — (18) — (18) (10) (35) (6) (51) 1 There were no transfers from Level II to Level III for the year ended December 31, 2021. 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) 2022 2021 Balance at beginning of year (6) (4) Net losses included in Net income (10) (3) Net losses included in OCI (3) — Transfers out of Level III 7 — Settlements 1 1 Balance at End of Year 1 (11) (6) 1 Revenues .

CHANGES IN OPERATING WORKING CA

CHANGES IN OPERATING WORKING CAPITAL	12 Months Ended
CHANGES IN OPERATING WORKING CAPITAL	Dec. 31, 2022
CHANGES IN OPERATING WORKING CAPITAL
CHANGES IN OPERATING WORKING CAPITAL	CHANGES IN OPERATING WORKING CAPITAL year ended December 31 2022 2021 2020 (millions of Canadian $) (Increase)/decrease in Accounts receivable (575) (925) 129 Increase in Inventories (190) (93) (55) Decrease/(increase) in Other current assets 118 (141) (221) (Decrease)/increase in Accounts payable and other (83) 890 (162) Increase/(decrease) in Accrued interest 91 (18) (18) Increase in Operating Working Capital (639) (287) (327)

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
ACQUISITIONS AND DISPOSITIONS	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS Canadian Natural Gas Pipelines Coastal GasLink LP In May 2020, TC Energy completed the sale of a 65 per cent equity interest in Coastal GasLink LP to third parties for net proceeds of $656 million before post-closing adjustments resulting in a pre-tax gain of $364 million ($402 million after tax). The pre-tax gain included $231 million related to the required remeasurement of the Company’s retained 35 per cent equity interest to fair value which was based on the proceeds realized for the 65 per cent equity interest, and also incorporated the reclassification from AOCI to income of the fair value of a derivative instrument used to hedge the interest rate risk associated with project-level financing for the Coastal GasLink construction. The $402 million after-tax gain also reflected the utilization of previously unrecognized tax loss benefits. The pre-tax gain was included in Net gain/(loss) on sale of assets in the Consolidated statement of income. As part of this transaction, TC Energy was contracted by Coastal GasLink LP to construct and operate the pipeline. TC Energy uses the equity method to account for its remaining 35 per cent equity interest in the Company's consolidated financial statements. Immediately preceding the equity sale, Coastal GasLink LP drew down $1.6 billion on the secured long-term project financing credit facilities, of which approximately $1.5 billion was paid to TC Energy. 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 TransCanada Turbines Ltd. In November 2020, TC Energy acquired the remaining 50 per cent ownership interest in TransCanada Turbines Ltd. (TC Turbines) for cash consideration of US$67 million. TC Turbines provides industrial gas turbine maintenance, parts, repair and overhaul services. The acquisition was accounted for as a business combination and the evaluation of assigned fair value of acquired assets and liabilities did not result in recognition of goodwill. TC Energy previously accounted for its 50 per cent interest in TC Turbines as an equity investment but commenced full consolidation of TC Turbines as of the date of acquisition, which did not have a material impact on Revenues and Net income of the Company. In addition, the pro forma incremental impact on the Company’s Revenues and Net income for each of the periods presented was not material. Ontario Natural Gas-fired Power Plants In April 2020, the Company completed the sale of the Halton Hills and Napanee power plants as well as its 50 per cent interest in Portlands Energy Centre to a subsidiary of Ontario Power Generation Inc. for net proceeds of approximately $2.8 billion before post-closing adjustments. The total pre-tax loss of $676 million ($470 million after tax) on this transaction included losses accrued during 2019 while classified as an asset held for sale and a 2021 post-close adjustment and also reflected utilization of previously unrecognized tax loss benefits. The pre-tax loss was included in Net gain/(loss)on sale of assets in the Consolidated statement of income. This loss may be amended in the future upon the settlement of existing insurance claims.

COMMITMENTS, CONTINGENCIES AND

COMMITMENTS, CONTINGENCIES AND GUARANTEES	12 Months Ended
COMMITMENTS, CONTINGENCIES AND GUARANTEES	Dec. 31, 2022
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 2022 were $362 million (2021 – $239 million; 2020 – $224 million). The Company has entered into PPAs with solar and wind-power generating facilities ranging from one 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, 2022, TC Energy had the following capital expenditure commitments: • approximately $1.0 billion for its Canadian natural gas pipelines, primarily related to construction costs associated with NGTL System expansion projects • approximately $0.3 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with ANR and Columbia Gas pipeline projects • approximately $1.7 billion for its Mexico natural gas pipelines, primarily related to construction of the Southeast Gateway pipeline • approximately $0.3 billion for its Power and Energy Solutions business, primarily related to the Company's proportionate share of commitments for Bruce Power's life extension program. Contingencies TC Energy is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2022, the Company had accrued approximately $20 million (2021 – $30 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. 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. Keystone XL In September 2022, the International Centre for Settlement of Investment Disputes (ICSID) formally constituted a tribunal to hear TC Energy's request for arbitration under NAFTA where the Company is seeking to recover more than US$15 billion in economic damages resulting from the revocation of the Presidential Permit for the Keystone XL pipeline project. This claim is in an early stage and the timing and outcome is unknown at present. Termination activities undertaken in 2022, including asset dispositions and preservation, will continue throughout 2023. The Company will continue to coordinate with regulators, stakeholders and Indigenous groups to meet its environmental and regulatory commitments. 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 2022 2021 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas Renewable to 2053 100 — 93 — Bruce Power Renewable to 2065 88 — 88 — Other jointly-owned entities to 2043 81 3 80 4 269 3 261 4 1 TC Energy's share of the potential estimated current or contingent exposure.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
VARIABLE INTEREST ENTITIES	Dec. 31, 2022
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 $) 2022 2021 ASSETS Current Assets Cash and cash equivalents 60 72 Accounts receivable 98 70 Inventories 32 28 Other current assets 14 13 204 183 Plant, Property and Equipment 3,997 3,672 Equity Investments 748 890 Goodwill 449 421 5,398 5,166 LIABILITIES Current Liabilities Accounts payable and other 234 232 Accrued interest 18 17 Current portion of long-term debt 31 29 283 278 Regulatory Liabilities 78 66 Other Long-Term Liabilities 1 1 Deferred Income Tax Liabilities 16 13 Long-Term Debt 2,136 2,025 2,514 2,383 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 $) 2022 2021 Balance sheet Loans receivable from affiliates (Notes 7 and 12) 1 — 1 Equity investments Bruce Power 5,783 4,493 Coastal GasLink (Note 7) 1 — 386 Pipeline equity investments and other 1,148 1,219 Long-term loans receivable from affiliate (Note 7) — 238 Off-balance sheet 2 Bruce Power 3 2,025 974 Coastal GasLink 4 3,300 3,037 Pipeline equity investments 58 171 Maximum exposure to loss 12,314 10,519 1 The pre-impairment balances in Equity investments ($2,798 million) and Loans receivable from affiliates ($250 million) at December 31, 2022 related to TC Energy’s investment in Coastal GasLink LP were reduced to a nil balance and an impairment charge was recognized in fourth quarter 2022 in Impairment of equity investment in the Consolidated statement of income. 2 Includes maximum potential exposure to guarantees and future funding commitments. 3 On March 7, 2022, the IESO verified Bruce Power's Unit 3 MCR program final cost and schedule duration estimate submitted in December 2021. As at December 31, 2022, the maximum exposure includes TC Energy's portion of capital to be invested under the Unit 3 MCR program as well as the expected increase in the capital to be invested under the Asset Management program through 2027. 4 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. The committed capacity under the subordinated loan agreement was $1,262 million as at December 31, 2022 and will increase in the future as required to support the estimated $3.3 billion of additional equity financing requirements through completion of construction of the Coastal GasLink pipeline. The determination of the Company’s maximum exposure to loss involves an estimate of the capital costs to complete the Coastal GasLink pipeline.

SUBSEQUENT EVENT

SUBSEQUENT EVENT	12 Months Ended
SUBSEQUENT EVENT	Dec. 31, 2022
Subsequent Events [Abstract]
SUBSEQUENT EVENT	SUBSEQUENT EVENT Mexico Debt Issuance On January 17, 2023, a wholly-owned Mexican subsidiary entered into a US$1.8 billion senior unsecured term loan and a US$500 million senior unsecured credit facility. Both the term loan and the revolving commitment are due in January 2028 and bear interest at a floating rate.

ACCOUNTING POLICIES (Policies)

ACCOUNTING POLICIES (Policies)	12 Months Ended
ACCOUNTING POLICIES (Policies)	Dec. 31, 2022
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: • assessment of goodwill impairment indicators and fair value of reporting units that contain goodwill (Note 14) • capital cost estimates to complete the Coastal GasLink pipeline used to measure TC Energy’s maximum exposure to loss resulting from its involvement with Coastal GasLink Limited Partnership (Coastal GasLink LP) and in measuring the fair value of TC Energy’s equity investment in Coastal GasLink LP (Notes 7 and 32). 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 (Note 6) • recoverability and depreciation rates of plant, property and equipment (Note 9) • allocation of consideration to lease and non-lease components in a contract that contains a lease (Note 10) • assumptions used to measure the carrying amount of (Note 10) and expected credit losses (Note 28) on net investment in leases and certain contract assets • fair value of equity investments not otherwise noted above (Note 11) • carrying value of regulatory assets and liabilities (Note 13) • assumptions used to measure the environmental remediation liability from the Keystone pipeline rupture (Note 17) • recognition of asset retirement obligations (Note 18) • provisions for income taxes, including valuation allowances and releases (Note 19) • assumptions used to measure retirement and other post-retirement benefit obligations (Note 27) • fair value of financial instruments (Note 28) • fair value of assets and liabilities acquired in a business combination (Note 30) • provisions for commitments, contingencies and guarantees (Note 31). TC Energy continues to assess the impact of climate change on the consolidated financial statements. The Company has announced internal greenhouse gas reduction targets and closely monitors regulatory initiatives that may impact its existing businesses. There were also recent 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 and accrued environmental costs. 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. 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.
Leases	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	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 income 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 on 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.
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.
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. 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 other post-retirement benefits 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 and 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 on 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 Changes in Accounting Policies for 2022 Reference Rate Reform In March 2020, FASB issued optional guidance with respect to the expected cessation of certain reference interest rates. The guidance provides optional expedients for contracts and hedging relationships that are affected by reference rate reform if certain criteria are met. In December 2022, FASB issued an update to defer the sunset date of the guidance to December 31, 2024. For eligible hedging relationships, the Company has applied the optional expedient allowing an entity to assume that the hedged forecasted transaction in a cash flow hedge is probable of occurring. The Company expects to use practical expedients available in the guidance to treat contract modifications as events that do not require contract remeasurement or reassessment of previous accounting determinations. As such, these changes are not expected to have a material impact on the Company's consolidated financial statements. Government Assistance In November 2021, the FASB issued new guidance that expands annual disclosure requirements for entities that account for a transaction with a government by applying a grant or contribution accounting model by analogy to other accounting guidance. Entities are required to disclose the nature of the transactions, the related accounting policies used to account for the transactions, the effect of the transactions on an entity’s financial statements and any significant terms and conditions of the transaction. This new guidance is effective for annual disclosure requirements at December 31, 2022 and can be applied either prospectively or retrospectively, with early application permitted. The Company adopted the guidance effective January 1, 2022 on a prospective basis and it did not have a material impact on the Company's consolidated financial statements. Contract Assets and Liabilities from Contracts with Customers In October 2021, the FASB issued new guidance that amends the accounting for contract assets and liabilities from contracts with customers acquired in a business combination. At the acquisition date, an acquirer should account for the contract assets and liabilities in accordance with guidance on revenue from contracts with customers. This new guidance is effective January 1, 2023 and is applied prospectively with early adoption permitted. Early adoption requires the application of the amendments retrospectively to all business combinations with an acquisition date in the year of early adoption. The Company elected to adopt the new guidance effective January 1, 2022 and it did not have any impact on the Company's consolidated financial statements.

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
SEGMENTED INFORMATION (Tables)	Dec. 31, 2022
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	year ended December 31, 2022 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Energy Solutions Corporate 1 Total (millions of Canadian $) 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 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 (Losses)/Earnings (1,440) 2,617 491 1,123 833 8 3,632 Interest expense (2,588) Allowance for funds used during construction 369 Foreign exchange loss, net 3 (185) Interest income and other 146 Income before Income Taxes 1,374 Income tax expense (589) Net Income 785 Net income attributable to non-controlling interests (37) Net Income Attributable to Controlling Interests 748 Preferred share dividends (107) Net Income Attributable to Common Shares 641 Capital Spending Capital expenditures 3,274 2,137 1,027 106 93 41 6,678 Capital projects in development — — — — 49 — 49 Contributions to equity investments 4 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 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 loss, net by the corresponding foreign exchange losses and gains on the affiliate receivable balance until March 15, 2022, when it was fully repaid upon maturity. Refer to Note 12, Loans receivable from affiliates, for additional information. 4 Contributions to equity investments in the Corporate segment of $1.2 billion are offset by the equivalent amount in Other distributions from equity investments, although they are reported on a gross basis in the Company’s Consolidated statement of cash flows. Refer to Note 12, Loans receivable from affiliates, for additional information. year ended December 31, 2021 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Energy Solutions Corporate 1 Total (millions of Canadian $) 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 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) Asset impairment charge and other — — — (2,775) — — (2,775) Gain 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 gain, net 3 10 Interest income and other 190 Income before Income Taxes 2,166 Income tax expense (120) Net Income 2,046 Net income attributable to non-controlling interests (91) Net Income Attributable to Controlling Interests 1,955 Preferred share dividends (140) Net Income Attributable to Common Shares 1,815 Capital Spending 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 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 gain, net by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 12, Loans receivable from affiliates, for additional information. year ended December 31, 2020 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Energy Solutions Corporate 1 Total (millions of Canadian $) Revenues 4,469 5,031 716 2,371 412 — 12,999 Intersegment revenues — 165 — — 20 (185) 2 — 4,469 5,196 716 2,371 432 (185) 12,999 Income from equity investments 12 264 127 75 455 86 3 1,019 Plant operating costs and other (1,631) (1,485) (57) (654) (220) 169 2 (3,878) Property taxes (284) (337) — (101) (5) — (727) Depreciation and amortization (1,273) (801) (117) (332) (67) — (2,590) Net gain/(loss) on sale of assets 364 — — — (414) — (50) Segmented Earnings 1,657 2,837 669 1,359 181 70 6,773 Interest expense (2,228) Allowance for funds used during construction 349 Foreign exchange gain, net 3 28 Interest income and other 185 Income before Income Taxes 5,107 Income tax expense (194) Net Income 4,913 Net income attributable to non-controlling interests (297) Net Income Attributable to Controlling Interests 4,616 Preferred share dividends (159) Net Income Attributable to Common Shares 4,457 Capital Spending Capital expenditures 3,503 2,785 173 1,315 179 58 8,013 Capital projects in development — — — 122 — — 122 Contributions to equity investments 105 — — 5 655 — 765 3,608 2,785 173 1,442 834 58 8,900 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 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 gain, net by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 12, Loans receivable from affiliates, for additional information. at December 31 2022 2021 (millions of Canadian $) Total Assets by Segment Canadian Natural Gas Pipelines 27,456 25,452 U.S. Natural Gas Pipelines 50,038 45,502 Mexico Natural Gas Pipelines 9,231 7,547 Liquids Pipelines 15,587 14,951 Power and Energy Solutions 8,272 6,563 Corporate 3,764 4,203 114,348 104,218
Revenue from External Customers by Geographic Areas	year ended December 31 2022 2021 2020 (millions of Canadian $) Revenues Canada – domestic 4,942 4,603 4,392 Canada – export 1,322 1,226 1,059 United States 8,025 6,953 6,832 Mexico 688 605 716 14,977 13,387 12,999
Schedule of Long-Lived Assets by Country	at December 31 2022 2021 (millions of Canadian $) Plant, Property and Equipment Canada 27,232 24,890 United States 43,505 39,335 Mexico 5,203 5,957 75,940 70,182

REVENUES (Tables)

REVENUES (Tables)	12 Months Ended
REVENUES (Tables)	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenues	Disaggregation of Revenues 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 development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy as at December 31, 2022. Refer to Note 30, Acquisitions and dispositions, for additional information. 2 Includes $37 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type leases on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. 3 Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 10, Leases, for additional information. 4 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information on income from operating lease arrangements and financial instruments, respectively. 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 13, 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 development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy as at December 31, 2021. Refer to Note 30, Acquisitions and dispositions, for additional information. 2 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information on income from operating lease arrangements and financial instruments, respectively. 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 13, Rate-regulated businesses, for additional information. year ended December 31, 2020 Canadian U.S. Mexico Liquids Pipelines Power Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,408 4,301 607 2,206 — 11,522 Power generation — — — — 192 192 Natural gas storage and other 1 61 654 109 3 106 933 4,469 4,955 716 2,209 298 12,647 Other revenues 2,3 — 76 — 162 114 352 4,469 5,031 716 2,371 412 12,999 1 Includes $138 million of fee revenues from affiliates, of which $77 million was related to the construction of the Sur de Texas pipeline which is 60 per cent owned by TC Energy and $61 million was related to development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy as at December 31, 2020. Refer to Note 30, Acquisitions and dispositions, for additional information. 2 Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 10, Leases, and Note 28, Risk management and financial instruments, for additional information on income from operating lease arrangements and financial instruments, respectively. 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 13, Rate-regulated businesses, for additional information.
Contract Balances	Contract Balances at December 31 2022 2021 Affected line item on the (millions of Canadian $) Receivables from contracts with customers 1,907 1,627 Accounts receivable Contract assets (Note 8) 155 202 Other current assets Long-term contract assets (Note 15) 355 249 Other long-term assets Contract liabilities 1 (Note 17) 62 90 Accounts payable and other Long-term contract liabilities (Note 18) 32 184 Other long-term liabilities 1 During the year ended December 31, 2022, $51 million (2021 – $95 million) of revenues were recognized that were included in contract liabilities at the beginning of the year.

KEYSTONE XL (Tables)

KEYSTONE XL (Tables)	12 Months Ended
KEYSTONE XL (Tables)	Dec. 31, 2022
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
Schedule of Redeemable Non-controlling Interest	The changes in Redeemable non-controlling interest classified in mezzanine equity were as follows: (millions of Canadian $) Balance at January 1, 2021 393 Net income attributable to redeemable non-controlling interest 1 Class A Interests repurchased (394) Balance at December 31, 2021 —

COASTAL GASLINK (Tables)

COASTAL GASLINK (Tables)	12 Months Ended
COASTAL GASLINK (Tables)	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Changes in Loan Balances	The table below reflects the changes in this loan balance for the year ended December 31, 2022. (millions of Canadian $) Outstanding balance as at December 31, 2021 238 Issuances 1 112 Repayments 1 (100) Outstanding balance at December 31, 2022 250 Impairment (250) Carrying value at December 31, 2022 — 1 Presented on a net basis on the Company's Consolidated statement of cash flows.

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
OTHER CURRENT ASSETS (Tables)	Dec. 31, 2022
Other Assets [Abstract]
Schedule of Other Current Assets	at December 31 2022 2021 (millions of Canadian $) Fair value of derivative contracts (Note 28) 614 169 Current portion of Keystone environmental provision recovery (Note 17 ) 410 — Current portion of net investment in leases (Note 10 ) 291 — Contract assets (Note 5) 155 202 Keystone XL assets held for sale 122 138 Prepaid expenses 118 112 Cash provided as collateral 106 273 Keystone XL contractual recoveries (Note 6) 86 640 Regulatory assets (Note 13) 67 53 Other 183 130 2,152 1,717

PLANT, PROPERTY AND EQUIPMENT (

PLANT, PROPERTY AND EQUIPMENT (Tables)	12 Months Ended
PLANT, PROPERTY AND EQUIPMENT (Tables)	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Schedule of Plant, Property and Equipment	at December 31 2022 2021 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 18,119 6,285 11,834 14,892 5,751 9,141 Compression 6,265 2,224 4,041 6,191 2,065 4,126 Metering and other 1,518 769 749 1,458 705 753 25,902 9,278 16,624 22,541 8,521 14,020 Under construction 1,552 — 1,552 2,285 — 2,285 27,454 9,278 18,176 24,826 8,521 16,305 Canadian Mainline Pipeline 10,472 7,852 2,620 10,423 7,698 2,725 Compression 4,328 3,247 1,081 4,165 3,125 1,040 Metering and other 692 285 407 652 264 388 15,492 11,384 4,108 15,240 11,087 4,153 Under construction 269 — 269 139 — 139 15,761 11,384 4,377 15,379 11,087 4,292 Other Canadian Natural Gas Pipelines 1 Other 1,984 1,624 360 1,937 1,567 370 Under construction 455 — 455 58 — 58 2,439 1,624 815 1,995 1,567 428 45,654 22,286 23,368 42,200 21,175 21,025 U.S. Natural Gas Pipelines Columbia Gas Pipeline 12,471 1,069 11,402 11,205 799 10,406 Compression 5,190 495 4,695 4,522 381 4,141 Metering and other 4,026 346 3,680 3,657 257 3,400 21,687 1,910 19,777 19,384 1,437 17,947 Under construction 659 — 659 433 — 433 22,346 1,910 20,436 19,817 1,437 18,380 ANR Pipeline 2,066 641 1,425 1,820 557 1,263 Compression 3,785 734 3,051 2,559 565 1,994 Metering and other 1,666 440 1,226 1,391 422 969 7,517 1,815 5,702 5,770 1,544 4,226 Under construction 328 — 328 833 — 833 7,845 1,815 6,030 6,603 1,544 5,059 at December 31 2022 2021 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Other U.S. Natural Gas Pipelines Columbia Gulf 3,511 224 3,287 2,749 178 2,571 GTN 2,964 1,239 1,725 2,701 1,071 1,630 Great Lakes 2,367 1,387 980 2,162 1,255 907 Other 2 1,928 760 1,168 1,755 657 1,098 10,770 3,610 7,160 9,367 3,161 6,206 Under construction 328 — 328 533 — 533 11,098 3,610 7,488 9,900 3,161 6,739 41,289 7,335 33,954 36,320 6,142 30,178 Mexico Natural Gas Pipelines 3 Pipeline 2,299 348 1,951 2,957 476 2,481 Compression 374 59 315 480 80 400 Metering and other 487 113 374 626 155 471 3,160 520 2,640 4,063 711 3,352 Under construction 2,547 — 2,547 2,590 — 2,590 5,707 520 5,187 6,653 711 5,942 Liquids Pipelines Keystone Pipeline System Pipeline 9,777 2,056 7,721 9,209 1,758 7,451 Pumping equipment 1,064 288 776 1,020 252 768 Tanks and other 3,723 859 2,864 3,534 737 2,797 14,564 3,203 11,361 13,763 2,747 11,016 Under construction 96 — 96 72 — 72 14,660 3,203 11,457 13,835 2,747 11,088 Intra-Alberta Pipelines 199 19 180 199 14 185 14,859 3,222 11,637 14,034 2,761 11,273 Power and Energy Solutions Natural Gas Power Generation 1,260 642 618 1,267 605 662 Natural Gas Storage and Other 820 238 582 797 216 581 2,080 880 1,200 2,064 821 1,243 Under construction 80 — 80 5 — 5 2,160 880 1,280 2,069 821 1,248 Corporate 900 386 514 836 320 516 110,569 34,629 75,940 102,112 31,930 70,182 1 Includes Foothills, Ventures LP and Great Lakes Canada. 2 Includes Portland, North Baja, Tuscarora, Crossroads and mineral rights.

LEASES (Tables)

LEASES (Tables)	12 Months Ended
LEASES (Tables)	Dec. 31, 2022
Leases [Abstract]
Operating Lease Cost and Other Information	Operating lease cost was as follows: year ended December 31 (millions of Canadian $) 2022 2021 Operating lease cost 1 106 105 Sublease income (5) (8) Net operating lease cost 101 97 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 $) 2022 2021 Cash paid for amounts included in the measurement of operating lease liabilities 67 69 ROU assets obtained in exchange for new operating lease liabilities 49 7 at December 31 2022 2021 Weighted average remaining lease term 8 years 9 years Weighted average discount rate 3.5 % 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 $) 2022 2021 Accounts payable and other 54 49 Other long-term liabilities (Note 18) 379 380 433 429
Maturities of Operating Lease Liabilities	Maturities of operating lease liabilities are as follows: (millions of Canadian $) 2022 2021 Less than one year 68 63 One to two years 65 60 Two to three years 62 58 Three to four years 60 55 Four to five years 54 54 More than five years 187 213 Total operating lease payments 496 503 Imputed interest (63) (74) Operating lease liabilities 433 429
Future Lease Payments to be Received Under Operating Leases	Future lease payments to be received under operating leases are as follows: (millions of Canadian $) 2022 2021 Less than one year 113 113 One to two years 111 111 Two to three years 94 110 Three to four years 70 94 Four to five years — 70 388 498
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: (millions of Canadian $) December 31, 2022 Net Investment in Leases Minimum lease payments 9,457 Unearned lease income (7,132) Lease receivable 2,325 Expected credit loss provision 1 (150) Present value of unguaranteed residual value 11 2,186 Current portion included in Other current assets (Note 8) (291) 1,895 1 Includes $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: (millions of Canadian $) December 31, 2022 Less than one year 291 One to two years 291 Two to three years 291 Three to four years 291 Four to five years 291 More than five years 8,002 9,457

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	12 Months Ended
EQUITY INVESTMENTS (Tables)	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Investments	(millions of Canadian $) Ownership Interest at December 31, 2022 Income from Equity Equity year ended December 31 at December 31 2022 2021 2020 2022 2021 Canadian Natural Gas Pipelines TQM 1 50.0 % 17 12 12 165 118 Coastal GasLink 1 35.0 % 1 — — — 386 U.S. Natural Gas Pipelines Northern Border 50.0 % 92 80 100 516 505 Millennium 47.5 % 103 91 96 500 474 Iroquois 50.0 % 77 55 52 237 392 Other Various 20 18 16 122 137 Mexico Natural Gas Pipelines Sur de Texas 60.0 % 150 160 213 1,050 835 Liquids Pipelines Grand Rapids 1 50.0 % 54 54 53 964 980 Port Neches Link LLC 2 95.0 % — — — 149 103 HoustonLink Pipeline 1 50.0 % 1 1 — 19 18 Northern Courier 1,3 nil — 16 22 — — Power and Energy Solutions Bruce Power 1 48.3 % 537 411 439 5,783 4,493 Other Various 2 — 16 30 — 1,054 898 1,019 9,535 8,441 1 Classified as a non-consolidated VIE. Refer to Note 32, Variable interest entities, for additional information. 2 Classified as a non-consolidated VIE in 2021. Refer to Note 32, Variable interest entities, for additional information. 3 In November 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 30, Acquisitions and dispositions, for additional information. Summarized Financial Information of Equity Investments year ended December 31 2022 2021 2020 (millions of Canadian $) Income Revenues 5,891 5,447 5,838 Operating and other expenses (3,390) (3,293) (3,341) Net income 2,147 1,859 2,047 Net income attributable to TC Energy 1,054 898 1,019 at December 31 2022 2021 (millions of Canadian $) Balance Sheet Current assets 3,414 3,498 Non-current assets 37,713 30,165 Current liabilities (2,856) (2,540) Non-current liabilities (17,690) (16,400)
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, 2022, 2021 and 2020 were as follows: year ended December 31 2022 2021 2020 (millions of Canadian $) Distributions Sur de Texas debt repayments 1,2 2,404 73 — Distributions received from operating activities of equity investments 1,025 975 1,123 Other 1 228 — — 3,657 1,048 1,123 Contributions Contributions to Coastal GasLink 1 1,414 92 101 Sur de Texas debt financing 1,2 1,199 — — Contributions made to other equity investments 1 820 1,118 664 3,433 1,210 765 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 12, Loans receivable from affiliates, for further information on 2022 refinancing activities with the Sur de Texas joint venture.

LOANS RECEIVABLE FROM AFFILIA_2

LOANS RECEIVABLE FROM AFFILIATES (Tables)	12 Months Ended
LOANS RECEIVABLE FROM AFFILIATES (Tables)	Dec. 31, 2022
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 $) 2022 2021 2020 Interest income 1 19 87 110 Interest income and other Interest expense 2 (19) (87) (110) Income from equity investments Foreign exchange losses 1 (28) (41) (86) Foreign exchange loss/(gain), net Foreign exchange gains 1 28 41 86 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
RATE-REGULATED BUSINESSES (Tables)	Dec. 31, 2022
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	at December 31 2022 2021 Remaining Recovery/ Settlement Period (years) (millions of Canadian $) Regulatory Assets Deferred income taxes 1 1,817 1,509 n/a Pensions and other post-retirement benefits 1,2 28 203 n/a Foreign exchange on long-term debt 1,3 19 3 1-7 Operating and debt-service regulatory assets 4 2 1 1 Other 111 104 n/a 1,977 1,820 Less: Current portion included in Other current assets (Note 8) 67 53 1,910 1,767 Regulatory Liabilities Pipeline abandonment trust balances 5 2,014 2,086 n/a Deferred income taxes – U.S. Tax Reform 6 1,197 1,141 n/a Canadian Mainline bridging amortization account 7 429 483 8 Cost of removal 8 337 254 n/a Canadian Mainline short-term adjustment and toll-stabilization accounts 7,9 284 60 n/a Canadian Mainline long-term adjustment account 7,10 149 186 4 Deferred income taxes 1 181 139 n/a Operating and debt-service regulatory liabilities 4 50 32 1 ANR post-employment and retirement benefits other than pension 11 43 40 n/a Pensions and other post-retirement benefits 2 10 13 n/a Other 99 66 n/a 4,793 4,500 Less: Current portion included in Accounts payable and other (Note 17) 273 200 4,520 4,300 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 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. 3 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. 4 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. 5 This balance represents the amounts collected in tolls from shippers 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 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. 9 Under the terms of the 2021-2026 Mainline Settlement, the STAA account will commence amortization when predetermined thresholds are met, over the term outlined per the settlement agreement. 10 Under the terms of the 2021-2026 Mainline Settlement, $223 million is amortized over the six-year settlement term.

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
GOODWILL (Tables)	Dec. 31, 2022
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 2022 2021 (millions) Canadian US Canadian dollars US Columbia Pipeline Group, Inc. 9,948 7,351 9,303 7,351 ANR 2,634 1,946 2,464 1,946 Great Lakes 165 122 725 573 North Baja 65 48 61 48 Tuscarora 31 23 29 23 12,843 9,490 12,582 9,941 Changes in Goodwill were as follows: (millions of Canadian $) U.S. Natural Balance at January 1, 2021 12,679 Foreign exchange rate changes (97) Balance at December 31, 2021 1 12,582 Great Lakes impairment charge (571) Foreign exchange rate changes 832 Balance at December 31, 2022 1 12,843 1 Represents gross amount of goodwill as at December 31, 2022 of $14,578 million (2021 – $13,746 million), net of accumulated impairment of $1,735 million (2021 – $1,164 million).

OTHER LONG-TERM ASSETS (Tables)

OTHER LONG-TERM ASSETS (Tables)	12 Months Ended
OTHER LONG-TERM ASSETS (Tables)	Dec. 31, 2022
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Schedule of Other Long-Term Assets	at December 31 2022 2021 (millions of Canadian $) Deferred income tax assets (Note 19) 1,070 509 Employee post-retirement benefits (Note 27) 563 312 Long-term contract assets (Note 5) 355 249 Keystone environmental provision recovery (Note 17) 240 — Capital projects in development 99 42 Fair value of derivative contracts (Note 28) 91 48 Keystone XL contractual recoveries (Note 6) 44 50 Other 323 193 2,785 1,403

NOTES PAYABLE (Tables)

NOTES PAYABLE (Tables)	12 Months Ended
NOTES PAYABLE (Tables)	Dec. 31, 2022
Short-Term Debt [Abstract]
Schedule of Notes Payable	2022 2021 (millions of Canadian $, unless otherwise noted) Outstanding at December 31 Weighted Outstanding at December 31 Weighted Canada 1 5,971 4.9 % 4,953 0.4 % U.S. (2022 – nil; 2021 – US$54) — — 68 0.3 % Mexico (2022 – US$215; 2021 – US$115) 2 291 6.0 % 145 1.7 % 6,262 5,166 1 At December 31, 2022, Notes payable consisted of Canadian dollar-denominated notes of $2,810 million (2021 – $1,989 million) and U.S. dollar-denominated notes of US$2,336 million (2021 – US$2,341 million). 2 The demand senior unsecured revolving credit facility for the Company's Mexico subsidiary can be drawn in either Mexican pesos or U.S. dollars, up to the total facility amount of MXN$5.0 billion or the U.S. dollar equivalent.
Schedule of Credit Facilities	These unsecured credit facilities included the following: at December 31 (billions of Canadian $, unless otherwise noted) 2022 2021 Borrowers Description Matures Total Facilities Unused Capacity 1 Total Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities 2 : TCPL Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes December 2027 3.0 1.7 3.0 TCPL / TCPL USA / Columbia / TransCanada American Investments Ltd. Supports TCPL's and TCPL USA's U.S. dollar commercial paper programs and for general corporate purposes of the borrowers, guaranteed by TCPL December 2023 US 3.0 US 0.6 US 4.5 TCPL / TCPL USA / Columbia / TransCanada American Investments Ltd. Supports TCPL's and TCPL USA's U.S. dollar commercial paper programs and for general and corporate purposes of the borrowers, guaranteed by TCPL December 2025 US 2.5 US 2.5 US 1.0 Demand senior unsecured revolving credit facilities 2 : TCPL / TCPL USA Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL Demand 2.1 3 1.0 2.1 3 Mexico subsidiary For Mexico general corporate purposes, guaranteed by TCPL Demand MXN 5.0 3 MXN 0.8 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, 2022, 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
ACCOUNTS PAYABLE AND OTHER (Tables)	Dec. 31, 2022
Payables and Accruals [Abstract]
Schedule of Accounts Payable and Other	at December 31 2022 2021 (millions of Canadian $) Trade payables 4,330 4,183 Fair value of derivative contracts (Note 28) 871 221 Keystone environmental provision 650 — Coastal GasLink contractual contribution (Notes 7, 11 and 32) 537 — Regulatory liabilities (Note 13) 273 200 Contract liabilities (Note 5) 62 90 Class C Interests (Note 6) 37 75 Other 389 330 7,149 5,099

OTHER LONG-TERM LIABILITIES (Ta

OTHER LONG-TERM LIABILITIES (Tables)	12 Months Ended
OTHER LONG-TERM LIABILITIES (Tables)	Dec. 31, 2022
Deferred Costs, Noncurrent [Abstract]
Schedule of Other Long-Term Liabilities	at December 31 2022 2021 (millions of Canadian $) Operating lease obligations (Note 10) 379 380 Fair value of derivative contracts (Note 28) 151 47 Employee post-retirement benefits (Note 27) 111 174 Asset retirement obligations 79 61 Long-term contract liabilities (Note 5) 32 184 Other 265 213 1,017 1,059

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
INCOME TAXES (Tables)	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Schedule of Geographic Components of Income	Geographic Components of Income before Income Taxes year ended December 31 2022 2021 2020 (millions of Canadian $) Canada (2,154) (292) 691 Foreign 3,528 2,458 4,416 Income before Income Taxes 1,374 2,166 5,107
Schedule of Provision for Income Taxes	year ended December 31 2022 2021 2020 (millions of Canadian $) Current Canada 43 29 (54) Foreign 372 276 306 415 305 252 Deferred Canada (467) (327) (224) Foreign 641 142 166 174 (185) (58) Income Tax Expense 589 120 194
Reconciliation of Income Tax Expense	year ended December 31 2022 2021 2020 (millions of Canadian $) Income before income taxes 1,374 2,166 5,107 Federal and provincial statutory tax rate 23.0 % 23.0 % 24.0 % Expected income tax expense 316 498 1,226 Foreign income tax rate differentials (271) (230) (258) Income tax differential related to regulated operations (174) (139) (228) Income from non-controlling interests and equity investments (54) (70) (141) Valuation allowance/(releases) 199 (8) (400) Non-taxable capital (gains) and losses 173 — (62) Settlement of Mexico prior years' income tax assessments 196 — — U.S. minimum tax 96 — — Non-deductible goodwill impairment 91 — — Impact of Mexico inflationary adjustments 24 32 7 Other (7) 37 50 Income Tax Expense 589 120 194
Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet	at December 31 2022 2021 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,519 1,163 Regulatory and other deferred amounts 571 537 Unrealized foreign exchange losses on long-term debt 333 130 Other 193 46 2,616 1,876 Less: Valuation allowance 640 229 1,976 1,647 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment 6,686 5,616 Equity investments 1,152 1,219 Taxes on future revenue requirement 397 333 Financial instruments 126 — Other 193 112 8,554 7,280 Net Deferred Income Tax Liabilities 6,578 5,633 The above deferred tax amounts have been classified on the Consolidated balance sheet as follows: at December 31 2022 2021 (millions of Canadian $) Deferred Income Tax Assets Other long-term assets (Note 15) 1,070 509 Deferred Income Tax Liabilities Deferred income tax liabilities 7,648 6,142 Net Deferred Income Tax Liabilities 6,578 5,633
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 2022 2021 2020 (millions of Canadian $) Unrecognized tax benefit at beginning of year 80 52 29 Gross increases – tax positions in prior years 6 5 26 Gross decreases – tax positions in prior years — (1) (2) Gross increases – tax positions in current year 7 26 1 Lapse of statutes of limitations (2) (2) (2) Unrecognized Tax Benefit at End of Year 91 80 52

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
LONG-TERM DEBT (Tables)	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	Outstanding amounts 2022 2021 Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Medium Term Notes Canadian 2023 to 2052 13,966 4.5 % 12,491 4.2 % Senior Unsecured Notes U.S. (2022 – US$15,542; 2021 – US$16,542) 2023 to 2049 21,032 4.9 % 20,936 4.8 % 34,998 33,427 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2022 and 2021 – US$200) 2023 271 7.9 % 254 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2022 and 2021 – US$33) 2026 44 7.5 % 41 7.5 % 919 899 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes 2 U.S. (2022 and 2021 – US$1,500) 2025 to 2045 2,030 4.9 % 1,898 4.9 % ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2022 – US$1,172; 2021 – US$372) 2024 to 2037 1,587 4.1 % 472 5.3 % TC PIPELINES, LP Senior Unsecured Notes U.S. (2022 and 2021 – US$850) 2025 to 2027 1,150 4.2 % 1,076 4.2 % GAS TRANSMISSION NORTHWEST LLC Senior Unsecured Notes U.S. (2022 and 2021 – US$325) 2030 to 2035 440 4.3 % 411 4.3 % Outstanding amounts 2022 2021 Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Unsecured Notes U.S. (2022 and 2021 – US$250 ) 2030 to 2031 338 2.8 % 316 2.8 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2022 – US$146; 2021 – US$167) 2028 to 2030 198 7.6 % 211 7.6 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2022 – US$34; 2021 – US$36) 2024 46 6.5 % 46 1.3 % 41,706 38,756 Current portion of long-term debt (1,898) (1,320) Unamortized debt discount and issue costs (239) (243) Fair value adjustments 3 76 148 39,645 37,341 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 Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia's obligations is required to comply with covenants under the debt indenture and, in the event of default, the guarantors would be obligated to pay the principal and related interest. 3 The fair value adjustments include $140 million (2021 – $148 million) related to the acquisition of Columbia Pipeline Group, Inc. These adjustments also include a decrease of $64 million (2021 – nil) related to hedged interest rate risk. Refer to Note 28, Risk management and financial instruments for additional information. The Company issued long-term debt over the three years ended December 31, 2022 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED 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 % 1 April 2020 Senior Unsecured Notes April 2030 US 1,250 4.10 % April 2020 Medium Term Notes April 2027 2,000 3.80 % 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 % October 2020 Senior Unsecured Notes October 2030 US 125 2.84 % TUSCARORA GAS TRANSMISSION COMPANY August 2021 Unsecured Term Loan August 2024 US 13 Floating KEYSTONE XL SUBSIDIARIES 2 Various Project-Level Credit Facility June 2021 US 849 Floating COLUMBIA PIPELINE GROUP, INC. 3 January 2021 Unsecured Term Loan June 2022 US 4,040 Floating GAS TRANSMISSION NORTHWEST LLC June 2020 Senior Unsecured Notes June 2030 US 175 3.12 % COASTAL GASLINK PIPELINE LIMITED PARTNERSHIP 4 April 2020 Senior Secured Credit Facilities April 2027 1,603 Floating 1 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 4.186 per cent. 2 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 6, Keystone XL, for additional information. 3 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. 4 In April 2020, Coastal GasLink LP entered into secured long-term project financing credit facilities. In May 2020, TC Energy completed the sale of a 65 per cent equity interest in Coastal GasLink LP and subsequently accounts for its remaining 35 per cent interest using the equity method. Immediately preceding the equity sale, Coastal GasLink LP made an initial draw of $1.6 billion on the credit facilities, of which approximately $1.5 billion was paid to TC Energy. Refer to Note 30, Acquisitions and dispositions, for additional information.
Schedule of Repayments of Long-Term Debt	At December 31, 2022, principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2023 2024 2025 2026 2027 Principal repayments on long-term debt 1,898 2,782 2,827 2,278 3,113
Schedule of Retired Long-Term Debt	The Company retired/repaid long-term debt over the three years ended December 31, 2022 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED 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 9.875 % November 2020 Debentures 250 11.80 % October 2020 Senior Unsecured Notes US 1,000 3.80 % March 2020 1 Senior Unsecured Notes US 750 4.60 % COLUMBIA PIPELINE GROUP, INC. December 2021 Unsecured Term Loan 2 US 4,040 Floating June 2020 Senior Unsecured Notes US 750 3.30 % 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 9.625 % 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 October 2020 Unsecured Loan Facility US 99 Floating KEYSTONE XL SUBSIDIARIES 3 June 2021 Project-Level Credit Facility US 849 Floating GAS TRANSMISSION NORTHWEST LLC June 2020 Senior Unsecured Notes US 100 5.29 % 1 Related unamortized debt issue costs of $8 million were included in Interest expense in the Consolidated statement of income for the year ended December 31, 2020. 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 6, Keystone XL, for additional information.
Schedule of Interest Expense	Interest Expense year ended December 31 2022 2021 2020 (millions of Canadian $) Interest on long-term debt 1,883 1,841 1,963 Interest on junior subordinated notes 543 453 470 Interest on short-term debt 153 10 46 Capitalized interest (27) (22) (294) Amortization and other financial charges 1 36 78 43 2,588 2,360 2,228 1 Amortization and other financial charges includes 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
JUNIOR SUBORDINATED NOTES (Tables)	Dec. 31, 2022
Junior Subordinated Notes [Abstract]
Schedule of Junior Subordinated Notes	2022 2021 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate 1 Outstanding at December 31 Effective Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED US$1,000 notes issued 2007 at 6.35% 2 2067 1,353 6.2 % 1,265 4.0 % US$750 notes issued 2015 at 5.875% 3,4 2075 1,015 7.4 % 949 5.0 % US$1,200 notes issued 2016 at 6.125% 3,4 2076 1,624 8.0 % 1,519 5.8 % US$1,500 notes issued 2017 at 5.55% 3,4 2077 2,030 7.1 % 1,899 4.7 % $1,500 notes issued 2017 at 4.90% 3,4 2077 1,500 6.8 % 1,500 4.5 % US$1,100 notes issued 2019 at 5.75% 3,4 2079 1,488 7.6 % 1,392 5.4 % $500 notes issued 2021 at 4.45% 3,5 2081 500 5.7 % 500 4.0 % US$800 notes issued 2022 at 5.85% 3,5 2082 1,083 7.2 % — — 10,593 9,024 Unamortized debt discount and issue costs (98) (85) 10,495 8,939 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 billion were issued in 2007 at a fixed rate of 6.35 per cent and converted in 2017 to a floating interest rate that is reset quarterly to the three-month LIBOR plus 2.21 per cent. 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 LOSS_(GAIN),_2

FOREIGN EXCHANGE LOSS/(GAIN), NET (Tables)	12 Months Ended
FOREIGN EXCHANGE LOSS/(GAIN), NET (Tables)	Dec. 31, 2022
Foreign Currency [Abstract]
Schedule of Foreign Exchange Contracts	year ended December 31 2022 2021 2020 (millions of Canadian $) Derivative instruments held for trading (Note 28) 151 (37) (93) Other 34 27 65 185 (10) (28)

NON-CONTROLLING INTERESTS (Tabl

NON-CONTROLLING INTERESTS (Tables)	12 Months Ended
NON-CONTROLLING INTERESTS (Tables)	Dec. 31, 2022
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 loss 353 Non-controlling interests (1,563) Deferred income tax liabilities (443) Other (12)
Schedule of Non-controlling Interests	The Company's Net income attributable to non-controlling interests included in the Consolidated statement of income were as follows: year ended December 31 2022 2021 2020 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP — 60 284 Non-controlling interest in PNGTS 37 30 23 Redeemable non-controlling interest (Note 6) — 1 (10) 37 91 297

COMMON SHARES (Tables)

COMMON SHARES (Tables)	12 Months Ended
COMMON SHARES (Tables)	Dec. 31, 2022
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, 2020 938,400 24,387 Exercise of options 1,664 101 Outstanding at December 31, 2020 940,064 24,488 Acquisition of TC PipeLines, LP, net of transaction costs (Note 23) 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 1 Net of underwriting commissions and deferred income taxes.
Schedule of Weighted Average Shares	Weighted Average Common Shares Outstanding (millions) 2022 2021 2020 Basic 995 973 940 Diluted 996 974 940
Schedule of Stock Options Activity	Number of Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (thousands) (years) Options outstanding at January 1, 2022 7,769 $61.29 Options granted 1,396 $66.49 Options exercised (2,830) $58.09 Options forfeited/expired (226) $63.96 Options Outstanding at December 31, 2022 6,109 $63.86 4.4 Options Exercisable at December 31, 2022 3,175 $63.13 3.4
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 2022 2021 2020 Weighted average fair value $8.24 $7.39 $7.73 Expected life (years) 1 5.4 5.4 5.7 Interest rate 1.6 % 0.5 % 1.5 % Volatility 2 22 % 25 % 17 % Dividend yield 5.5 % 6.0 % 4.2 % 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 2022 2021 2020 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 33 28 31 Total fair value of options that have vested 89 110 101 Total options vested 1.6 million 1.9 million 2.0 million

PREFERRED SHARES (Tables)

PREFERRED SHARES (Tables)	12 Months Ended
PREFERRED SHARES (Tables)	Dec. 31, 2022
Preferred Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Schedule of Preferred Shares	at December 31, 2022 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 2022 2021 2020 (thousands) (millions of Canadian $) Cumulative First Preferred Shares Series 1 14,577 3.479 % $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 1.694 % $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 1.949 % 5 $0.48725 $25.00 January 30, 2026 Series 6 294 294 310 Series 6 1,929 Floating 4 Floating $25.00 January 30, 2026 Series 5 48 48 32 Series 7 24,000 3.903 % $0.97575 $25.00 April 30, 2024 Series 8 589 589 589 Series 9 18,000 3.762 % $0.9405 $25.00 October 30, 2024 Series 10 442 442 442 Series 11 10,000 3.351 % $0.83775 $25.00 November 28, 2025 Series 12 244 244 244 Series 13 — — — — — — — — 493 Series 15 — — — — — — — 988 988 2,499 3,487 3,980 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 6.053 per cent for the period starting December 30, 2022 to, but excluding, March 31, 2023. The floating quarterly dividend rate for the Series 4 preferred shares is 5.413 per cent for the period starting December 30, 2022 to, but excluding, March 31, 2023. The floating quarterly dividend rate for the Series 6 preferred shares is 5.192 per cent for the period starting October 30, 2022 to, but excluding, January 30, 2023. These rates will reset each quarter going forward. 5 The fixed rate dividend for Series 5 preferred shares decreased from 2.263 per cent to 1.949 per cent on January 30, 2021 and is due to reset on every fifth anniversary thereafter.

OTHER COMPREHENSIVE INCOME _ _2

OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 Before Tax Amount Income Tax Recovery/(Expense) 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 and losses on cash flow hedges 63 (21) 42 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 81 (18) 63 Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans 9 (3) 6 Other comprehensive income on equity investments 1,156 (289) 867 Other Comprehensive Income 2,613 (216) 2,397 year ended December 31, 2021 Before Tax Amount Income Tax Recovery/(Expense) 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 and losses on cash flow hedges 68 (13) 55 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 208 (50) 158 Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans 20 (6) 14 Other comprehensive income on equity investments 714 (179) 535 Other Comprehensive Income 894 (252) 642 year ended December 31, 2020 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation gains and losses on net investment in foreign operations (647) 38 (609) Change in fair value of net investment hedges 48 (12) 36 Change in fair value of cash flow hedges (771) 188 (583) Reclassification to net income of gains and losses on cash flow hedges 649 (160) 489 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans 15 (3) 12 Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans 23 (6) 17 Other comprehensive loss on equity investments (373) 93 (280) Other Comprehensive Loss (1,056) 138 (918)
Schedule of Changes in Accumulated Other Comprehensive Income	The changes in AOCI by component were as follows: (millions of Canadian $) Currency Cash Flow Pension and Other Post-Retirement Benefit Plan Adjustments Equity Investments Total 1 AOCI balance at January 1, 2020 (730) (58) (314) (457) (1,559) Other comprehensive (loss)/income before reclassifications 2 (543) (567) 12 (292) (1,390) Amounts reclassified from AOCI — 482 17 11 510 Net current period other comprehensive (loss)/income (543) (85) 29 (281) (880) AOCI balance at December 31, 2020 (1,273) (143) (285) (738) (2,439) Other comprehensive (loss)/income before reclassifications 2 (98) (11) 158 506 555 Amounts reclassified from AOCI — 55 14 28 97 Net current period other comprehensive (loss)/income (98) 44 172 534 652 Acquisition of TC PipeLines, LP 3 362 (13) — 4 353 AOCI balance at December 31, 2021 (1,009) (112) (113) (200) (1,434) Other comprehensive income/(loss) before reclassifications 2 1,450 (39) 63 870 2,344 Amounts reclassified from AOCI 4 — 42 6 (3) 45 Net current period other comprehensive income 1,450 3 69 867 2,389 AOCI balance at December 31, 2022 441 (109) (44) 667 955 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 Other comprehensive income/(loss) before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling interest gains of $8 million (2021 – losses of $12 million; 2020 – losses of $30 million), nil (2021 – gains of $1 million; 2020 – losses of $16 million), and nil (2021 – gains of $1 million; 2020 – gains of $1 million ), respectively. 3 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 23, Non-controlling interests, for additional information. 4 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 $84 million ($64 million, net of tax) at December 31, 2022. 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.
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 2022 2021 2020 (millions of Canadian $) Cash flow hedges Commodities (47) (22) (1) Revenues (Power and Energy Solutions) Interest rate (16) (46) (28) Interest expense Interest rate — — (613) Net gain/(loss) on sale of assets 2 (63) (68) (642) Total before tax 21 13 160 Income tax expense (42) (55) (482) Net of tax 3 Pension and other post-retirement benefit plan adjustments Amortization of actuarial losses (11) (22) (23) Plant operating costs and other 4 Settlement gain 2 2 — Plant operating costs and other 4 (9) (20) (23) Total before tax 3 6 6 Income tax expense (6) (14) (17) Net of tax Equity investments Equity income 4 (37) (15) Income from equity investments (1) 9 4 Income tax expense 3 (28) (11) Net of tax 1 Amounts in parentheses indicate expenses to the Consolidated statement of income. 2 Represents a loss of $613 million ($459 million, net of tax) related to a contractually required derivative instrument used to hedge the interest rate risk associated with project-level financing of the Coastal GasLink construction. The derivative instrument was derecognized as part of the sale of a 65 per cent equity interest in Coastal GasLink LP. Refer to Note 30, Acquisitions and dispositions, for additional information. 3 Amounts reclassified from AOCI on cash flow hedges are net of non-controlling interest of nil (2021 – nil; 2020 – losses of $7 million). 4 These AOCI components are included in the computation of net benefit cost. Refer to Note 27, Employee post-retirement benefits, for additional information.

EMPLOYEE POST-RETIREMENT BENE_2

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)	12 Months Ended
EMPLOYEE POST-RETIREMENT BENEFITS (Tables)	Dec. 31, 2022
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 2022 2021 2020 (millions of Canadian $) DB Plans 78 105 124 Other post-retirement benefit plans 8 8 9 Savings and DC Plans 64 58 58 150 171 191
Schedule of Change in Benefit Obligations, Change in Plan Assets, and Funded Status	The Company's funded status at December 31 was comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2022 2021 2022 2021 Change in Benefit Obligation 1 Benefit obligation – beginning of year 4,027 4,326 419 457 Service cost 145 171 5 6 Interest cost 125 119 13 12 Employee contributions 6 6 2 1 Benefits paid (324) (372) (24) (21) Actuarial gain (949) (208) (120) (35) Curtailment — (5) — 3 Foreign exchange rate changes 51 (10) 15 (4) Benefit obligation – end of year 3,081 4,027 310 419 Change in Plan Assets Plan assets at fair value – beginning of year 4,145 4,038 431 441 Actual return on plan assets (483) 376 (89) 5 Employer contributions 2 78 105 8 8 Employee contributions 6 6 2 1 Benefits paid (324) (372) (24) (21) Foreign exchange rate changes 59 (8) 26 (3) Plan assets at fair value – end of year 3,481 4,145 354 431 Funded Status – Plan Surplus 400 118 44 12 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 Excludes a nil (2021 – $20 million) letter of credit provided to the Canadian DB Plan 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 $) 2022 2021 2022 2021 Other long-term assets (Note 15) 400 119 163 193 Accounts payable and other — — (8) (8) Other long-term liabilities (Note 18) — (1) (111) (173) 400 118 44 12
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 $) 2022 2021 2022 2021 Projected benefit obligation 1 — (2,687) (119) (183) Plan assets at fair value — 2,686 — — Funded Status – Plan Deficit — (1) (119) (183) 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 2022 2021 (millions of Canadian $) Accumulated benefit obligation (2,880) (3,714) Plan assets at fair value 3,481 4,145 Funded Status – Plan Surplus 601 431
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 2022 2021 2022 Fixed income securities 38 % 34 % 25% to 50% Equity securities 44 % 53 % 30% to 55% Other investments 18 % 13 % 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 $) 2022 2021 2022 2021 Fixed income securities 7 7 0.2 % 0.2 % Equity securities 3 5 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 other post-retirement benefits measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. For additional information on the fair value hierarchy, refer to Note 28, Risk management and financial instruments. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2022 2021 2022 2021 2022 2021 2022 2021 2022 2021 Asset Category Cash and Cash Equivalents 55 68 1 2 — — 56 70 1 2 Equity Securities: Canadian 117 269 — 148 — — 117 417 3 9 U.S. 897 649 — 164 — — 897 813 24 18 International 172 126 172 354 — — 344 480 9 10 Global — 111 75 313 — — 75 424 2 9 Emerging 50 25 127 120 — — 177 145 5 3 Fixed Income Securities: Canadian Bonds: Federal — — 221 226 — — 221 226 6 5 Provincial — — 249 331 — — 249 331 6 7 Municipal — — 12 16 — — 12 16 — — Corporate — — 108 147 — — 108 147 3 4 U.S. Bonds: Federal 177 433 158 15 — — 335 448 9 10 Municipal — — 1 1 — — 1 1 — — Corporate 345 67 94 143 — — 439 210 11 5 International: Government 5 6 6 7 — — 11 13 — — Corporate — — 58 73 — — 58 73 1 2 Mortgage backed 36 42 1 5 — — 37 47 1 1 Net forward contracts — — (78) — — — (78) — (2) — Other Investments: Real estate — — — — 336 283 336 283 9 6 Infrastructure — — — — 296 281 296 281 8 6 Private equity funds — — — — — 1 — 1 — — Funds held on deposit 144 150 — — — — 144 150 4 3 1,998 1,946 1,205 2,065 632 565 3,835 4,576 100 100
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, 2020 417 Purchases and sales 100 Realized and unrealized gains 48 Balance at December 31, 2021 565 Purchases and sales 52 Realized and unrealized gains 15 Balance at December 31, 2022 632
Schedule of Estimated Future Benefit Payments	The following are estimated future benefit payments, which reflect expected future service: (millions of Canadian $) Pension Benefits Other Post-Retirement Benefits 2023 210 25 2024 214 24 2025 217 24 2026 221 23 2027 224 23 2028 to 2032 1,160 111
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 2022 2021 2022 2021 Discount rate 5.15 % 3.05 % 5.45 % 3.10 % Rate of compensation increase 3.30 % 2.95 % — —
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 2022 2021 2020 2022 2021 2020 Discount rate 3.05 % 2.70 % 3.20 % 3.10 % 2.80 % 3.35 % Expected long-term rate of return on plan assets 6.10 % 6.15 % 6.40 % 3.25 % 3.00 % 3.50 % Rate of compensation increase 3.00 % 2.60 % 3.00 % — — —
Schedule of Net Benefit Costs	The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans was as follows: year ended December 31 Pension Other Post-Retirement (millions of Canadian $) 2022 2021 2020 2022 2021 2020 Service cost 1 145 171 155 5 6 6 Other components of net benefit cost 1 Interest cost 125 119 133 13 12 14 Expected return on plan assets (239) (234) (230) (14) (13) (14) Amortization of actuarial loss 10 23 21 1 2 2 Amortization of regulatory asset 12 27 25 1 2 2 Curtailment gain — (5) — — — — Settlement gain – AOCI (2) (2) — — — — (94) (72) (51) 1 3 4 Net Benefit Cost Recognized 51 99 104 6 9 10 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: year ended December 31 2022 2021 2020 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Net loss 38 24 147 5 358 22
Schedule of the Pre-Tax Amounts Recognized in OCI	Pre-tax amounts recognized in OCI were as follows: year ended December 31 2022 2021 2020 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Amortization of net loss from AOCI to net income (10) (1) (23) (2) (21) (2) Curtailment — — — 3 — — Settlement 2 — 2 — — — Funded status adjustment (101) 20 (190) (18) (18) 3 (109) 19 (211) (17) (39) 1

RISK MANAGEMENT AND FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	Dec. 31, 2022
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 2022 2021 Fair 1,2 Notional Amount Fair 1,2 Notional Amount (millions of Canadian $, unless otherwise noted) U.S. dollar foreign exchange options (maturing 2023 to 2024) (22) US 3,600 (4) US 3,800 U.S. dollar cross-currency interest rate swaps (maturing 2023 to 2025) 3 (5) US 300 23 US 400 (27) US 3,900 19 US 4,200 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2022, Net income includes net realized gains of $1 million (2021 – 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 2022 2021 (millions of Canadian $, unless otherwise noted) Notional amount 32,500 (US 24,000) 30,700 (US 24,200) Fair value 30,800 (US 22,700) 35,500 (US 28,100) 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, 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. In 2022, TC Energy updated this presentation to a net basis as it better reflects the Company's trading positions and how it manages its business. at December 31, 2021 Power Natural Gas Liquids Foreign Exchange Interest Rate Net sales/(purchases) 1 490 (52) 4 — — Millions of U.S. dollars — — — 6,636 650 Millions of Mexican pesos — — — 5,500 — Maturity dates 2022-2026 2022-2027 2022 2022-2026 2024-2026 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively. In 2022, TC Energy updated this presentation to a net basis as it better reflects the Company's trading positions and how it manages its business.
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 2022 2021 Carrying Amount Fair Value Carrying Fair (millions of Canadian $) Long-term debt, including current portion (Note 20) 1,2 (41,543) (39,505) (38,661) (45,615) Junior subordinated notes (Note 21) (10,495) (9,415) (8,939) (9,236) (52,038) (48,920) (47,600) (54,851) 1 Long-term debt is recorded at amortized cost, except for US$1.6 billion (2021 – nil) that is attributed to hedged risk and recorded at fair value. 2 Net income for 2022 included unrealized gains of $64 million (2021 – nil) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$1.6 billion of long-term debt at December 31, 2022 (2021 – nil). 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 2022 2021 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 — 54 — 26 Maturing within 1-5 years — 106 8 107 Maturing within 5-10 years 1,153 — 1,150 — Maturing after 10 years 77 — 84 — Fair value of equity securities 2,4 749 — 817 — 1,979 160 2,059 133 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, 2022 Cash Flow Hedges Fair Value Hedges Net Held for Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 8) Commodities 2 — — — 597 597 Foreign exchange — — 6 11 17 — — 6 608 614 Other long-term assets (Note 15) 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 17) Commodities 2 (72) — — (584) (656) Foreign exchange — — (31) (158) (189) Interest rate — (26) — — (26) (72) (26) (31) (742) (871) Other long-term liabilities (Note 18) 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 balance sheet classification of the fair value of derivative instruments was as follows: at December 31, 2021 Cash Flow Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 8) Commodities 2 — — 122 122 Foreign exchange — 10 37 47 — 10 159 169 Other long-term assets (Note 15) Commodities 2 — — 8 8 Foreign exchange — 32 6 38 Interest rate 2 — — 2 2 32 14 48 Total Derivative Assets 2 42 173 217 Accounts payable and other (Note 17) Commodities 2 (23) — (138) (161) Foreign exchange — (4) (46) (50) Interest rate (10) — — (10) (33) (4) (184) (221) Other long-term liabilities (Note 18) Commodities 2 (4) — (6) (10) Foreign exchange — (19) (10) (29) Interest rate (8) — — (8) (12) (19) (16) (47) Total Derivative Liabilities (45) (23) (200) (268) Total Derivatives (43) 19 (27) (51) 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 2022 2021 2020 (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 (losses)/gains (244) (7) 45 (2) 130 1 Net realized (losses)/gains 3 (32) — 3 — 20 1 1 Gains and 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 assets or regulatory liabilities. 2 Gains and losses on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income. 3 Realized gains and losses on the sale of LMCI restricted investments are determined using the average cost basis.
Realized Gain (Loss) on Investments	year ended December 31 2022 2021 2020 (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 (losses)/gains (244) (7) 45 (2) 130 1 Net realized (losses)/gains 3 (32) — 3 — 20 1 1 Gains and 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 assets or regulatory liabilities. 2 Gains and losses on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income. 3 Realized gains and 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 $) 2022 2021 2022 2021 Long-term debt (2,101) — 64 — 1 At December 31, 2022 and 2021, 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 2022 2021 2020 (millions of Canadian $) Derivative Instruments Held For Trading 1 Amount of unrealized gains/(losses) in the year Commodities 14 9 (23) Foreign exchange (Note 22 ) (149) (203) 126 Amount of realized gains/(losses) in the year Commodities 759 287 183 Foreign exchange (Note 22 ) (2) 240 (33) Derivative Instruments in Hedging Relationships 2 Amount of realized (losses)/gains in the year Commodities (73) (44) 6 Interest rate (3) (32) (16) 1 Realized and unrealized gains and 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 and losses on foreign exchange held-for-trading derivative instruments are included on a net basis in Foreign exchange (loss)/gain, net. 2 In 2022, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur (2021 – realized loss of $10 million, 2020 – nil). The following table details amounts presented in the Consolidated statement of income in which the effects of fair value or cash flow hedging relationships were recorded: year ended December 31 2022 2021 2020 (millions of Canadian $) Fair Value Hedges Interest rate contracts 1 Hedged items (30) — (3) Derivatives designated as hedging instruments (1) — 1 Cash Flow Hedges Reclassification of losses on derivative instruments from AOCI to Net income 2,3 Commodity contracts 4 (47) (22) (1) Interest rate contracts 1 (16) (46) (648) 1 Presented within Interest expense in the Consolidated statement of income, except for a loss of $613 million recorded in May 2020 related to a contractually required derivative instrument used to hedge the interest rate risk associated with project-level financing for the Coastal GasLink construction. This derivative instrument was derecognized as part of the sale of a 65 per cent equity interest in Coastal GasLink LP. The loss was included in Net gain/(loss) on sale of assets. Refer to Note 30, Acquisitions and dispositions, for additional information. 2 Refer to Note 26, Other comprehensive income/(loss) and accumulated other comprehensive income/(loss), for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests. 3 There are no amounts recognized in earnings that were excluded from effectiveness testing. 4 Presented within Revenues (Power and Energy Solutions) in the Consolidated statement of income.
Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships	The components of OCI (Note 26) related to the change in fair value of derivatives in cash flow hedging relationships before tax and including the portion attributable to non-controlling interests were as follows: year ended December 31 2022 2021 2020 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI 1 Commodities (94) (35) (5) Interest rate 36 22 (766) (58) (13) (771) 1 No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI.
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, 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. at December 31, 2021 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 130 (91) 39 Foreign exchange 85 (54) 31 Interest rate 2 (1) 1 217 (146) 71 Derivative Instrument Liabilities Commodities (171) 91 (80) Foreign exchange (79) 54 (25) Interest rate (18) 1 (17) (268) 146 (122) 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, 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. at December 31, 2021 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative Instrument Assets Commodities 130 (91) 39 Foreign exchange 85 (54) 31 Interest rate 2 (1) 1 217 (146) 71 Derivative Instrument Liabilities Commodities (171) 91 (80) Foreign exchange (79) 54 (25) Interest rate (18) 1 (17) (268) 146 (122) 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, 2022 Quoted Prices in Active Markets 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. at December 31, 2021 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 39 91 — 130 Foreign exchange — 85 — 85 Interest rate — 2 — 2 Derivative Instrument Liabilities Commodities (49) (116) (6) (171) Foreign exchange — (79) — (79) Interest rate — (18) — (18) (10) (35) (6) (51) 1 There were no transfers from Level II to Level III for the year ended December 31, 2021.
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) 2022 2021 Balance at beginning of year (6) (4) Net losses included in Net income (10) (3) Net losses included in OCI (3) — Transfers out of Level III 7 — Settlements 1 1 Balance at End of Year 1 (11) (6) 1 Revenues .

CHANGES IN OPERATING WORKING _2

CHANGES IN OPERATING WORKING CAPITAL (Tables)	12 Months Ended
CHANGES IN OPERATING WORKING CAPITAL (Tables)	Dec. 31, 2022
CHANGES IN OPERATING WORKING CAPITAL
Schedule of changes in operating working capital	year ended December 31 2022 2021 2020 (millions of Canadian $) (Increase)/decrease in Accounts receivable (575) (925) 129 Increase in Inventories (190) (93) (55) Decrease/(increase) in Other current assets 118 (141) (221) (Decrease)/increase in Accounts payable and other (83) 890 (162) Increase/(decrease) in Accrued interest 91 (18) (18) Increase in Operating Working Capital (639) (287) (327)

COMMITMENTS, CONTINGENCIES AN_2

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)	12 Months Ended
COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)	Dec. 31, 2022
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 2022 2021 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas Renewable to 2053 100 — 93 — Bruce Power Renewable to 2065 88 — 88 — Other jointly-owned entities to 2043 81 3 80 4 269 3 261 4 1 TC Energy's share of the potential estimated current or contingent exposure.

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
VARIABLE INTEREST ENTITIES (Tables)	Dec. 31, 2022
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 $) 2022 2021 ASSETS Current Assets Cash and cash equivalents 60 72 Accounts receivable 98 70 Inventories 32 28 Other current assets 14 13 204 183 Plant, Property and Equipment 3,997 3,672 Equity Investments 748 890 Goodwill 449 421 5,398 5,166 LIABILITIES Current Liabilities Accounts payable and other 234 232 Accrued interest 18 17 Current portion of long-term debt 31 29 283 278 Regulatory Liabilities 78 66 Other Long-Term Liabilities 1 1 Deferred Income Tax Liabilities 16 13 Long-Term Debt 2,136 2,025 2,514 2,383 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 $) 2022 2021 Balance sheet Loans receivable from affiliates (Notes 7 and 12) 1 — 1 Equity investments Bruce Power 5,783 4,493 Coastal GasLink (Note 7) 1 — 386 Pipeline equity investments and other 1,148 1,219 Long-term loans receivable from affiliate (Note 7) — 238 Off-balance sheet 2 Bruce Power 3 2,025 974 Coastal GasLink 4 3,300 3,037 Pipeline equity investments 58 171 Maximum exposure to loss 12,314 10,519 1 The pre-impairment balances in Equity investments ($2,798 million) and Loans receivable from affiliates ($250 million) at December 31, 2022 related to TC Energy’s investment in Coastal GasLink LP were reduced to a nil balance and an impairment charge was recognized in fourth quarter 2022 in Impairment of equity investment in the Consolidated statement of income. 2 Includes maximum potential exposure to guarantees and future funding commitments. 3 On March 7, 2022, the IESO verified Bruce Power's Unit 3 MCR program final cost and schedule duration estimate submitted in December 2021. As at December 31, 2022, the maximum exposure includes TC Energy's portion of capital to be invested under the Unit 3 MCR program as well as the expected increase in the capital to be invested under the Asset Management program through 2027. 4 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. The committed capacity under the subordinated loan agreement was $1,262 million as at December 31, 2022 and will increase in the future as required to support the estimated $3.3 billion of additional equity financing requirements through completion of construction of the Coastal GasLink pipeline. The determination of the Company’s maximum exposure to loss involves an estimate of the capital costs to complete the Coastal GasLink pipeline.

DESCRIPTION OF TC ENERGY'S BU_2

DESCRIPTION OF TC ENERGY'S BUSINESS (Details)	12 Months Ended
DESCRIPTION OF TC ENERGY'S BUSINESS (Details)	Dec. 31, 2022 plant segment mi km 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	40,792
Investments of regulated natural gas pipelines (in miles) \| mi	25,347
U.S. Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) \| km	50,164
Investments of regulated natural gas pipelines (in miles) \| mi	31,170
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	2,775
Investments of regulated natural gas pipelines (in miles) \| mi	1,723
Liquids Pipelines
Segment Reporting Information [Line Items]
Wholly owned and operated crude oil pipeline systems (in kilometers) \| km	4,856
Wholly owned and operated crude oil pipeline systems (in miles) \| mi	3,019
Power and Energy Solutions
Segment Reporting Information [Line Items]
Number of electrical power generation plants (in plants) \| plant	4,300
Non-regulated natural gas storage facilities (in billion cubic feet) \| Bcf	118

ACCOUNTING POLICIES (Details)

ACCOUNTING POLICIES (Details)	12 Months Ended
ACCOUNTING POLICIES (Details)	Dec. 31, 2022
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%

SEGMENTED INFORMATION - Schedul

SEGMENTED INFORMATION - Schedule of Segment Reporting Information, by Segment (Details) - CAD ($) $ in Millions		12 Months Ended
	Mar. 15, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segmented information
Revenues		$ 14,977	$ 13,387	$ 12,999
Income from equity investments		1,054	898	1,019
Impairment of equity investment		(3,048)	0	0
Plant operating costs and other		(4,932)	(4,098)	(3,878)
Commodity purchases resold		(534)	(87)	0
Property taxes		(848)	(774)	(727)
Depreciation and amortization		(2,584)	(2,522)	(2,590)
Asset impairment charge and other		(453)	(2,775)	0
Goodwill and asset impairment charges and other		(453)
Net gain/(loss) on sale of assets		0	30	(50)
Segmented Earnings/(Losses)		3,632	4,059	6,773
Interest expense		(2,588)	(2,360)	(2,228)
Allowance for funds used during construction		369	267	349
Foreign exchange gain (loss), net		(185)	10	28
Interest income and other		146	190	185
Income before Income Taxes		1,374	2,166	5,107
Income tax expense		(589)	(120)	(194)
Net Income		785	2,046	4,913
Net income attributable to non-controlling interests		(37)	(91)	(297)
Net Income Attributable to Controlling Interests		748	1,955	4,616
Preferred share dividends		(107)	(140)	(159)
Net Income Attributable to Common Shares		641	1,815	4,457
Capital Spending
Capital expenditures		6,678	5,924	8,013
Capital projects in development		49	0	122
Contributions to equity investments, net of distributions		2,234
Contributions to equity investments		3,433	1,210	765
Capital Spending		8,961	7,134	8,900
Assets		114,348	104,218
Revolving credit facility \| Sur de Texas \| Line of credit \| Joint venture
Capital Spending
Contributions to equity investments, net of distributions	$ 1,200
Intersegment eliminations
Segmented information
Revenues		(144)	(159)	(185)
Corporate
Segmented information
Revenues		(144)	(159)	(185)
Income from equity investments		28	41	86
Impairment of equity investment		0
Plant operating costs and other		124	72	169
Commodity purchases resold		0	0
Property taxes		0	0	0
Depreciation and amortization		0	0	0
Asset impairment charge and other			0
Goodwill and asset impairment charges and other		0
Net gain/(loss) on sale of assets			0	0
Segmented Earnings/(Losses)		8	(46)	70
Capital Spending
Capital expenditures		41	35	58
Capital projects in development		0		0
Contributions to equity investments, net of distributions		0
Contributions to equity investments			0	0
Capital Spending		41	35	58
Assets		3,764	4,203
Canadian Natural Gas Pipelines
Segmented information
Revenues		4,764	4,519	4,469
Canadian Natural Gas Pipelines \| Operating segments
Segmented information
Revenues		4,764	4,519	4,469
Income from equity investments		18	12	12
Impairment of equity investment		(3,048)
Plant operating costs and other		(1,679)	(1,567)	(1,631)
Commodity purchases resold		0	0
Property taxes		(297)	(289)	(284)
Depreciation and amortization		(1,198)	(1,226)	(1,273)
Asset impairment charge and other			0
Goodwill and asset impairment charges and other		0
Net gain/(loss) on sale of assets			0	364
Segmented Earnings/(Losses)		(1,440)	1,449	1,657
Capital Spending
Capital expenditures		3,274	2,629	3,503
Capital projects in development		0		0
Contributions to equity investments, net of distributions		1,445
Contributions to equity investments			108	105
Capital Spending		4,719	2,737	3,608
Assets		27,456	25,452
Canadian Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues		0	0	0
U.S. Natural Gas Pipelines
Segmented information
Revenues		5,933	5,233	5,031
U.S. Natural Gas Pipelines \| Operating segments
Segmented information
Revenues		6,065	5,378	5,196
Income from equity investments		292	244	264
Impairment of equity investment		0
Plant operating costs and other		(1,856)	(1,393)	(1,485)
Commodity purchases resold		0	0
Property taxes		(426)	(367)	(337)
Depreciation and amortization		(887)	(791)	(801)
Asset impairment charge and other			0
Goodwill and asset impairment charges and other		(571)
Net gain/(loss) on sale of assets			0	0
Segmented Earnings/(Losses)		2,617	3,071	2,837
Capital Spending
Capital expenditures		2,137	2,611	2,785
Capital projects in development		0		0
Contributions to equity investments, net of distributions		0
Contributions to equity investments			209	0
Capital Spending		2,137	2,820	2,785
Assets		50,038	45,502
U.S. Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues		(132)	(145)	(165)
Mexico Natural Gas Pipelines
Segmented information
Revenues		688	605	716
Mexico Natural Gas Pipelines \| Operating segments
Segmented information
Revenues		688	605	716
Income from equity investments		122	119	127
Impairment of equity investment		0
Plant operating costs and other		(221)	(55)	(57)
Commodity purchases resold		0	(3)
Property taxes		0	0	0
Depreciation and amortization		(98)	(109)	(117)
Asset impairment charge and other			0
Goodwill and asset impairment charges and other		0
Net gain/(loss) on sale of assets			0	0
Segmented Earnings/(Losses)		491	557	669
Capital Spending
Capital expenditures		1,027	129	173
Capital projects in development		0		0
Contributions to equity investments, net of distributions		0
Contributions to equity investments			0	0
Capital Spending		1,027	129	173
Assets		9,231	7,547
Mexico Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues		0	0	0
Liquids Pipelines
Segmented information
Revenues		2,668	2,306	2,371
Liquids Pipelines \| Operating segments
Segmented information
Revenues		2,668	2,306	2,371
Income from equity investments		55	71	75
Impairment of equity investment		0
Plant operating costs and other		(756)	(700)	(654)
Commodity purchases resold		(512)	(84)
Property taxes		(121)	(113)	(101)
Depreciation and amortization		(329)	(318)	(332)
Asset impairment charge and other			(2,775)
Goodwill and asset impairment charges and other		118
Net gain/(loss) on sale of assets			13	0
Segmented Earnings/(Losses)		1,123	(1,600)	1,359
Capital Spending
Capital expenditures		106	488	1,315
Capital projects in development		0		122
Contributions to equity investments, net of distributions		37
Contributions to equity investments			83	5
Capital Spending		143	571	1,442
Assets		15,587	14,951
Liquids Pipelines \| Intersegment eliminations
Segmented information
Revenues		0	0	0
Power and Energy Solutions
Segmented information
Revenues		924	724	412
Power and Energy Solutions \| Operating segments
Segmented information
Revenues		936	738	432
Income from equity investments		539	411	455
Impairment of equity investment		0
Plant operating costs and other		(544)	(455)	(220)
Commodity purchases resold		(22)	0
Property taxes		(4)	(5)	(5)
Depreciation and amortization		(72)	(78)	(67)
Asset impairment charge and other			0
Goodwill and asset impairment charges and other		0
Net gain/(loss) on sale of assets			17	(414)
Segmented Earnings/(Losses)		833	628	181
Capital Spending
Capital expenditures		93	32	179
Capital projects in development		49		0
Contributions to equity investments, net of distributions		752
Contributions to equity investments			810	655
Capital Spending		894	842	834
Assets		8,272	6,563
Power and Energy Solutions \| Intersegment eliminations
Segmented information
Revenues		$ (12)	$ (14)	$ (20)

SEGMENTED INFORMATION - Revenue

SEGMENTED INFORMATION - Revenue from External Customers by Geographic Areas (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Revenues	$ 14,977	$ 13,387	$ 12,999
Canada – domestic
Segment Reporting Information [Line Items]
Revenues	4,942	4,603	4,392
Canada – export
Segment Reporting Information [Line Items]
Revenues	1,322	1,226	1,059
United States
Segment Reporting Information [Line Items]
Revenues	8,025	6,953	6,832
Mexico
Segment Reporting Information [Line Items]
Revenues	$ 688	$ 605	$ 716

SEGMENTED INFORMATION - Sched_2

SEGMENTED INFORMATION - Schedule of Long-Lived Assets by Country (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Plant, Property and Equipment	$ 75,940	$ 70,182
Canada
Segment Reporting Information [Line Items]
Plant, Property and Equipment	27,232	24,890
United States
Segment Reporting Information [Line Items]
Plant, Property and Equipment	43,505	39,335
Mexico
Segment Reporting Information [Line Items]
Plant, Property and Equipment	$ 5,203	$ 5,957

REVENUES - Disaggregation of Re

REVENUES - Disaggregation of Revenues (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jul. 31, 2022	May 31, 2020
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 14,112	$ 12,952	$ 12,647
Sales-type lease income	127
Other revenues	738	435	352
Revenues	14,977	13,387	12,999
Fee revenue from affiliates			138
Coastal GasLink
Disaggregation of Revenue [Line Items]
Fee revenue from affiliates			$ 61
Ownership interest percentage			35%
Sur de Texas
Disaggregation of Revenue [Line Items]
Fee revenue from affiliates			$ 77
Ownership interest percentage			60%
Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	11,807	11,172	$ 11,522
Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	490	324	192
Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,815	1,456	933
Canadian Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,764	4,519	4,469
Sales-type lease income	0
Other revenues	0	0	0
Revenues	$ 4,764	4,519	4,469
Canadian Natural Gas Pipelines \| Coastal GasLink
Disaggregation of Revenue [Line Items]
Ownership interest percentage	35%			35%	35%
Canadian Natural Gas Pipelines \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 4,696	4,432	4,408
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	68	87	61
Canadian Natural Gas Pipelines \| Coastal GasLink
Disaggregation of Revenue [Line Items]
Fee revenue from affiliates	68	87
U.S. Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5,919	5,196	4,955
Sales-type lease income	0
Other revenues	14	37	76
Revenues	5,933	5,233	5,031
U.S. Natural Gas Pipelines \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,621	4,139	4,301
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	1,298	1,057	654
Mexico Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	561	605	716
Sales-type lease income	127
Other revenues	0	0	0
Revenues	$ 688	605	716
Mexico Natural Gas Pipelines \| Sur de Texas
Disaggregation of Revenue [Line Items]
Ownership interest percentage	60%
Mexico Natural Gas Pipelines \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 507	576	607
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	54	29	109
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,987	2,030	2,209
Sales-type lease income	0
Other revenues	681	276	162
Revenues	2,668	2,306	2,371
Liquids Pipelines \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,983	2,025	2,206
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	4	5	3
Power and Energy Solutions
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	881	602	298
Sales-type lease income	0
Other revenues	43	122	114
Revenues	924	724	412
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	490	324	192
Power and Energy Solutions \| Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	391	$ 278	$ 106
TGNH Pipelines
Disaggregation of Revenue [Line Items]
Other revenues	$ 37

REVENUES - Contract Balances (D

REVENUES - Contract Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 1,907	$ 1,627
Contract assets (Note 8)	155	202
Long-term contract assets (Note 15)	355	249
Contract liabilities (Note 5)	62	90
Long-term contract liabilities (Note 18)	32	184
Revenue recognized	$ 51	$ 95

REVENUES - Remaining Performanc

REVENUES - Remaining Performance Obligations - Narrative (Details) $ in Billions	Dec. 31, 2022 CAD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 23.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 3.8
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 ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 CAD ($)	Jun. 30, 2021 USD ($)	Jan. 31, 2021 USD ($)	Jan. 04, 2021 USD ($)
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net				$ 75,940		$ 70,182
Impairment charge, U.S. minimum income tax				91		0		$ 0
Class A interests issued								1,033
Repurchase of Class A Interests				0		633		0
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 6)						737
Payments to noncontrolling interests				43		16		0
Proceeds from sales of assets, net of transaction costs				0		35		$ 3,407
Coastal GasLink contractual contribution (Notes 7, 11 and 32)				537		0
Additional Paid-In Capital
Property, Plant and Equipment [Line Items]
Keystone XL project-level credit facility retirement and issuance of Class C Interests (Note 6)						737
Aggregate transaction value						(394)
Class C Interests \| Government of Alberta
Property, Plant and Equipment [Line Items]
Payments to noncontrolling interests				43		16
Class A 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]
Impairment charge, U.S. minimum income tax				96
Project Level Credit Facility due June 2021 \| Line of credit \| Keystone XL
Property, Plant and Equipment [Line Items]
Revolving credit facility, borrowing capacity									$ 1,600	$ 4,100	$ 4,100
Proceeds from issuance of debt					$ 849	1,028	$ 849
Keystone XL
Property, Plant and Equipment [Line Items]
Goodwill and asset impairment charges and other				24		192
Changes in asset impairments				(54)
Legal obligations and termination accruals				48
Remaining contractual recoveries				130
Gain (loss) on disposition of property plant equipment				64		0
Proceeds from sales of assets, net of transaction costs				$ 25		16
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]
Goodwill and asset impairment charges and other						2,775
Asset impairment charges, net of tax						2,134
Property, plant and equipment, net						175
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment	$ 75,940	$ 70,182
Asset impairment charge and other, Pre-tax
Goodwill and asset impairment charges and other (Notes 6 and 14)	453	2,775	$ 0
Keystone XL
Asset impairment charge and other, Pre-tax
Contractual recoveries	571
Goodwill and asset impairment charges and other (Notes 6 and 14)	$ 24	192
Keystone XL \| Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment		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 6 and 14)		3,126
Contractual recoveries		(693)
Contractual and legal obligations related to termination activities		342
Goodwill and asset impairment charges and other (Notes 6 and 14)		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		175
Keystone XL \| Fair Value \| Plant and equipment \| Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment		175
Keystone XL \| Fair Value \| Related capital projects in development \| Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment		0
Keystone XL \| Fair Value \| Other capitalized costs \| Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment		0
Keystone XL \| Fair Value \| Capitalized interest \| Liquids Pipelines
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment		$ 0

KEYSTONE XL - Schedule of Redee

KEYSTONE XL - Schedule of Redeemable Non-controlling interest (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Increase (Decrease) in Temporary Equity [Roll Forward]
Balance at beginning of year	$ 0	$ 393
Net income attributable to redeemable non-controlling interest	$ 0	1	$ (10)
Class A Interests repurchased		(394)
Balance at end of year		$ 0	$ 393

COASTAL GASLINK - Narrative (De

COASTAL GASLINK - Narrative (Details) $ in Millions		1 Months Ended	3 Months Ended	12 Months Ended
COASTAL GASLINK - Narrative (Details) $ in Millions	Jul. 28, 2022 CAD ($)	Dec. 31, 2022 CAD ($) Year	Dec. 31, 2022 CAD ($) Year	Dec. 31, 2022 CAD ($) Year	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)	Feb. 01, 2023 CAD ($)	Jul. 31, 2022	May 31, 2020
Equity Investments
Contributions to equity investments				$ 3,433	$ 1,210	$ 765
Impairment of equity investment (Notes 7 and 11)				3,048	0	0
Equity investments		$ 9,535	$ 9,535	9,535	8,441
Coastal GasLink
Equity Investments
Contributions to equity investments	$ 1,900
Additional aggregate cost		$ 3,300	$ 3,300	$ 3,300	3,300
Coastal GasLink \| Expected term \| Discounted cash flow
Equity Investments
Equity method investments, measurement input \| Year		40	40	40
Coastal GasLink \| Accounts payable and other
Equity Investments
Contributions to equity investments		$ 500
Coastal GasLink \| Subordinated Loan Agreement \| Subordinated debt
Equity Investments
Due from affiliates		250	$ 250	$ 250	238
Carrying value		0	0	0
Coastal GasLink \| Coastal GasLink \| Subordinated Loan Agreement \| Subordinated debt
Equity Investments
Revolving credit facility, borrowing capacity		1,262	1,262	1,262
Coastal GasLink \| Subsequent event
Equity Investments
Additional aggregate cost							$ 3,300
Coastal GasLink \| Canadian Natural Gas Pipelines
Equity Investments
Impairment of equity investment (Notes 7 and 11)			3,048
Impairment charges after tax			2,643
Equity investments		$ 2,798	$ 2,798	2,798
Coastal GasLink
Equity Investments
Contributions to equity investments				$ 1,414	92	$ 101
Ownership interest percentage						35%
Coastal GasLink \| Canadian Natural Gas Pipelines
Equity Investments
Ownership interest percentage		35%	35%	35%				35%	35%
Equity investments		$ 0	$ 0	$ 0	$ 386
Coastal GasLink \| Canadian Natural Gas Pipelines \| Subsequent event
Equity Investments
Expected cost of pipeline project							$ 14,500

COASTAL GASLINK - Changes in Lo

COASTAL GASLINK - Changes in Loan Balances (Details) - Subordinated Loan Agreement - Subordinated debt - Coastal GasLink $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)
Related Party Transaction [Roll Forward]
Balance at the beginning	$ 238
Issuances	112
Repayments	(100)
Balance at the end	250
Impairment	(250)
Carrying value	$ 0

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Other Assets [Abstract]
Fair value of derivative contracts (Note 28)	$ 614	$ 169
Current portion of Keystone environmental provision recovery (Note 17)	410	0
Current portion of net investment in leases (Note 10)	291	0
Contract assets (Note 5)	155	202
Keystone XL assets held for sale	122	138
Prepaid expenses	118	112
Cash provided as collateral	106	273
Keystone XL contractual recoveries (Note 6)	86	640
Regulatory assets (Note 13)	67	53
Other	183	130
Other current assets	$ 2,152	$ 1,717

PLANT, PROPERTY AND EQUIPMENT_2

PLANT, PROPERTY AND EQUIPMENT (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Cost	$ 110,569	$ 102,112
Accumulated Depreciation	34,629	31,930
Net Book Value	75,940	70,182
Asset impairment charges	453	2,775	$ 0
TGNH Pipelines
Property, Plant and Equipment [Line Items]
Sales-type lease, net investment in lease, before allowance for credit loss	2,319
Operating segments \| Canadian Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	45,654	42,200
Accumulated Depreciation	22,286	21,175
Net Book Value	23,368	21,025
Asset impairment charges		0
Operating segments \| Canadian Natural Gas Pipelines \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	27,454	24,826
Accumulated Depreciation	9,278	8,521
Net Book Value	18,176	16,305
Operating segments \| Canadian Natural Gas Pipelines \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	15,761	15,379
Accumulated Depreciation	11,384	11,087
Net Book Value	4,377	4,292
Operating segments \| Canadian Natural Gas Pipelines \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	2,439	1,995
Accumulated Depreciation	1,624	1,567
Net Book Value	815	428
Operating segments \| Canadian Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	25,902	22,541
Accumulated Depreciation	9,278	8,521
Net Book Value	16,624	14,020
Operating segments \| Canadian Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	15,492	15,240
Accumulated Depreciation	11,384	11,087
Net Book Value	4,108	4,153
Operating segments \| Canadian Natural Gas Pipelines \| Pipeline \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	18,119	14,892
Accumulated Depreciation	6,285	5,751
Net Book Value	11,834	9,141
Operating segments \| Canadian Natural Gas Pipelines \| Pipeline \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	10,472	10,423
Accumulated Depreciation	7,852	7,698
Net Book Value	2,620	2,725
Operating segments \| Canadian Natural Gas Pipelines \| Compression \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	6,265	6,191
Accumulated Depreciation	2,224	2,065
Net Book Value	4,041	4,126
Operating segments \| Canadian Natural Gas Pipelines \| Compression \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	4,328	4,165
Accumulated Depreciation	3,247	3,125
Net Book Value	1,081	1,040
Operating segments \| Canadian Natural Gas Pipelines \| Metering and other \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	1,518	1,458
Accumulated Depreciation	769	705
Net Book Value	749	753
Operating segments \| Canadian Natural Gas Pipelines \| Metering and other \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	692	652
Accumulated Depreciation	285	264
Net Book Value	407	388
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| NGTL System
Property, Plant and Equipment [Line Items]
Cost	1,552	2,285
Accumulated Depreciation	0	0
Net Book Value	1,552	2,285
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	269	139
Accumulated Depreciation	0	0
Net Book Value	269	139
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	455	58
Accumulated Depreciation	0	0
Net Book Value	455	58
Operating segments \| Canadian Natural Gas Pipelines \| Other \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	1,984	1,937
Accumulated Depreciation	1,624	1,567
Net Book Value	360	370
Operating segments \| U.S. Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	41,289	36,320
Accumulated Depreciation	7,335	6,142
Net Book Value	33,954	30,178
Asset impairment charges		0
Operating segments \| U.S. Natural Gas Pipelines \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	11,098	9,900
Accumulated Depreciation	3,610	3,161
Net Book Value	7,488	6,739
Operating segments \| U.S. Natural Gas Pipelines \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	22,346	19,817
Accumulated Depreciation	1,910	1,437
Net Book Value	20,436	18,380
Operating segments \| U.S. Natural Gas Pipelines \| ANR
Property, Plant and Equipment [Line Items]
Cost	7,845	6,603
Accumulated Depreciation	1,815	1,544
Net Book Value	6,030	5,059
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	10,770	9,367
Accumulated Depreciation	3,610	3,161
Net Book Value	7,160	6,206
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	21,687	19,384
Accumulated Depreciation	1,910	1,437
Net Book Value	19,777	17,947
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| ANR
Property, Plant and Equipment [Line Items]
Cost	7,517	5,770
Accumulated Depreciation	1,815	1,544
Net Book Value	5,702	4,226
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	1,928	1,755
Accumulated Depreciation	760	657
Net Book Value	1,168	1,098
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	12,471	11,205
Accumulated Depreciation	1,069	799
Net Book Value	11,402	10,406
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| ANR
Property, Plant and Equipment [Line Items]
Cost	2,066	1,820
Accumulated Depreciation	641	557
Net Book Value	1,425	1,263
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Columbia Gulf
Property, Plant and Equipment [Line Items]
Cost	3,511	2,749
Accumulated Depreciation	224	178
Net Book Value	3,287	2,571
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| GTN
Property, Plant and Equipment [Line Items]
Cost	2,964	2,701
Accumulated Depreciation	1,239	1,071
Net Book Value	1,725	1,630
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Great Lakes
Property, Plant and Equipment [Line Items]
Cost	2,367	2,162
Accumulated Depreciation	1,387	1,255
Net Book Value	980	907
Operating segments \| U.S. Natural Gas Pipelines \| Compression \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	5,190	4,522
Accumulated Depreciation	495	381
Net Book Value	4,695	4,141
Operating segments \| U.S. Natural Gas Pipelines \| Compression \| ANR
Property, Plant and Equipment [Line Items]
Cost	3,785	2,559
Accumulated Depreciation	734	565
Net Book Value	3,051	1,994
Operating segments \| U.S. Natural Gas Pipelines \| Metering and other \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	4,026	3,657
Accumulated Depreciation	346	257
Net Book Value	3,680	3,400
Operating segments \| U.S. Natural Gas Pipelines \| Metering and other \| ANR
Property, Plant and Equipment [Line Items]
Cost	1,666	1,391
Accumulated Depreciation	440	422
Net Book Value	1,226	969
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	328	533
Accumulated Depreciation	0	0
Net Book Value	328	533
Operating segments \| U.S. Natural Gas Pipelines \| Under construction \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	659	433
Accumulated Depreciation	0	0
Net Book Value	659	433
Operating segments \| U.S. Natural Gas Pipelines \| Under construction \| ANR
Property, Plant and Equipment [Line Items]
Cost	328	833
Net Book Value	328	833
Operating segments \| Mexico Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	5,707	6,653
Accumulated Depreciation	520	711
Net Book Value	5,187	5,942
Asset impairment charges		0
Operating segments \| Mexico Natural Gas Pipelines \| Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost	3,160	4,063
Accumulated Depreciation	520	711
Net Book Value	2,640	3,352
Operating segments \| Mexico Natural Gas Pipelines \| Pipeline
Property, Plant and Equipment [Line Items]
Cost	2,299	2,957
Accumulated Depreciation	348	476
Net Book Value	1,951	2,481
Operating segments \| Mexico Natural Gas Pipelines \| Compression
Property, Plant and Equipment [Line Items]
Cost	374	480
Accumulated Depreciation	59	80
Net Book Value	315	400
Operating segments \| Mexico Natural Gas Pipelines \| Metering and other
Property, Plant and Equipment [Line Items]
Cost	487	626
Accumulated Depreciation	113	155
Net Book Value	374	471
Operating segments \| Mexico Natural Gas Pipelines \| Under construction
Property, Plant and Equipment [Line Items]
Cost	2,547	2,590
Accumulated Depreciation	0	0
Net Book Value	2,547	2,590
Operating segments \| Liquids Pipelines
Property, Plant and Equipment [Line Items]
Cost	14,859	14,034
Accumulated Depreciation	3,222	2,761
Net Book Value	11,637	11,273
Asset impairment charges		2,775
Operating segments \| Liquids Pipelines \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	14,660	13,835
Accumulated Depreciation	3,203	2,747
Net Book Value	11,457	11,088
Operating segments \| Liquids Pipelines \| Intra-Alberta Pipelines
Property, Plant and Equipment [Line Items]
Cost	199	199
Accumulated Depreciation	19	14
Net Book Value	180	185
Operating segments \| Liquids Pipelines \| Property, plant and equipment excluding under construction \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	14,564	13,763
Accumulated Depreciation	3,203	2,747
Net Book Value	11,361	11,016
Operating segments \| Liquids Pipelines \| Pipeline \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	9,777	9,209
Accumulated Depreciation	2,056	1,758
Net Book Value	7,721	7,451
Operating segments \| Liquids Pipelines \| Pumping equipment \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	1,064	1,020
Accumulated Depreciation	288	252
Net Book Value	776	768
Operating segments \| Liquids Pipelines \| Tanks and other \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	3,723	3,534
Accumulated Depreciation	859	737
Net Book Value	2,864	2,797
Operating segments \| Liquids Pipelines \| Under construction \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	96	72
Accumulated Depreciation	0	0
Net Book Value	96	72
Operating segments \| Power and Energy Solutions
Property, Plant and Equipment [Line Items]
Cost	2,160	2,069
Accumulated Depreciation	880	821
Net Book Value	1,280	1,248
Asset impairment charges		0
Operating segments \| Power and Energy Solutions \| Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost	2,080	2,064
Accumulated Depreciation	880	821
Net Book Value	1,200	1,243
Operating segments \| Power and Energy Solutions \| Natural Gas
Property, Plant and Equipment [Line Items]
Cost	1,260	1,267
Accumulated Depreciation	642	605
Net Book Value	618	662
Operating segments \| Power and Energy Solutions \| Natural Gas Storage and Other
Property, Plant and Equipment [Line Items]
Cost	820	797
Accumulated Depreciation	238	216
Net Book Value	582	581
Operating segments \| Power and Energy Solutions \| Under construction
Property, Plant and Equipment [Line Items]
Cost	80	5
Accumulated Depreciation	0	0
Net Book Value	80	5
Corporate
Property, Plant and Equipment [Line Items]
Cost	900	836
Accumulated Depreciation	386	320
Net Book Value	$ 514	516
Asset impairment charges		$ 0

LEASES - (Lessee) Narrative (De

LEASES - (Lessee) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Operating lease termination period	1 year
Right-of-use asset	$ 415	$ 415
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, 2022	Dec. 31, 2021
Operating lease cost
Operating lease cost	$ 106	$ 105
Sublease income	(5)	(8)
Net operating lease cost	101	97
Cash paid for amounts included in the measurement of operating lease liabilities	67	69
ROU assets obtained in exchange for new operating lease liabilities	$ 49	$ 7
Weighted average remaining lease term	8 years	9 years
Weighted average discount rate	3.50%	3.50%

LEASES - (Lessee) Maturities of

LEASES - (Lessee) Maturities of Operating Lease Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Less than one year	$ 68	$ 63
One to two years	65	60
Two to three years	62	58
Three to four years	60	55
Four to five years	54	54
More than five years	187	213
Total operating lease payments	496	503
Imputed interest	(63)	(74)
Operating lease liabilities	433	429
Operating lease, reported as accounts payable and other	54	49
Operating lease, reported as other long-term liabilities	$ 379	$ 380
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts payable and other (Note 17)	Accounts payable and other (Note 17)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other Long-Term Liabilities (Note 18)	Other Long-Term Liabilities (Note 18)

LEASES - (Lessor) Narrative (De

LEASES - (Lessor) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Fixed portion of the operating lease income	$ 118	$ 126	$ 130
Cost for facilities accounted for as operating leases	802	812
Accumulated depreciation for facilities accounted for as operating leases	$ 360	$ 340

LEASES - (Lessor) Future Lease

LEASES - (Lessor) Future Lease Payments to be Received Under Operating Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Less than one year	$ 113	$ 113
One to two years	111	111
Two to three years	94	110
Three to four years	70	94
Four to five years	0	70
Total payments to be received	$ 388	$ 498

LEASES - Sale Type Leases Narra

LEASES - Sale Type Leases Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Expected credit loss provision	$ 163	$ 0	$ 0
TGNH Pipelines
Lessee, Lease, Description [Line Items]
Expected credit loss provision	$ 149	$ 0	$ 0

LEASES - Component of Aggregate

LEASES - Component of Aggregate Investment in Leases (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Lessee, Lease, Description [Line Items]
Minimum lease payments	$ 9,457
Unearned lease income	(7,132)
Lease receivable	2,325
Expected credit loss provision	(150)
Present value of unguaranteed residual value	11
Sales-type lease, net investment in lease, before allowance for credit loss	2,186
Current portion included in Other current assets (Note 8)	(291)
Sales-type lease, net investment in lease, before allowance for credit loss, noncurrent	1,895
Currency Translation Adjustments
Lessee, Lease, Description [Line Items]
Expected credit loss provision	$ 1

LEASES - Sales-Type Leases (Det

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

EQUITY INVESTMENTS - Ownership

EQUITY INVESTMENTS - Ownership Information of Equity Investments (Details) - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jul. 31, 2022	May 31, 2020
Equity Investments
Income from Equity Investments		$ 1,054	$ 898	$ 1,019
Equity Investments		$ 9,535	8,441
TQM \| Canadian Natural Gas Pipelines
Equity Investments
Ownership interest percentage		50%
Income from Equity Investments		$ 17	12	$ 12
Equity Investments		$ 165	118
Coastal GasLink
Equity Investments
Ownership interest percentage				35%
Coastal GasLink \| Canadian Natural Gas Pipelines
Equity Investments
Ownership interest percentage		35%			35%	35%
Income from Equity Investments		$ 1	0	$ 0
Equity Investments		$ 0	386
Northern Border \| U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage		50%
Income from Equity Investments		$ 92	80	100
Equity Investments		$ 516	505
Millennium \| U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage		47.50%
Income from Equity Investments		$ 103	91	96
Equity Investments		$ 500	474
Iroquois \| U.S. Natural Gas Pipelines
Equity Investments
Ownership interest percentage		50%
Income from Equity Investments		$ 77	55	52
Equity Investments		237	392
Other \| U.S. Natural Gas Pipelines
Equity Investments
Income from Equity Investments		20	18	16
Equity Investments		122	137
Other \| Power and Energy Solutions
Equity Investments
Income from Equity Investments		2	0	$ 16
Equity Investments		$ 30	0
Sur de Texas
Equity Investments
Ownership interest percentage				60%
Sur de Texas \| Mexico Natural Gas Pipelines
Equity Investments
Ownership interest percentage		60%
Income from Equity Investments		$ 150	160	$ 213
Equity Investments		$ 1,050	835
Grand Rapids \| Liquids Pipelines
Equity Investments
Ownership interest percentage		50%
Income from Equity Investments		$ 54	54	53
Equity Investments		$ 964	980
Port Neches Link LLC \| Liquids Pipelines
Equity Investments
Ownership interest percentage		95%
Income from Equity Investments		$ 0	0	0
Equity Investments		$ 149	103
HoustonLink Pipeline \| Liquids Pipelines
Equity Investments
Ownership interest percentage		50%
Income from Equity Investments		$ 1	1	0
Equity Investments		19	18
Northern Courier \| Liquids Pipelines
Equity Investments
Income from Equity Investments		0	16	22
Equity Investments		$ 0	0
Ownership interest sold	15%
Bruce Power \| Power and Energy Solutions
Equity Investments
Ownership interest percentage		48.30%
Income from Equity Investments		$ 537	411	$ 439
Equity Investments		$ 5,783	$ 4,493

EQUITY INVESTMENTS - Narrative

EQUITY INVESTMENTS - Narrative (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Feb. 01, 2023
Equity Investments
Impairment of equity investment (Notes 7 and 11)		$ 3,048	$ 0	$ 0
Difference between the carrying value of the investment and the underlying equity in the net assets	$ 299	$ 299	$ 1,109
Coastal GasLink \| Canadian Natural Gas Pipelines \| Subsequent event
Equity Investments
Expected cost of pipeline project					$ 14,500
Coastal GasLink \| Canadian Natural Gas Pipelines
Equity Investments
Impairment of equity investment (Notes 7 and 11)	3,048
Impairment charges after tax	$ 2,643

EQUITY INVESTMENTS - Schedule o

EQUITY INVESTMENTS - Schedule of Distribution Received and Contribution Paid (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Equity Investments
Distributions received from equity investments	$ 3,657	$ 1,048	$ 1,123
Contributions to equity investments	3,433	1,210	765
Equity investments
Equity Investments
Distributions received from equity investments	1,025	975	1,123
Contributions to equity investments	820	1,118	664
Other
Equity Investments
Distributions received from equity investments	228	0	0
Coastal GasLink
Equity Investments
Contributions to equity investments	1,414	92	101
Sur de Texas
Equity Investments
Distributions received from equity investments	2,404	73	0
Contributions to equity investments	$ 1,199	$ 0	$ 0

EQUITY INVESTMENTS - Summarized

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income
Revenues	$ 14,977	$ 13,387	$ 12,999
Operating and other expenses	(9,351)	(10,256)	(7,195)
Net income	748	1,955	4,616
Income from Equity Investments	1,054	898	1,019
Balance Sheet
Current assets	7,332	7,423
Current liabilities	(16,907)	(13,041)
Group of Investees
Income
Revenues	5,891	5,447	5,838
Operating and other expenses	(3,390)	(3,293)	(3,341)
Net income	2,147	1,859	$ 2,047
Balance Sheet
Current assets	3,414	3,498
Non-current assets	37,713	30,165
Current liabilities	(2,856)	(2,540)
Non-current liabilities	$ (17,690)	$ (16,400)

EQUITY INVESTMENTS - Interest i

EQUITY INVESTMENTS - Interest income and foreign exchange impact (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Equity [Abstract]
Difference between the carrying value of the investment and the underlying equity in the net assets	$ 299	$ 1,109

LOANS RECEIVABLE FROM AFFILIA_3

LOANS RECEIVABLE FROM AFFILIATES - Narrative (Details) $ in Millions, $ in Millions	Mar. 15, 2022 CAD ($)	Mar. 15, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Jul. 31, 2022	Dec. 31, 2021 CAD ($)	Dec. 31, 2020	May 31, 2020	Dec. 31, 2017 MXN ($)
Loans and Leases Receivable Disclosure [Line Items]
Loans receivable from affiliates			$ 0		$ 1,217
Revolving credit facility \| Line of credit \| Coastal GasLink
Loans and Leases Receivable Disclosure [Line Items]
Loans receivable from affiliates			$ 0		$ 1
Joint venture \| Revolving credit facility \| Line of credit \| Sur de Texas
Loans and Leases Receivable Disclosure [Line Items]
Revolving credit facility, borrowing capacity								$ 21,300,000,000
Repayments of debt	$ 1,200
Inter-affiliate debt issuance	$ 1,200	$ 938
Sur de Texas
Loans and Leases Receivable Disclosure [Line Items]
Ownership interest percentage						60%
Sur de Texas \| Mexico Natural Gas Pipelines
Loans and Leases Receivable Disclosure [Line Items]
Ownership interest percentage			60%
Coastal GasLink Pipeline Limited Partnership
Loans and Leases Receivable Disclosure [Line Items]
Ownership interest percentage						35%
Coastal GasLink Pipeline Limited Partnership \| Canadian Natural Gas Pipelines
Loans and Leases Receivable Disclosure [Line Items]
Ownership interest percentage			35%	35%			35%
Coastal GasLink
Loans and Leases Receivable Disclosure [Line Items]
Loans receivable from affiliates			$ 250
Coastal GasLink \| Revolving credit facility \| Line of credit
Loans and Leases Receivable Disclosure [Line Items]
Revolving credit facility, borrowing capacity			$ 100

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Loans and Leases Receivable Disclosure [Line Items]
Foreign exchange gains (losses)	$ 185	$ (10)	$ (28)
Sur de Texas \| Interest income and other \| Joint venture
Loans and Leases Receivable Disclosure [Line Items]
Interest income	19	87	110
Sur de Texas \| Foreign exchange loss/(gain), net \| Joint venture
Loans and Leases Receivable Disclosure [Line Items]
Foreign exchange gains (losses)	(28)	(41)	(86)
Sur de Texas \| Income from equity investments \| Joint venture
Loans and Leases Receivable Disclosure [Line Items]
Interest expense	(19)	(87)	(110)
Foreign exchange gains (losses)	$ (28)	$ (41)	$ (86)

RATE-REGULATED BUSINESSES - Nar

RATE-REGULATED BUSINESSES - Narrative (Details) - CAD ($) $ in Millions	1 Months Ended		11 Months Ended	12 Months Ended
	Apr. 30, 2020	Dec. 31, 2018	Nov. 30, 2018	Dec. 31, 2022	Dec. 31, 2014
Columbia Gas Transmission
Public Utilities, General Disclosures [Line Items]
Maximum cost recovery and return on investment				$ 1,200
Remaining Recovery/ Settlement Period (years)				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%	10.10%
Deemed common equity, percent				40%	40%
Unanimous negotiated settlement period	6 years				6 years
After-tax annual contribution to reduce revenue requirement					$ 20
Fixed toll term					6 years
Approved composite depreciation rate		3.90%	3.20%

RATE-REGULATED BUSINESSES - Ass

RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)
Regulatory Assets
Regulatory Assets	$ 1,977		$ 1,820
Less: Current portion included in Other current assets (Note 8)	67		53
Regulatory Assets, noncurrent	1,910		1,767
Regulatory Liabilities
Regulatory Liabilities	4,793		4,500
Less: Current portion included in Accounts payable and other (Note 17)	273		200
Regulatory liabilities, noncurrent	$ 4,520		4,300
Columbia Gas Transmission
Regulatory Liabilities
Remaining Recovery/ Settlement Period (years)	4 years
Pipeline abandonment trust balances
Regulatory Liabilities
Regulatory Liabilities	$ 2,014		2,086
Deferred income taxes - U.S. Tax Reform
Regulatory Liabilities
Regulatory Liabilities	1,197		1,141
Canadian Mainline bridging amortization account
Regulatory Liabilities
Regulatory Liabilities	$ 429		483
Remaining Recovery/ Settlement Period (years)	8 years
Cost of removal
Regulatory Liabilities
Regulatory Liabilities	$ 337		254
Canadian Mainline short-term adjustment and toll-stabilization accounts
Regulatory Liabilities
Regulatory Liabilities	284		60
Canadian Mainline long-term adjustment account
Regulatory Liabilities
Regulatory Liabilities	$ 149		186
Remaining Recovery/ Settlement Period (years)	4 years
Deferred income taxes
Regulatory Liabilities
Regulatory Liabilities	$ 181		139
Operating and debt-service regulatory liabilities
Regulatory Liabilities
Regulatory Liabilities	$ 50		32
Remaining Recovery/ Settlement Period (years)	1 year
Pensions and other post retirement benefits
Regulatory Liabilities
Regulatory Liabilities	$ 10		13
Pensions and other post retirement benefits \| ANR PIPELINE COMPANY
Regulatory Liabilities
Regulatory Liabilities	43		40
Other
Regulatory Liabilities
Regulatory Liabilities	99		66
Long term adjustment account, amount to be amortized over one year
Regulatory Liabilities
Regulatory Liabilities	$ 223
Remaining Recovery/ Settlement Period (years)	6 years
Postretirement benefit costs \| ANR PIPELINE COMPANY
Regulatory Liabilities
Amount to be addressed In next settlement	$ 43	$ 32
Deferred income taxes
Regulatory Assets
Regulatory Assets	1,817		1,509
Pensions and other post retirement benefits
Regulatory Assets
Regulatory Assets	28		203
Foreign exchange on long-term debt
Regulatory Assets
Regulatory Assets	$ 19		3
Foreign exchange on long-term debt \| Minimum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year
Foreign exchange on long-term debt \| Maximum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	7 years
Operating and debt-service regulatory assets
Regulatory Assets
Regulatory Assets	$ 2		1
Remaining Recovery/ Settlement Period (years)	1 year
Other
Regulatory Assets
Regulatory Assets	$ 111		$ 104

GOODWILL - Acquisitions (Detail

GOODWILL - Acquisitions (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)
Goodwill
Balance at the beginning of the period	$ 12,582	$ 9,941
Great Lakes impairment charge	453
Balance at the end of the period	12,843	9,490	$ 12,582
Goodwill, gross	14,578		13,746
Goodwill accumulated impairment loss	1,735		1,164
U.S. Natural Gas Pipelines
Goodwill
Balance at the beginning of the period	12,582		12,679
Foreign exchange rate changes	832		(97)
Balance at the end of the period	12,843		12,582
COLUMBIA PIPELINE GROUP, INC.
Goodwill
Balance at the beginning of the period	9,303	7,351
Balance at the end of the period	9,948	7,351	9,303
ANR PIPELINE COMPANY
Goodwill
Balance at the beginning of the period	2,464	1,946
Balance at the end of the period	2,634	1,946	2,464
Great Lakes
Goodwill
Balance at the beginning of the period	725	573
Balance at the end of the period	165	122	725
Great Lakes \| U.S. Natural Gas Pipelines
Goodwill
Great Lakes impairment charge	(571)
NORTH BAJA PIPELINE, LLC
Goodwill
Balance at the beginning of the period	61	48
Balance at the end of the period	65	48	61
TUSCARORA GAS TRANSMISSION COMPANY
Goodwill
Balance at the beginning of the period	29	23
Balance at the end of the period	$ 31	$ 23	$ 29

GOODWILL - Narrative (Details)

GOODWILL - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
GOODWILL - Narrative (Details) $ in Millions, $ in Millions	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	$ 12,843	$ 12,582		$ 9,490	$ 9,941
Goodwill, expected tax deductible amount	91	0	$ 0
Great Lakes
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	165	725		122	$ 573
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	$ 12,843	$ 12,582	$ 12,679
ANR PIPELINE COMPANY
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill				$ 1,946

OTHER LONG-TERM ASSETS - Summar

OTHER LONG-TERM ASSETS - Summary (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Deferred income tax assets (Note 19)	$ 1,070	$ 509
Employee post-retirement benefits (Note 27)	563	312
Long-term contract assets (Note 5)	355	249
Keystone environmental provision recovery (Note 17)	240	0
Capital projects in development	99	42
Fair value of derivative contracts (Note 28)	91	48
Keystone XL contractual recoveries (Note 6)	44	50
Other	323	193
Total other assets	$ 2,785	$ 1,403

NOTES PAYABLE (Details)

NOTES PAYABLE (Details)	12 Months Ended
NOTES PAYABLE (Details)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 MXN ($)	Nov. 22, 2022 CAD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 MXN ($)
Notes payable
Outstanding	$ 6,262,000,000	$ 5,166,000,000
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	17,000,000	$ 21,000,000
Notes payable
Notes payable
Denominated value	2,810,000,000	1,989,000,000		$ 2,336,000,000			$ 2,341,000,000
Revolving and demand credit facility
Notes payable
Total Facilities	12,900,000,000	12,400,000,000
TCPL \| Revolving credit facility \| Maturing December 2027
Notes payable
Total Facilities	3,000,000,000	3,000,000,000
Unused Capacity	1,700,000,000
TCPL \| Notes payable
Notes payable
Outstanding	$ 5,971,000,000	$ 4,953,000,000
Weighted average interest rate per annum	4.90%	0.40%		4.90%	4.90%		0.40%	0.40%
USA \| Notes payable
Notes payable
Outstanding	$ 0	$ 68,000,000		$ 0			$ 54,000,000
Weighted average interest rate per annum	0%	0.30%		0%	0%		0.30%	0.30%
Mexico subsidiary \| Revolving credit facility
Notes payable
Total Facilities					$ 5,000,000,000			$ 5,000,000,000
Unused Capacity					$ 800,000,000
Mexico subsidiary \| Notes payable
Notes payable
Outstanding	$ 291,000,000	$ 145,000,000		$ 215,000,000			$ 115,000,000
Weighted average interest rate per annum	6%	1.70%		6%	6%		1.70%	1.70%
TCPL / TCPL USA / Columbia / TransCanada American Investments Ltd. \| Revolving credit facility \| Maturing December 2023
Notes payable
Total Facilities				$ 3,000,000,000			$ 4,500,000,000
Unused Capacity				600,000,000
TCPL / TCPL USA / Columbia / TransCanada American Investments Ltd. \| Revolving credit facility \| Maturing December 2025
Notes payable
Total Facilities				2,500,000,000			$ 1,000,000,000
Unused Capacity				$ 2,500,000,000
TCPL / TCPL USA \| Revolving credit facility
Notes payable
Total Facilities	$ 2,100,000,000	$ 2,100,000,000
Unused Capacity	$ 1,000,000,000

ACCOUNTS PAYABLE AND OTHER - Sc

ACCOUNTS PAYABLE AND OTHER - Schedule of Accounts Payable and Other (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Payables and Accruals [Abstract]
Trade payables	$ 4,330	$ 4,183
Fair value of derivative contracts (Note 28)	871	221
Keystone environmental provision	650	0
Coastal GasLink contractual contribution (Notes 7, 11 and 32)	537	0
Regulatory liabilities (Note 13)	273	200
Contract liabilities (Note 5)	62	90
Class C Interests (Note 6)	37	75
Other	389	330
Accounts payable and other	$ 7,149	$ 5,099

ACCOUNTS PAYABLE AND OTHER - Na

ACCOUNTS PAYABLE AND OTHER - Narratives (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Environmental Exit Cost [Line Items]
Environmental remediation liability	$ 650
Keystone environmental provision recovery, current	410	$ 0
Keystone environmental provision recovery, noncurrent	240	$ 0
Other current assets
Environmental Exit Cost [Line Items]
Keystone environmental provision recovery, current	410
Other long-term assets
Environmental Exit Cost [Line Items]
Keystone environmental provision recovery, noncurrent	$ 240

OTHER LONG-TERM LIABILITIES (De

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred Costs, Noncurrent [Abstract]
Operating lease obligations (Note 10)	$ 379	$ 380
Fair value of derivative contracts (Note 28)	151	47
Employee post-retirement benefits (Note 27)	111	174
Asset retirement obligations	79	61
Long-term contract liabilities (Note 5)	32	184
Other	265	213
Other long-term liabilities	$ 1,017	$ 1,059

INCOME TAXES - Geographic Compo

INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Canada	$ (2,154)	$ (292)	$ 691
Foreign	3,528	2,458	4,416
Income before Income Taxes	$ 1,374	$ 2,166	$ 5,107

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	12 Months Ended
INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current
Canada	$ 43	$ 29	$ (54)
Foreign	372	276	306
Total	415	305	252
Deferred
Canada	(467)	(327)	(224)
Foreign	641	142	166
Total	174	(185)	(58)
Income Tax Expense	$ 589	$ 120	$ 194

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income before income taxes	$ 1,374	$ 2,166	$ 5,107
Federal and provincial statutory tax rate	23%	23%	24%
Expected income tax expense	$ 316	$ 498	$ 1,226
Foreign income tax rate differentials	(271)	(230)	(258)
Income tax differential related to regulated operations	(174)	(139)	(228)
Income from non-controlling interests and equity investments	(54)	(70)	(141)
Valuation allowance/(releases)	199	(8)	(400)
Non-taxable capital (gains) and losses	173	0	(62)
Settlement of Mexico prior years' income tax assessments	196	0	0
U.S. minimum tax	96	0	0
Non-deductible goodwill impairment	91	0	0
Impact of Mexico inflationary adjustments	24	32	7
Other	(7)	37	50
Income Tax Expense	$ 589	$ 120	$ 194

INCOME TAXES - Deferred Assets

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred Income Tax Assets
Tax loss and credit carryforwards	$ 1,519	$ 1,163
Regulatory and other deferred amounts	571	537
Unrealized foreign exchange losses on long-term debt	333	130
Other	193	46
Deferred tax assets, gross	2,616	1,876
Less: Valuation allowance	640	229
Deferred tax assets, net of Valuation allowance	1,976	1,647
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment	6,686	5,616
Equity investments	1,152	1,219
Taxes on future revenue requirement	397	333
Financial instruments	126	0
Other	193	112
Deferred tax liabilities, gross	8,554	7,280
Net Deferred Income Tax Liabilities	6,578	5,633
Deferred Income Tax Assets
Other long-term assets (Note 15)	1,070	509
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities	$ 7,648	$ 6,142

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) $ in Millions		1 Months Ended	12 Months Ended
INCOME TAXES - Narrative (Details) $ in Millions	May 22, 2020	May 31, 2020	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2019 USD ($)
Net operating loss carryforwards
Not recognized tax benefits			$ 22,000,000	$ 0
Valuation allowance			640,000,000	229,000,000
Deferred income tax liabilities on the unremitted earnings of foreign investments			1,216,000,000	896,000,000
Income tax payments, net of refunds			394,000,000	371,000,000	$ 252,000,000
Interest expense (recovery) reflected within net tax expense			6,000,000	1,000,000	4,000,000
Accrued interest expense			18,000,000	12,000,000	11,000,000
Income tax penalties expense			0	0	0
Income tax penalties accrued			0	0	0
Coastal GasLink
Net operating loss carryforwards
Decrease in valuation allowance			173,000,000
Disposal group, disposed of by sale, not discontinued operations
Net operating loss carryforwards
Decrease in valuation allowance					$ 400,000,000
Disposal group, disposed of by sale, not discontinued operations \| Coastal GasLink
Net operating loss carryforwards
Ownership interest sold	65%	65%			65%
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards			5,429,000,000	4,067,000,000
Capital loss carryforwards unrecognized			251,000,000	21,000,000
Canada federal and provincial \| Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits			126,000,000	$ 113,000,000
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards							$ 446
Foreign Tax Authority \| Mexican Tax Authority (SAT)
Net operating loss carryforwards
Unused net operating loss carryforwards						$ 69	$ 10
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefit at beginning of year	$ 80	$ 52	$ 29
Gross increases – tax positions in prior years	6	5	26
Gross decreases – tax positions in prior years	0	(1)	(2)
Gross increases – tax positions in current year	7	26	1
Lapse of statutes of limitations	(2)	(2)	(2)
Unrecognized Tax Benefit at End of Year	$ 91	$ 80	$ 52

LONG-TERM DEBT - Amounts Outsta

LONG-TERM DEBT - Amounts Outstanding and Principal Repayments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Debt Instrument [Line Items]
Outstanding	$ 41,706	$ 38,756
Current portion of long-term debt	(1,898)	(1,320)
Unamortized debt discount and issue costs	(239)	(243)
Fair value adjustments	76	148
Noncurrent portion of long-term debt	39,645	37,341
Fair value adjustments of interest rate hedge	64	0
Repayments of Long-term Debt [Abstract]
2023	1,898
2024	2,782
2025	2,827
2026	2,278
2027	3,113
COLUMBIA PIPELINE GROUP, INC.3
Debt Instrument [Line Items]
Fair value adjustments of interest rate hedge	140	148
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	34,998	33,427
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	919	899
Medium Term Notes \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	$ 13,966	$ 12,491
Interest Rate	4.50%	4.20%	4.50%	4.20%
Senior Unsecured Notes \| TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	$ 21,032	$ 20,936	$ 15,542	$ 16,542
Interest Rate	4.90%	4.80%	4.90%	4.80%
Senior Unsecured Notes \| COLUMBIA PIPELINE GROUP, INC.3
Debt Instrument [Line Items]
Outstanding	$ 2,030	$ 1,898	$ 1,500	$ 1,500
Interest Rate	4.90%	4.90%	4.90%	4.90%
Senior Unsecured Notes \| ANR PIPELINE COMPANY
Debt Instrument [Line Items]
Outstanding	$ 1,587	$ 472	$ 1,172	$ 372
Interest Rate	4.10%	5.30%	4.10%	5.30%
Senior Unsecured Notes \| TC PIPELINES, LP
Debt Instrument [Line Items]
Outstanding	$ 1,150	$ 1,076	$ 850
Interest Rate	4.20%	4.20%	4.20%	4.20%
Senior Unsecured Notes \| GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Outstanding	$ 440	$ 411	$ 325	$ 325
Interest Rate	4.30%	4.30%	4.30%	4.30%
Senior Unsecured Notes \| PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Debt Instrument [Line Items]
Outstanding	$ 338	$ 316	$ 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	$ 198	$ 211	$ 146	$ 167
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	$ 271	$ 254	$ 200	$ 200
Interest Rate	7.90%	7.90%	7.90%	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	$ 44	$ 41	$ 33	$ 33
Interest Rate	7.50%	7.50%	7.50%	7.50%
Unsecured Term Loan \| TUSCARORA GAS TRANSMISSION COMPANY
Debt Instrument [Line Items]
Outstanding	$ 46	$ 46	$ 34	$ 36
Interest Rate	6.50%	1.30%	6.50%	1.30%

LONG-TERM DEBT - Issued (Detail

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

1 Months Ended

12 Months Ended

May 22, 2020

May 31, 2022 USD ($)

May 31, 2022 CAD ($)

Oct. 31, 2021 USD ($)

Aug. 31, 2021 USD ($)

Jun. 30, 2021 CAD ($)

Jan. 31, 2021 USD ($)

Oct. 31, 2020 USD ($)

Jun. 30, 2020 USD ($)

May 31, 2020

Apr. 30, 2020 USD ($)

Apr. 30, 2020 CAD ($)

Dec. 31, 2022 USD ($)

Dec. 31, 2021 USD ($)

Dec. 31, 2021 CAD ($)

Dec. 31, 2020 USD ($)

Jul. 31, 2022

Jun. 30, 2021 USD ($)

Jan. 04, 2021 USD ($)

Coastal GasLink

Debt Instrument [Line Items]

Ownership interest percentage

35%

Coastal GasLink | Canadian Natural Gas Pipelines

Debt Instrument [Line Items]

Ownership interest percentage

35%

Disposal group, disposed of by sale, not discontinued operations | Coastal GasLink

Debt Instrument [Line Items]

Ownership interest sold

65%

Medium Term Notes due May 2032 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

$ 800

Interest Rate

5.33%

Medium Term Notes due May 2026 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

$ 400

Interest Rate

4.35%

Medium Term Notes due May 2052 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

$ 300

Interest Rate

5.92%

Senior Unsecured Notes due October 2024 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

$ 1,250

Interest Rate

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

4.186%

Medium Term Notes due April 2030 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

$ 1,250

Interest Rate

4.10%

Medium Term Notes due April 2027 | TRANSCANADA PIPELINES LIMITED

Debt Instrument [Line Items]

Amount

$ 2,000

Interest Rate

3.80%

Senior Unsecured Notes due May 2032 | ANR PIPELINE COMPANY

Debt Instrument [Line Items]

Amount

$ 300

Interest Rate

3.43%

Senior Unsecured Notes due May 2034 | ANR PIPELINE COMPANY

Debt Instrument [Line Items]

Amount

$ 200

Interest Rate

3.58%

Senior Unsecured Notes due May 2037 | ANR PIPELINE COMPANY

Debt Instrument [Line Items]

Amount

$ 200

Interest Rate

3.73%

Senior Unsecured Notes due May 2029 | ANR PIPELINE COMPANY

Debt Instrument [Line Items]

Amount

$ 100

Interest Rate

3.26%

Senior Unsecured Notes due October 2030 | PORTLAND NATURAL GAS TRANSMISSION SYSTEM

Debt Instrument [Line Items]

Amount

$ 125

Interest Rate

2.84%

Senior Unsecured Notes due August 2024 | TUSCARORA GAS TRANSMISSION COMPANY

Debt Instrument [Line Items]

Amount

$ 13

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

Debt Instrument [Line Items]

Amount

$ 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 June 2030 | GAS TRANSMISSION NORTHWEST LLC

Debt Instrument [Line Items]

Amount

$ 175

Interest Rate

3.12%

Senior Secured Credit Facilities due April 2027

Debt Instrument [Line Items]

Amount

$ 1,500

Senior Secured Credit Facilities due April 2027 | Coastal GasLink

Debt Instrument [Line Items]

Amount

$ 1,603

LONG-TERM DEBT - Retired_Repaid

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

1 Months Ended

12 Months Ended

Dec. 31, 2022 CAD ($)

Aug. 31, 2022 CAD ($)

Dec. 31, 2021 CAD ($)

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 ($)

Nov. 30, 2020 CAD ($)

Oct. 31, 2020 USD ($)

Jun. 30, 2020 USD ($)

Mar. 31, 2020 USD ($)

Dec. 31, 2022 USD ($)

Dec. 31, 2021 CAD ($)

Dec. 31, 2021 USD ($)

Mar. 31, 2021 CAD ($)

Dec. 31, 2020 USD ($)

Debt Instrument [Line Items]

Long-term debt

$ 1,600

$ 0

TRANSCANADA PIPELINES LIMITED | Medium Term Note due December 2022

Debt Instrument [Line Items]

Amount

$ 25

Interest Rate

9.95%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due August 2022

Debt Instrument [Line Items]

Amount

$ 1,000

Interest Rate

2.50%

TRANSCANADA PIPELINES LIMITED | Medium Term Note due November 2021

Debt Instrument [Line Items]

Amount

$ 500

Interest Rate

3.65%

TRANSCANADA PIPELINES LIMITED | Debentures due January 2021

Debt Instrument [Line Items]

Amount

$ 400

Interest Rate

9.875%

TRANSCANADA PIPELINES LIMITED | Debentures due November 2020

Debt Instrument [Line Items]

Amount

$ 250

Interest Rate

11.80%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due October 2020

Debt Instrument [Line Items]

Amount

$ 1,000

Interest Rate

3.80%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due March 2020

Debt Instrument [Line Items]

Amount

$ 750

Interest Rate

4.60%

Amortization of debt Issue costs

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

Debt Instrument [Line Items]

Amount

$ 4,040

COLUMBIA PIPELINE GROUP, INC. | Senior Unsecured Notes due June 2020

Debt Instrument [Line Items]

Amount

$ 750

Interest Rate

3.30%

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

Debt Instrument [Line Items]

Amortization of debt Issue costs

$ 5

Debt instrument, face amount

$ 4,200

Amount

$ 4,040

NORTH BAJA PIPELINE, LLC | 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%

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

9.625%

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

Debt Instrument [Line Items]

Amount

$ 10

Interest Rate

9.09%

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

Debt Instrument [Line Items]

Amount

$ 93

PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Unsecured Loan Facility due October 2020

Debt Instrument [Line Items]

Amount

$ 99

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

Debt Instrument [Line Items]

Amount

$ 849

Amount

$ 849

$ 1,028

$ 849

GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes due June 2020

Debt Instrument [Line Items]

Amount

$ 100

Interest Rate

5.29%

LONG-TERM DEBT - Interest Expen

LONG-TERM DEBT - Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Interest Expense [Abstract]
Capitalized interest	$ (27)	$ (22)	$ (294)
Amortization and other financial charges	36	78	43
Interest expense	2,588	2,360	2,228
Interest payments, net of interest capitalized	2,478	2,299	2,203
Short-term debt
Interest Expense [Abstract]
Interest on debt	153	10	46
Long-term debt (excluding junior subordinated notes)
Interest Expense [Abstract]
Interest on debt	1,883	1,841	1,963
Junior subordinated notes
Interest Expense [Abstract]
Interest on debt	$ 543	$ 453	$ 470

JUNIOR SUBORDINATED NOTES (Deta

JUNIOR SUBORDINATED NOTES (Details) $ in Millions	1 Months Ended		12 Months Ended
JUNIOR SUBORDINATED NOTES (Details) $ in Millions	Mar. 31, 2022 USD ($)	Mar. 31, 2021 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	May 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)
Debt Instrument [Line Items]
Outstanding				$ 41,706			$ 38,756
Unamortized debt discount and issue costs				(239)			(243)
Long-term Debt				1,600			0
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding				34,998			33,427
TRANSCANADA PIPELINES LIMITED \| Junior subordinated notes
Debt Instrument [Line Items]
Outstanding				10,593			9,024
Unamortized debt discount and issue costs				(98)			(85)
Long-term Debt				$ 10,495			8,939
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2067
Debt Instrument [Line Items]
Debt converted			$ 1,000,000,000
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2067 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 1,000,000,000
Stated interest rate				6.35%	6.35%
Outstanding				$ 1,353			$ 1,265
Effective Interest Rate				6.20%	6.20%		4%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2067 \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Variable interest rate			2.21%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2075 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 750,000,000
Stated interest rate				5.875%	5.875%
Outstanding				$ 1,015			$ 949
Effective Interest Rate				7.40%	7.40%		5%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2076 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 1,200,000,000
Stated interest rate				6.125%	6.125%
Outstanding				$ 1,624			$ 1,519
Effective Interest Rate				8%	8%		5.80%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2077 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 1,500,000,000
Stated interest rate				5.55%	5.55%
Outstanding				$ 2,030			$ 1,899
Effective Interest Rate				7.10%	7.10%		4.70%
TRANSCANADA PIPELINES LIMITED \| Canadian junior subordinated debt, due 2077 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount				$ 1,500
Stated interest rate				4.90%	4.90%
Outstanding				$ 1,500			$ 1,500
Effective Interest Rate				6.80%	6.80%		4.50%
TRANSCANADA PIPELINES LIMITED \| Junior subordinated debt, due 2079 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 1,100,000,000
Stated interest rate				5.75%	5.75%
Outstanding				$ 1,488			$ 1,392
Effective Interest Rate				7.60%	7.60%		5.40%
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%		4%
TRANSCANADA PIPELINES LIMITED \| $800 notes due 2082 at 5.85% \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 800,000,000
Stated interest rate				5.85%	5.85%
Outstanding				$ 1,083			$ 0
Effective Interest Rate				7.20%	7.20%		0%
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2022-A \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount	$ 800,000,000
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 PIPELINES LIMITED \| 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 PIPELINES LIMITED \| Trust Notes - Series 2021-A \| Period one \| Junior subordinated notes
Debt Instrument [Line Items]
Stated interest rate		4.45%
TRANSCANADA PIPELINES LIMITED \| 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 PIPELINES LIMITED \| 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%
TransCanada Trust \| Trust Notes - Series 2022-A \| Notes payable
Debt Instrument [Line Items]
Debt instrument, face amount	$ 800,000,000
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 \| Notes payable
Debt Instrument [Line Items]
Debt instrument, face amount		$ 500				$ 800,000,000
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 \| Notes payable
Debt Instrument [Line Items]
Stated interest rate, period of time		5 years

FOREIGN EXCHANGE LOSS_(GAIN),_3

FOREIGN EXCHANGE LOSS/(GAIN), NET (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Components of OCI related to derivatives
Foreign exchange gains (losses)	$ 185	$ (10)	$ (28)
Derivative instrument held-for-trading
Components of OCI related to derivatives
Foreign exchange gains (losses)	151	(37)	(93)
Other instruments
Components of OCI related to derivatives
Foreign exchange gains (losses)	$ 34	$ 27	$ 65

NON-CONTROLLING INTERESTS - Nar

NON-CONTROLLING INTERESTS - Narrative (Details)	Mar. 03, 2021 shares	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
TC PipeLines, LP
Non-controlling interests
Common shares issued to common unitholders	0.70
Common shares issued (in shares)	37,955,093
TC PipeLines, LP \| Noncontrolling Interest \| TC PipeLines, LP
Non-controlling interests
Percentage of non-controlling interests			74.50%	74.50%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Noncontrolling Interest \| TC PipeLines, LP
Non-controlling interests
Percentage of non-controlling interests		61.70%

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, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Non-controlling interests
Common shares		$ 28,995	$ 26,716
Common shares
Non-controlling interests
Common shares		$ 28,995	$ 26,716	$ 24,488	$ 24,387
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Non-controlling interests
Redeemable non-controlling interest	$ 0	$ 1	$ (10)
Total non-controlling interests	37	91	297
TC PipeLines, LP
Non-controlling interests
Non-controlling interest	0	60	284
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Non-controlling interests
Non-controlling interest	$ 37	$ 30	$ 23

COMMON SHARES - Reconciliation

COMMON SHARES - Reconciliation and Weighted Average Common Shares Outstanding (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Number of Shares
Outstanding at the beginning of the period (in shares)	981,000
Exercise of options (in shares)	2,830
Acquisition of TC PipeLines, LP, net of transaction costs (Note 22) (in shares)		37,955
Outstanding at the end of the period (in shares)	1,018,000	981,000
Amount
Outstanding at the beginning of the period	$ 26,716
Acquisition of TC PipeLines, LP, net of transaction costs (Note 23)		$ 2,063
Outstanding at the end of the period	$ 28,995	$ 26,716
Common shares
Number of Shares
Outstanding at the beginning of the period (in shares)	980,816	940,064	938,400
Exercise of options (in shares)	2,830	2,797	1,664
Issued under public offering (in shares)	28,400
Dividend reinvestment and share purchase plan (in shares)	5,916
Outstanding at the end of the period (in shares)	1,017,962	980,816	940,064
Amount
Outstanding at the beginning of the period	$ 26,716	$ 24,488	$ 24,387
Exercise of options	183	165	101
Acquisition of TC PipeLines, LP, net of transaction costs (Note 23)		2,063
Issued under public offering	1,754
Dividend reinvestment and share purchase plan	342
Outstanding at the end of the period	$ 28,995	$ 26,716	$ 24,488

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)	31 Months Ended
	Jul. 27, 2022
Equity [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 - TC Energy Corpo

COMMON SHARES - TC Energy Corporation At-the-Market Equity Issuance Program (Details) - At-the-Market Equity Issuance Program	12 Months Ended
	Dec. 31, 2022 CAD ($)
Subsidiary, Sale of Stock [Line Items]
Stock issuance program, period in effect (in months)	25 months
Authorized amount	$ 1,000,000,000

COMMON SHARES - Weighted Averag

COMMON SHARES - Weighted Average Common Shares Outstanding (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Class of Stock [Line Items]
Basic (in shares)	995	973	940
Diluted (in shares)	996	974	940
Common shares
Class of Stock [Line Items]
Basic (in shares)	995	973	940
Diluted (in shares)	996	974	940

COMMON SHARES - Options (Detail

COMMON SHARES - Options (Details)	12 Months Ended
COMMON SHARES - Options (Details)	Dec. 31, 2022 $ / shares shares
Number of Options
Outstanding at the beginning of the period (in shares)	7,769,000
Granted (in shares)	1,396,000
Exercised (in shares)	(2,830,000)
Options forfeited/expired (in shares)	(226,000)
Outstanding at the end of the period (in shares)	6,109,000
Options Exercisable (in shares)	3,175,000
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share) \| $ / shares	$ 61.29
Granted (in Canadian dollars per share) \| $ / shares	66.49
Exercised (in Canadian dollars per share) \| $ / shares	58.09
Options forfeited/expired (in Canadian dollars per share) \| $ / shares	63.96
Outstanding at the end of the period (in Canadian dollars per share) \| $ / shares	63.86
Options Exercisable at December 31, 2020 (in Canadian dollars per share) \| $ / shares	$ 63.13
Weighted Average Remaining Contractual Life
Options Outstanding at December 31, 2022	4 years 4 months 24 days
Options Exercisable at December 31, 2022	3 years 4 months 24 days
Number of shares available for grant (in shares)	3,656,518
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Weighted average fair value (in Canadian dollars per share)	$ 8.24	$ 7.39	$ 7.73
Expected life (years)	5 years 4 months 24 days	5 years 4 months 24 days	5 years 8 months 12 days
Interest rate	1.60%	0.50%	1.50%
Volatility	22%	25%	17%
Dividend yield	5.50%	6%	4.20%
Expense for stock options	$ 10	$ 12	$ 12
Unrecognized compensation costs related to non-vested stock options	$ 12
Expense recognition period	1 year 10 months 24 days

COMMON SHARES - Summary of Addi

COMMON SHARES - Summary of Additional Stock Options Information (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Common Stock, Number of Shares, Par Value and Other Disclosure [Abstract]
Total intrinsic value of options exercised	$ 33	$ 28	$ 31
Total fair value of options that have vested	$ 89	$ 110	$ 101
Total options vested (in shares)	1.6	1.9	2
Options, exercisable, intrinsic value	$ 1
Options, outstanding, intrinsic value	$ 1

COMMON SHARES - Shareholder Rig

COMMON SHARES - Shareholder Rights Plan (Details)	Dec. 31, 2022 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	Dec. 31, 2022	Dec. 31, 2022	May 31, 2022	Dec. 31, 2021	May 31, 2021	Dec. 31, 2020
Class of Stock [Line Items]
Preferred shares			$ 2,499	$ 2,499		$ 3,487		$ 3,980
Series 1
Class of Stock [Line Items]
Number of shares outstanding (in shares)			14,577	14,577
Current yield (as a percent)				3.479%
Annual dividend ( in Canadian dollars per share)				$ 0.86975
Redemption price per share (in Canadian dollars per share)			$ 25	$ 25
Preferred shares			$ 360	$ 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%	1.92%
Series 2
Class of Stock [Line Items]
Number of shares outstanding (in shares)			7,423	7,423
Current yield (as a percent)				6.053%
Redemption price per share (in Canadian dollars per share)			$ 25	$ 25
Preferred shares			$ 179	$ 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%	1.92%
Series 3
Class of Stock [Line Items]
Number of shares outstanding (in shares)			9,997	9,997
Current yield (as a percent)				1.694%
Annual dividend ( in Canadian dollars per share)				$ 0.4235
Redemption price per share (in Canadian dollars per share)			$ 25	$ 25
Preferred shares			$ 246	$ 246		246		246
Series 3 \| Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)			1.28%	1.28%
Series 4
Class of Stock [Line Items]
Number of shares outstanding (in shares)			4,003	4,003
Current yield (as a percent)				5.413%
Redemption price per share (in Canadian dollars per share)			$ 25	$ 25
Preferred shares			$ 97	$ 97		97		97
Series 4 \| Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)			1.28%	1.28%
Series 5
Class of Stock [Line Items]
Number of shares outstanding (in shares)			12,071	12,071
Current yield (as a percent)	1.949%	2.263%		1.949%
Annual dividend ( in Canadian dollars per share)				$ 0.48725
Redemption price per share (in Canadian dollars per share)			$ 25	$ 25
Preferred shares			$ 294	$ 294		294		310
Series 5 \| Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)			1.54%	1.54%
Series 6
Class of Stock [Line Items]
Number of shares outstanding (in shares)			1,929	1,929
Current yield (as a percent)				5.192%
Redemption price per share (in Canadian dollars per share)			$ 25	$ 25
Preferred shares			$ 48	$ 48		48		32
Series 6 \| Government of Canada, Treasury Bill Rate
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)			1.54%	1.54%
Series 7
Class of Stock [Line Items]
Number of shares outstanding (in shares)			24,000	24,000
Current yield (as a percent)				3.903%
Annual dividend ( in Canadian dollars per share)				$ 0.97575
Redemption price per share (in Canadian dollars per share)			$ 25	$ 25
Preferred shares			$ 589	$ 589		589		589
Series 7 \| Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)			2.38%	2.38%
Series 9
Class of Stock [Line Items]
Number of shares outstanding (in shares)			18,000	18,000
Current yield (as a percent)				3.762%
Annual dividend ( in Canadian dollars per share)				$ 0.9405
Redemption price per share (in Canadian dollars per share)			$ 25	$ 25
Preferred shares			$ 442	$ 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%	2.35%
Series 11
Class of Stock [Line Items]
Number of shares outstanding (in shares)			10,000	10,000
Current yield (as a percent)				3.351%
Annual dividend ( in Canadian dollars per share)				$ 0.83775
Redemption price per share (in Canadian dollars per share)			$ 25	$ 25
Preferred shares			$ 244	$ 244		244		244
Series 11 \| Government of Canada, Five-Year Bond Yield
Class of Stock [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum (as a percent)			2.96%	2.96%
Series 13
Class of Stock [Line Items]
Number of shares outstanding (in shares)			0	0
Current yield (as a percent)				0%
Annual dividend ( in Canadian dollars per share)			$ 0.34375	$ 0
Redemption price per share (in Canadian dollars per share)			$ 0	$ 0			$ 25
Preferred shares								493
Series 15
Class of Stock [Line Items]
Number of shares outstanding (in shares)			0	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	$ 0	$ 25
Preferred shares						$ 988		$ 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%	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%	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%	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 USD ($) shares	May 31, 2021 $ / shares shares	Feb. 01, 2021 shares	Jun. 30, 2020 shares	Dec. 31, 2022 $ / shares	Dec. 31, 2022 $ / shares	May 31, 2022 $ / shares	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	$ 25.50
Series 15
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)					0	0	$ 25
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			0	0
Stock redeemed during period (in shares) \| shares		20,000,000
Annual dividend ( in Canadian dollars per share)					0.34375	0
Series 5
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)					25	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	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	25
Annual dividend ( in Canadian dollars per share)						0.4235
Shares converted (in shares) \| shares				401,590
Conversion ratio				1
Series 4
Class of Stock [Line Items]
Redemption price per share (in Canadian dollars per share)					$ 25	$ 25
Shares converted (in shares) \| shares				1,865,362
Conversion ratio				1

OTHER COMPREHENSIVE INCOME _ _3

OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - Components (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Before Tax Amount
Other Comprehensive Income (Loss)	$ 2,613	$ 894	$ (1,056)
Income Tax Recovery/(Expense)
Other Comprehensive Income (Loss)	(216)	(252)	138
Net of Tax Amount
Other comprehensive income/(loss) (Note 26)	2,397	642	(918)
Foreign currency translation gains and losses on net investment in foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications	1,410	(100)	(647)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	84	(8)	38
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	1,494	(108)	(609)
Change in fair value of net investment hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(48)	(3)	48
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	12	1	(12)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(36)	(2)	36
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)	(771)
Reclassification from accumulated other comprehensive Income (loss)	63	68	649
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	19	3	188
Reclassification from AOCI	(21)	(13)	(160)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(39)	(10)	(583)
Reclassification from accumulated other comprehensive income (loss)	42	55	489
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	81	208	15
Reclassification from accumulated other comprehensive Income (loss)	9	20	23
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	(18)	(50)	(3)
Reclassification from AOCI	(3)	(6)	(6)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	63	158	12
Reclassification from accumulated other comprehensive income (loss)	6	14	17
Other comprehensive income on equity investments
Before Tax Amount
Other Comprehensive Income (Loss)	1,156	714	(373)
Income Tax Recovery/(Expense)
Other Comprehensive Income (Loss)	(289)	(179)	93
Net of Tax Amount
Other comprehensive income/(loss) (Note 26)	$ 867	$ 535	$ (280)

OTHER COMPREHENSIVE INCOME _ _4

OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - Reconciliation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	$ 33,271
Other comprehensive income/(loss) (Note 26)	2,397	$ 642	$ (918)
Balance at end of year	33,990	33,271
Cash flow hedge loss to be reclassified within twelve months	(84)
Cash flow hedge loss to be reclassified within twelve months, net of tax	(64)
Currency Translation Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(1,009)	(1,273)	(730)
Other comprehensive (loss) / income, before reclassifications	1,450	(98)	(543)
Amounts reclassified from AOCI	0	0	0
Other comprehensive income/(loss) (Note 26)	1,450	(98)	(543)
Acquisition of TC Pipelines, LP		362
Balance at end of year	441	(1,009)	(1,273)
Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(112)	(143)	(58)
Other comprehensive (loss) / income, before reclassifications	(39)	(11)	(567)
Amounts reclassified from AOCI	42	55	482
Other comprehensive income/(loss) (Note 26)	3	44	(85)
Acquisition of TC Pipelines, LP		(13)
Balance at end of year	(109)	(112)	(143)
Pension and Other Post-Retirement Benefit Plan Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(113)	(285)	(314)
Other comprehensive (loss) / income, before reclassifications	63	158	12
Amounts reclassified from AOCI	6	14	17
Other comprehensive income/(loss) (Note 26)	69	172	29
Acquisition of TC Pipelines, LP		0
Balance at end of year	(44)	(113)	(285)
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(200)	(738)	(457)
Other comprehensive (loss) / income, before reclassifications	870	506	(292)
Amounts reclassified from AOCI	(3)	28	11
Other comprehensive income/(loss) (Note 26)	867	534	(281)
Acquisition of TC Pipelines, LP		4
Balance at end of year	667	(200)	(738)
AOCI Attributable to Parent
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(1,434)	(2,439)	(1,559)
Other comprehensive (loss) / income, before reclassifications	2,344	555	(1,390)
Amounts reclassified from AOCI	45	97	510
Other comprehensive income/(loss) (Note 26)	2,389	652	(880)
Acquisition of TC Pipelines, LP		353
Balance at end of year	955	(1,434)	(2,439)
Accumulated foreign currency adjustment attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive (loss) / income, before reclassifications	8	(12)	(30)
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	1	(16)
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	$ 1	$ 1

OTHER COMPREHENSIVE INCOME _ _5

OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) - Reclassifications (Details) - CAD ($) $ in Millions		1 Months Ended	12 Months Ended
	May 22, 2020	May 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Energy Solutions)			$ 14,977	$ 13,387	$ 12,999
Interest expense			(2,588)	(2,360)	(2,228)
Net gain/(loss) on assets sold/held for sale			0	30	(50)
Total before tax			1,374	2,166	5,107
Income tax expense			(589)	(120)	(194)
Net Income Attributable to Common Shares			641	1,815	4,457
Plant operating costs and other			4,932	4,098	3,878
Income from equity investments			1,054	898	1,019
Reclassification to net income of gains and losses on cash flow hedges			(42)	(55)	$ (489)
Disposal group, disposed of by sale, not discontinued operations \| Coastal GasLink
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net gain/(loss) on assets sold/held for sale		$ 364
Ownership interest sold	65%	65%			65%
Interest rate
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Change in fair value of derivative instruments recognized in OCI		$ (613)		(613)
Reclassification to net income of gains and losses on cash flow hedges				(459)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax			(63)	(68)	$ (642)
Income tax expense			21	13	160
Net Income Attributable to Common Shares			(42)	(55)	(482)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Cash flow hedges \| Interest rate
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense			(16)	(46)	(28)
Net gain/(loss) on assets sold/held for sale			0	0	(613)
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			(9)	(20)	(23)
Income tax expense			3	6	6
Net Income Attributable to Common Shares			(6)	(14)	(17)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Amortization of actuarial losses
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other			(11)	(22)	(23)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Settlement gain
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other			2	2	0
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax expense			(1)	9	4
Net Income Attributable to Common Shares			3	(28)	(11)
Income from equity investments			4	(37)	(15)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Accumulated net gain (loss) from cash flow hedges attributable to noncontrolling interest
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income Attributable to Common Shares			0	0	7
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)			$ (47)	$ (22)	$ (1)

EMPLOYEE POST-RETIREMENT BENE_3

EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments, Changes and Balance Sheet Presentation (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized	12 years	11 years	11 years
Expense for savings plan and DC Plans	$ 64,000,000	$ 58,000,000	$ 58,000,000
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Savings and DC Plans	64,000,000	58,000,000	58,000,000
Total cash contributions	150,000,000	171,000,000	$ 191,000,000
Gain (loss) due to settlement		81,000,000
Net periodic benefit cost, settlement charge		18,000,000
Change in Plan Assets
Plan assets at fair value – beginning of year	4,576,000,000
Plan assets at fair value – end of year	3,835,000,000	4,576,000,000
Amounts recognized in the Balance Sheet
Other long-term assets (Note 15)	563,000,000	312,000,000
Other long-term liabilities (Note 18)	(111,000,000)	$ (174,000,000)
Company's expected funding contributions for savings plan and DC Plans	$ 69,000,000
Pension Benefit Plans
Employee post-retirement benefits
Consecutive period of employment for highest average earnings	3 years
Expected average remaining service life of employees over which past service costs are amortized	9 years	10 years	9 years
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans	$ 78,000,000	$ 105,000,000	$ 124,000,000
Total amount outstanding under letters of credit	0	20,000,000
Settlement gain (loss), before tax	(2,000,000)	(2,000,000)	0
Curtailment gain	0	5,000,000	0
Net benefit cost recognized	51,000,000	99,000,000	104,000,000
Change in Benefit Obligation
Benefit obligation – beginning of year	4,027,000,000	4,326,000,000
Service cost	145,000,000	171,000,000	155,000,000
Interest cost	125,000,000	119,000,000	133,000,000
Employee contributions	6,000,000	6,000,000
Benefits paid	(324,000,000)	(372,000,000)
Actuarial gain	(949,000,000)	(208,000,000)
Curtailment	0	(5,000,000)
Foreign exchange rate changes	51,000,000	(10,000,000)
Benefit obligation – end of year	3,081,000,000	4,027,000,000	4,326,000,000
Change in Plan Assets
Plan assets at fair value – beginning of year	4,145,000,000	4,038,000,000
Actual return on plan assets	(483,000,000)	376,000,000
Employer contributions	78,000,000	105,000,000
Employee contributions	6,000,000	6,000,000
Benefits paid	(324,000,000)	(372,000,000)
Foreign exchange rate changes	59,000,000	(8,000,000)
Plan assets at fair value – end of year	3,481,000,000	4,145,000,000	4,038,000,000
Funded Status – Plan Surplus	$ 400,000,000	$ 118,000,000
Discount rate	5.15%	3.05%
Amounts recognized in the Balance Sheet
Other long-term assets (Note 15)	$ 400,000,000	$ 119,000,000
Accounts payable and other	0	0
Other long-term liabilities (Note 18)	0	(1,000,000)
Net	400,000,000	118,000,000
Company's expected funding contributions	32,000,000
Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans	8,000,000	8,000,000	9,000,000
Settlement gain (loss), before tax	0	0	0
Curtailment gain	0	0	0
Net benefit cost recognized	6,000,000	9,000,000	10,000,000
Change in Benefit Obligation
Benefit obligation – beginning of year	419,000,000	457,000,000
Service cost	5,000,000	6,000,000	6,000,000
Interest cost	13,000,000	12,000,000	14,000,000
Employee contributions	2,000,000	1,000,000
Benefits paid	(24,000,000)	(21,000,000)
Actuarial gain	(120,000,000)	(35,000,000)
Curtailment	0	3,000,000
Foreign exchange rate changes	15,000,000	(4,000,000)
Benefit obligation – end of year	310,000,000	419,000,000	457,000,000
Change in Plan Assets
Plan assets at fair value – beginning of year	431,000,000	441,000,000
Actual return on plan assets	(89,000,000)	5,000,000
Employer contributions	8,000,000	8,000,000
Employee contributions	2,000,000	1,000,000
Benefits paid	(24,000,000)	(21,000,000)
Foreign exchange rate changes	26,000,000	(3,000,000)
Plan assets at fair value – end of year	354,000,000	431,000,000	441,000,000
Funded Status – Plan Surplus	$ 44,000,000	$ 12,000,000
Discount rate	5.45%	3.10%
Amounts recognized in the Balance Sheet
Other long-term assets (Note 15)	$ 163,000,000	$ 193,000,000
Accounts payable and other	(8,000,000)	(8,000,000)
Other long-term liabilities (Note 18)	(111,000,000)	(173,000,000)
Net	44,000,000	12,000,000
Company's expected funding contributions	6,000,000
Canadian \| Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Letter of credit to the DB Plan	0	20,000,000	$ 13,000,000
Total amount outstanding under letters of credit	$ 322,000,000
United States \| Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Settlement gain (loss), before tax		2,000,000
Curtailment gain		5,000,000
United States \| Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Settlement gain (loss), before tax		3,000,000
Curtailment gain		3,000,000
Net benefit cost recognized		$ 0

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Benefit obligation and fair value of plan assets for plans that are not fully funded
Plan assets at fair value	$ 3,835	$ 4,576
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	$ (3,081)	$ (4,027)	$ (4,326)
Plan assets at fair value	3,481	4,145	4,038
Funded Status – Plan Surplus	400	118
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(2,880)	(3,714)
Plan assets at fair value	3,481	4,145
Funded Status – Plan Surplus	$ 601	$ 431
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	38%	34%
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	25%
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%	53%
Company debt or common shares included in plan assets, amount	$ 3	$ 5
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	18%	13%
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	$ (2,687)
Plan assets at fair value	0	2,686
Funded Status – Plan Surplus	0	(1)
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	(310)	(419)	(457)
Plan assets at fair value	354	431	$ 441
Funded Status – Plan Surplus	44	12
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	(119)	(183)
Plan assets at fair value	0	0
Funded Status – Plan Surplus	$ (119)	$ (183)

EMPLOYEE POST-RETIREMENT BENE_5

EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Employee post-retirement benefits
Fair value of plan assets	$ 3,835	$ 4,576
Percentage of Total Portfolio	100%	100%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 1,998	$ 1,946
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1,205	2,065
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	632	565	$ 417
Cash and Cash Equivalents
Employee post-retirement benefits
Fair value of plan assets	$ 56	$ 70
Percentage of Total Portfolio	1%	2%
Cash and Cash Equivalents \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 55	$ 68
Cash and Cash Equivalents \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1	2
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	$ 117	$ 417
Percentage of Total Portfolio	3%	9%
Equity Securities, Canadian \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 117	$ 269
Equity Securities, Canadian \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	148
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	$ 897	$ 813
Percentage of Total Portfolio	24%	18%
Equity Securities, U.S. \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 897	$ 649
Equity Securities, U.S. \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	164
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	$ 344	$ 480
Percentage of Total Portfolio	9%	10%
Equity Securities, International \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 172	$ 126
Equity Securities, International \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	172	354
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	$ 75	$ 424
Percentage of Total Portfolio	2%	9%
Equity Securities, Global \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 111
Equity Securities, Global \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	75	313
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	$ 177	$ 145
Percentage of Total Portfolio	5%	3%
Equity Securities, Emerging \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 50	$ 25
Equity Securities, Emerging \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	127	120
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	$ 221	$ 226
Percentage of Total Portfolio	6%	5%
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	221	226
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	$ 249	$ 331
Percentage of Total Portfolio	6%	7%
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	249	331
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	$ 12	$ 16
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	12	16
Fixed Income Securities, Canadian Bonds, Municipal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Corporate
Employee post-retirement benefits
Fair value of plan assets	$ 108	$ 147
Percentage of Total Portfolio	3%	4%
Fixed Income Securities, Canadian Bonds, Corporate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Corporate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	108	147
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	$ 335	$ 448
Percentage of Total Portfolio	9%	10%
Fixed Income Securities, U.S. Bonds, Federal \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 177	$ 433
Fixed Income Securities, U.S. Bonds, Federal \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	158	15
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	$ 439	$ 210
Percentage of Total Portfolio	11%	5%
Fixed Income Securities, U.S. Bonds, Corporate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 345	$ 67
Fixed Income Securities, U.S. Bonds, Corporate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	94	143
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	$ 11	$ 13
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	$ 5	$ 6
Fixed Income Securities, International, Government \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	6	7
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	$ 58	$ 73
Percentage of Total Portfolio	1%	2%
Fixed Income Securities, International, Corporate \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, International, Corporate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	58	73
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	$ 37	$ 47
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	$ 36	$ 42
Fixed Income Securities, International, Mortgage-backed \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1	5
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	$ (78)	$ 0
Percentage of Total Portfolio	(2.00%)	0%
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	(78)	0
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	$ 336	$ 283
Percentage of Total Portfolio	9%	6%
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	336	283
Infrastructure
Employee post-retirement benefits
Fair value of plan assets	$ 296	$ 281
Percentage of Total Portfolio	8%	6%
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	296	281
Private equity funds
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 1
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	0	1
Funds held on deposit
Employee post-retirement benefits
Fair value of plan assets	$ 144	$ 150
Percentage of Total Portfolio	4%	3%
Funds held on deposit \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 144	$ 150
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, 2022	Dec. 31, 2021
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	$ 4,576
Plan assets at fair value – end of year	3,835	$ 4,576
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	565	417
Purchases and sales	52	100
Realized and unrealized gains	15	48
Plan assets at fair value – end of year	$ 632	$ 565

EMPLOYEE POST-RETIREMENT BENE_7

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for savings plan and DC Plans	$ 69
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits	6.10%
Percentage level to which average annual rate was assumed to decrease	4.80%
Pension Benefit Plans
DB Plans
Company's expected funding contributions	$ 32
Estimated future benefit payments, which reflect expected future service
2023	210
2024	214
2025	217
2026	221
2027	224
2028 to 2032	$ 1,160
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	5.15%	3.05%
Rate of compensation increase	3.30%	2.95%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	3.05%	2.70%	3.20%
Expected long-term rate of return on plan assets	6.10%	6.15%	6.40%
Rate of compensation increase	3%	2.60%	3%
Net benefit cost
Service cost	$ 145	$ 171	$ 155
Other components of net benefit cost
Interest cost	125	119	133
Expected return on plan assets	(239)	(234)	(230)
Amortization of actuarial loss	10	23	21
Amortization of regulatory asset	12	27	25
Curtailment gain	0	(5)	0
Settlement gain – AOCI	(2)	(2)	0
Other components of net benefit cost	(94)	(72)	(51)
Net Benefit Cost Recognized	51	99	104
Pre-tax amounts recognized in AOCI
Net loss	38	147	358
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to net income	(10)	(23)	(21)
Curtailment	0	0	0
Settlement	2	2	0
Funded status adjustment	(101)	(190)	(18)
Total pre-tax amounts recognized in OCI	(109)	$ (211)	$ (39)
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	6
Estimated future benefit payments, which reflect expected future service
2023	25
2024	24
2025	24
2026	23
2027	23
2028 to 2032	$ 111
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	5.45%	3.10%
Rate of compensation increase	0%	0%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	3.10%	2.80%	3.35%
Expected long-term rate of return on plan assets	3.25%	3%	3.50%
Rate of compensation increase	0%	0%	0%
Net benefit cost
Service cost	$ 5	$ 6	$ 6
Other components of net benefit cost
Interest cost	13	12	14
Expected return on plan assets	(14)	(13)	(14)
Amortization of actuarial loss	1	2	2
Amortization of regulatory asset	1	2	2
Curtailment gain	0	0	0
Settlement gain – AOCI	0	0	0
Other components of net benefit cost	1	3	4
Net Benefit Cost Recognized	6	9	10
Pre-tax amounts recognized in AOCI
Net loss	24	5	22
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to net income	(1)	(2)	(2)
Curtailment	0	3	0
Settlement	0	0	0
Funded status adjustment	20	(18)	3
Total pre-tax amounts recognized in OCI	$ 19	$ (17)	$ 1

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, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Derivative [Line Items]
Fair Value	$ (317)	$ (51)
Designated as a net investment hedge
Derivative [Line Items]
Fair Value	(27)	19
Designated as a net investment hedge \| US$ denominated
Derivative [Line Items]
Notional Amount			$ 3,900	$ 4,200
U.S. dollar foreign exchange options (maturing 2023 to 2024) \| Designated as a net investment hedge
Derivative [Line Items]
Fair Value	(22)	(4)
U.S. dollar foreign exchange options (maturing 2023 to 2024) \| Designated as a net investment hedge \| US$ denominated
Derivative [Line Items]
Notional Amount			3,600	3,800
U.S. dollar cross-currency interest rate swaps (maturing 2023 to 2025) \| Designated as a net investment hedge
Derivative [Line Items]
Fair Value	(5)	23
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			$ 300	$ 400
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, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)
Derivative [Line Items]
Notional amount	$ 32,500		$ 30,700
Fair value	$ 30,800		$ 35,500
US$ denominated
Derivative [Line Items]
Notional amount		$ 24,000		$ 24,200
Fair value		$ 22,700		$ 28,100

RISK MANAGEMENT AND FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Expected credit loss provision	$ 163,000,000	$ 0	$ 0
Provision for other credit losses	0	0
Financing receivable, recorded investment, past due	0	0
TGNH Pipelines
Derivative [Line Items]
Expected credit loss provision	149,000,000	0	0
Mexico Natural Gas Pipelines
Derivative [Line Items]
Expected credit loss provision	$ 14,000,000	$ 0	$ 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, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 USD ($)
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	$ (41,706)	$ (38,756)
Junior subordinated notes (Note 21)	(10,495)	(8,939)
Long-term debt	1,600	0
Interest rate swap agreements
Carrying and fair values of non-derivative financial instruments
Hedged items	64	0
Long-term debt hedged		0	$ 1.6
Level II \| Carrying Amount
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	(41,543)	(38,661)
Junior subordinated notes (Note 21)	(10,495)	(8,939)
Total liabilities	(52,038)	(47,600)
Level II \| Fair Value
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	(39,505)	(45,615)
Junior subordinated notes (Note 21)	(9,415)	(9,236)
Total liabilities	$ (48,920)	$ (54,851)

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Total Derivatives
Derivative Assets	$ 705	$ 217
Derivative Liabilities	(1,022)	(268)
Total Derivatives	(317)	(51)
Total trading activity
Total Derivatives
Derivative Assets	685	173
Derivative Liabilities	(837)	(200)
Total Derivatives	(152)	(27)
Cash Flow Hedges
Total Derivatives
Derivative Assets	0	2
Derivative Liabilities	(74)	(45)
Total Derivatives	(74)	(43)
Net Investment Hedges
Total Derivatives
Derivative Assets	8	42
Derivative Liabilities	(35)	(23)
Total Derivatives	(27)	19
Other current assets
Total Derivatives
Derivative Assets	614	169
Other current assets \| Total trading activity
Total Derivatives
Derivative Assets	608	159
Other current assets \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Net Investment Hedges
Total Derivatives
Derivative Assets	6	10
Other current assets \| Commodities
Total Derivatives
Derivative Assets	597	122
Other current assets \| Commodities \| Commodities
Total Derivatives
Derivative Assets	597	122
Other current assets \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Foreign exchange
Total Derivatives
Derivative Assets	17	47
Other current assets \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Assets	11	37
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	6	10
Other long-term assets
Total Derivatives
Derivative Assets	91	48
Other long-term assets \| Total trading activity
Total Derivatives
Derivative Assets	77	14
Other long-term assets \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	2
Other long-term assets \| Net Investment Hedges
Total Derivatives
Derivative Assets	2	32
Other long-term assets \| Commodities
Total Derivatives
Derivative Assets	62	8
Other long-term assets \| Commodities \| Commodities
Total Derivatives
Derivative Assets	62	8
Other long-term assets \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	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	17	38
Other long-term assets \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Assets	15	6
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	2	32
Other long-term assets \| Interest rate
Total Derivatives
Derivative Assets	12	2
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	2
Other long-term assets \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Accounts payable and other
Total Derivatives
Derivative Liabilities	(871)	(221)
Accounts payable and other \| Total trading activity
Total Derivatives
Derivative Liabilities	(742)	(184)
Accounts payable and other \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(72)	(33)
Accounts payable and other \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	(31)	(4)
Accounts payable and other \| Commodities
Total Derivatives
Derivative Liabilities	(656)	(161)
Accounts payable and other \| Commodities \| Commodities
Total Derivatives
Derivative Liabilities	(584)	(138)
Accounts payable and other \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(72)	(23)
Accounts payable and other \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Foreign exchange
Total Derivatives
Derivative Liabilities	(189)	(50)
Accounts payable and other \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Liabilities	(158)	(46)
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	(31)	(4)
Accounts payable and other \| Interest rate
Total Derivatives
Derivative Liabilities	(26)	(10)
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	(10)
Accounts payable and other \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities
Total Derivatives
Derivative Liabilities	(151)	(47)
Other long-term liabilities \| Total trading activity
Total Derivatives
Derivative Liabilities	(95)	(16)
Other long-term liabilities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(2)	(12)
Other long-term liabilities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	(4)	(19)
Other long-term liabilities \| Commodities
Total Derivatives
Derivative Liabilities	(77)	(10)
Other long-term liabilities \| Commodities \| Commodities
Total Derivatives
Derivative Liabilities	(75)	(6)
Other long-term liabilities \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(2)	(4)
Other long-term liabilities \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Foreign exchange
Total Derivatives
Derivative Liabilities	(24)	(29)
Other long-term liabilities \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Liabilities	(20)	(10)
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	(4)	(19)
Other long-term liabilities \| Interest rate
Total Derivatives
Derivative Liabilities	(50)	(8)
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	(8)
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	749	817
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized (losses)/gains	(244)	45	$ 130
Net realized (losses)/ gains	(32)	3	20
Other Restricted Investments
Fair value
Fair value of equity securities	0	0
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized (losses)/gains	(7)	(2)	1
Net realized (losses)/ gains	0	0	$ 1
Fixed income securities \| LMCI Restricted Investments
Fair value
Maturing within 1 year	0	0
Maturing within 1-5 years	0	8
Maturing within 5-10 years	1,153	1,150
Maturing after 10 years	77	84
Fair value of securities	1,979	2,059
Fixed income securities \| Other Restricted Investments
Fair value
Maturing within 1 year	54	26
Maturing within 1-5 years	106	107
Maturing within 5-10 years	0	0
Maturing after 10 years	0	0
Fair value of securities	$ 160	$ 133

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Fair Value Hedging Relationships (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
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	(2,101)	0
Long-term debt \| Fair Value
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability	$ 64	$ 0

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional and Maturity Summary (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) GWh Bcf MMBbls	Dec. 31, 2021 USD ($) GWh MMBbls Bcf	Dec. 31, 2022 MXN ($)	Dec. 31, 2021 MXN ($)
Foreign exchange
Derivative [Line Items]
Notional amount	$ 5,997	$ 6,636	$ 9,747	$ 5,500
Interest rate
Derivative [Line Items]
Notional amount	$ 1,600	$ 650	$ 0	$ 0
Power \| Commodities \| Sales
Derivative [Line Items]
Notional amount, energy (gwh) \| GWh	673	490
Natural Gas \| Commodities \| Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| Bcf	96	52
Liquids \| Commodities \| Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| MMBbls	11	4

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Gain (loss) on cash flow hedge	$ 0	$ 10,000,000	$ 0
Commodities
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	14,000,000	9,000,000	(23,000,000)
Amount of realized gains/(losses) in the year	759,000,000	287,000,000	183,000,000
Commodities \| Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	(73,000,000)	(44,000,000)	6,000,000
Foreign exchange
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	(149,000,000)	(203,000,000)	126,000,000
Amount of realized gains/(losses) in the year	(2,000,000)	240,000,000	(33,000,000)
Interest rate \| Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	$ (3,000,000)	$ (32,000,000)	$ (16,000,000)

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ (58)	$ (13)	$ (771)
Commodities
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	(94)	(35)	(5)
Interest rate
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ 36	$ 22	$ (766)

RISK MANAGEMENT AND FINANCIA_12

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Effect of Fair Value and Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions		1 Months Ended	12 Months Ended
	May 22, 2020	May 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disposal group, disposed of by sale, not discontinued operations \| Coastal GasLink
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Ownership interest sold	65%	65%			65%
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Change in fair value of derivative instruments recognized in OCI		$ (613)		$ (613)
Interest rate contracts \| Interest Expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged items			$ (30)	0	$ (3)
Derivatives designated as hedging instruments			(1)	0	1
Reclassification of gains/(losses) on derivative instruments from AOCI to net income			(16)	(46)	(648)
Commodity contracts \| Revenue
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification of gains/(losses) on derivative instruments from AOCI to net income			$ (47)	$ (22)	$ (1)

RISK MANAGEMENT AND FINANCIA_13

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative Instrument Assets
Gross Derivative Instruments	$ 705	$ 217
Amounts Available for Offset	(628)	(146)
Net Amounts	77	71
Derivative Instrument Liabilities
Gross Derivative Instruments	(1,022)	(268)
Amounts Available for Offset	628	146
Net Amounts	(394)	(122)
Cash collateral provided by the Company	138	144
Letters of credit provided by the Company	68	130
Cash collateral received by the Company (less than)	1	0
Letters of credit received by the Company	10	6
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	19	5
Foreign exchange
Derivative Instrument Assets
Gross Derivative Instruments	34	85
Amounts Available for Offset	(33)	(54)
Net Amounts	1	31
Derivative Instrument Liabilities
Gross Derivative Instruments	(213)	(79)
Amounts Available for Offset	33	54
Net Amounts	(180)	(25)
Interest rate
Derivative Instrument Assets
Gross Derivative Instruments	12	2
Amounts Available for Offset	(4)	(1)
Net Amounts	8	1
Derivative Instrument Liabilities
Gross Derivative Instruments	(76)	(18)
Amounts Available for Offset	4	1
Net Amounts	(72)	(17)
Power \| Commodities
Derivative Instrument Assets
Gross Derivative Instruments	659	130
Amounts Available for Offset	(591)	(91)
Net Amounts	68	39
Derivative Instrument Liabilities
Gross Derivative Instruments	(733)	(171)
Amounts Available for Offset	591	91
Net Amounts	$ (142)	$ (80)

RISK MANAGEMENT AND FINANCIA_14

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Fair Value Hierarchy
Derivative Instrument Assets	$ 705	$ 217
Derivative Instrument Liabilities	(1,022)	(268)
Fair Value	(317)	(51)
Recurring basis
Fair Value Hierarchy
Assets and (liabilities), net	(317)	(51)
Recurring basis \| Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	37	(10)
Recurring basis \| Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Assets and (liabilities), net	(343)	(35)
Recurring basis \| Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	(11)	(6)
Total trading activity
Fair Value Hierarchy
Derivative Instrument Assets	685	173
Derivative Instrument Liabilities	(837)	(200)
Fair Value	(152)	(27)
Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	2
Derivative Instrument Liabilities	(74)	(45)
Fair Value	(74)	(43)
Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	12
Derivative Instrument Liabilities	(76)
Fair Value	(64)
Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	8	42
Derivative Instrument Liabilities	(35)	(23)
Fair Value	(27)	19
Commodities \| Recurring basis \| Power
Fair Value Hierarchy
Derivative Instrument Assets	659	130
Derivative Instrument Liabilities	(733)	(171)
Commodities \| Recurring basis \| Quoted Prices in Active Markets (Level I) \| Power
Fair Value Hierarchy
Derivative Instrument Assets	515	39
Derivative Instrument Liabilities	(478)	(49)
Commodities \| Recurring basis \| Significant Other Observable Inputs (Level II) \| Power
Fair Value Hierarchy
Derivative Instrument Assets	142	91
Derivative Instrument Liabilities	(242)	(116)
Commodities \| Recurring basis \| Significant Unobservable Inputs (Level III) \| Power
Fair Value Hierarchy
Derivative Instrument Assets	2	0
Derivative Instrument Liabilities	(13)	(6)
Foreign exchange \| Recurring basis
Fair Value Hierarchy
Derivative Instrument Assets	34	85
Derivative Instrument Liabilities	(213)	(79)
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	34	85
Derivative Instrument Liabilities	(213)	(79)
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	12	2
Derivative Instrument Liabilities	(76)	(18)
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	12	2
Derivative Instrument Liabilities	(76)	(18)
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	614	169
Other current assets \| Total trading activity
Fair Value Hierarchy
Derivative Instrument Assets	608	159
Other current assets \| Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other current assets \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0
Other current assets \| Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	6	10
Other current assets \| Commodities
Fair Value Hierarchy
Derivative Instrument Assets	597	122
Other current assets \| Commodities \| Commodities
Fair Value Hierarchy
Derivative Instrument Assets	597	122
Other current assets \| Commodities \| Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other current assets \| Commodities \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	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	17	47
Other current assets \| Foreign exchange \| Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets	11	37
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
Other current assets \| Foreign exchange \| Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	6	10
Other long-term assets
Fair Value Hierarchy
Derivative Instrument Assets	91	48
Other long-term assets \| Total trading activity
Fair Value Hierarchy
Derivative Instrument Assets	77	14
Other long-term assets \| Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	2
Other long-term assets \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	12
Other long-term assets \| Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	2	32
Other long-term assets \| Commodities
Fair Value Hierarchy
Derivative Instrument Assets	62	8
Other long-term assets \| Commodities \| Commodities
Fair Value Hierarchy
Derivative Instrument Assets	62	8
Other long-term assets \| Commodities \| Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Other long-term assets \| Commodities \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	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	17	38
Other long-term assets \| Foreign exchange \| Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets	15	6
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
Other long-term assets \| Foreign exchange \| Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Assets	2	32
Other long-term assets \| Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	12	2
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	2
Other long-term assets \| Interest rate \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Assets	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	(871)	(221)
Accounts payable and other \| Total trading activity
Fair Value Hierarchy
Derivative Instrument Liabilities	(742)	(184)
Accounts payable and other \| Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(72)	(33)
Accounts payable and other \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(26)
Accounts payable and other \| Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(31)	(4)
Accounts payable and other \| Commodities
Fair Value Hierarchy
Derivative Instrument Liabilities	(656)	(161)
Accounts payable and other \| Commodities \| Commodities
Fair Value Hierarchy
Derivative Instrument Liabilities	(584)	(138)
Accounts payable and other \| Commodities \| Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(72)	(23)
Accounts payable and other \| Commodities \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	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	(189)	(50)
Accounts payable and other \| Foreign exchange \| Foreign exchange
Fair Value Hierarchy
Derivative Instrument Liabilities	(158)	(46)
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
Accounts payable and other \| Foreign exchange \| Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(31)	(4)
Accounts payable and other \| Interest rate
Fair Value Hierarchy
Derivative Instrument Liabilities	(26)	(10)
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	(10)
Accounts payable and other \| Interest rate \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(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	(151)	(47)
Other long-term liabilities \| Total trading activity
Fair Value Hierarchy
Derivative Instrument Liabilities	(95)	(16)
Other long-term liabilities \| Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(2)	(12)
Other long-term liabilities \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(50)
Other long-term liabilities \| Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(4)	(19)
Other long-term liabilities \| Commodities
Fair Value Hierarchy
Derivative Instrument Liabilities	(77)	(10)
Other long-term liabilities \| Commodities \| Commodities
Fair Value Hierarchy
Derivative Instrument Liabilities	(75)	(6)
Other long-term liabilities \| Commodities \| Cash Flow Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(2)	(4)
Other long-term liabilities \| Commodities \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	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	(24)	(29)
Other long-term liabilities \| Foreign exchange \| Foreign exchange
Fair Value Hierarchy
Derivative Instrument Liabilities	(20)	(10)
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
Other long-term liabilities \| Foreign exchange \| Net Investment Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(4)	(19)
Other long-term liabilities \| Interest rate
Fair Value Hierarchy
Derivative Instrument Liabilities	(50)	(8)
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	(8)
Other long-term liabilities \| Interest rate \| Fair Value Hedges
Fair Value Hierarchy
Derivative Instrument Liabilities	(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, 2022	Dec. 31, 2021
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	$ (10)	$ 3
Commodity contracts \| Power
Net change in the Level III fair value category
Balance at beginning of year	(6)	(4)
Net losses included in Net income	(10)	(3)
Net losses included in OCI	(3)	0
Transfers out of Level III	7	0
Settlements	1	1
Balance at end of year	$ (11)	$ (6)

CHANGES IN OPERATING WORKING _3

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
CHANGES IN OPERATING WORKING CAPITAL
(Increase)/decrease in Accounts receivable	$ (575)	$ (925)	$ 129
Increase in Inventories	(190)	(93)	(55)
Decrease/(increase) in Other current assets	118	(141)	(221)
(Decrease)/increase in Accounts payable and other	(83)	890	(162)
Increase/(decrease) in Accrued interest	91	(18)	(18)
Increase in Operating Working Capital	$ (639)	$ (287)	$ (327)

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Details) $ in Millions, $ in Millions			1 Months Ended			12 Months Ended			36 Months Ended
	Nov. 30, 2021 CAD ($)	May 22, 2020	Nov. 30, 2020 USD ($)	May 31, 2020 CAD ($)	Apr. 30, 2020 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2021 CAD ($)	Jul. 31, 2022
Business Acquisition [Line Items]
Net gain/(loss) on sale of assets						$ 0	$ 30	$ (50)
Senior Secured Credit Facilities due April 2027
Business Acquisition [Line Items]
Amount					$ 1,500
Senior Secured Credit Facilities due April 2027 \| Coastal GasLink
Business Acquisition [Line Items]
Amount					$ 1,603
TransCanada Turbines \| TransCanada Turbines
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired			50%
Coastal GasLink
Business Acquisition [Line Items]
Ownership interest percentage								35%
Coastal GasLink \| Canadian Natural Gas Pipelines
Business Acquisition [Line Items]
Ownership interest percentage				35%		35%				35%
TransCanada Turbines \| TransCanada Turbines
Business Acquisition [Line Items]
Ownership interest percentage			50%
Business combination, consideration transferred			$ 67
Disposal group, disposed of by sale, not discontinued operations \| Coastal GasLink
Business Acquisition [Line Items]
Ownership interest sold		65%		65%				65%
Sale consideration				$ 656
Net gain/(loss) on sale of assets				364
Gain (loss) on sale				402
Revaluation of retained interest, gain (loss)				$ 231
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 sale of assets	13
Gain (loss) on sale	$ 19
Disposal group, disposed of by sale, not discontinued operations \| Portlands Energy Centre
Business Acquisition [Line Items]
Ownership interest sold					50%
Disposal group, disposed of by sale, not discontinued operations \| Halton Hills, Napanee and Portlands Energy Centre
Business Acquisition [Line Items]
Sale consideration					$ 2,800
Net gain/(loss) on sale of assets									$ (676)
Gain (loss) on sale									$ (470)

COMMITMENTS, CONTINGENCIES AN_3

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Narrative (Details) $ in Millions, $ in Billions	1 Months Ended	12 Months Ended
	Sep. 30, 2022 USD ($)	Dec. 31, 2022 CAD ($) Megawatt	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)
Other Commitments
Purchase commitment		$ 362	$ 239	$ 224
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites		$ 20	$ 30
Keystone XL
Contingencies
Economic recovery of damages	$ 15
Capital expenditures
Other Commitments
Power purchase agreement, planned capacity (in megawatts) \| Megawatt		1,020
Capital expenditures \| Canadian Natural Gas Pipelines
Other Commitments
Purchase commitment		$ 1,000
Capital expenditures \| U.S. Natural Gas Pipelines
Other Commitments
Purchase commitment		300
Capital expenditures \| Mexico Natural Gas Pipelines
Other Commitments
Purchase commitment		1,700
Capital expenditures \| Power and Energy Solutions
Other Commitments
Purchase commitment		$ 300
Minimum \| Capital expenditures
Other Commitments
Purchase commitment, period		1 year
Maximum \| Capital expenditures
Other Commitments
Purchase commitment, period		15 years

COMMITMENTS, CONTINGENCIES AN_4

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - Contingent financial obligation - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Guarantees
Potential Exposure	$ 269	$ 261
Carrying Value	3	4
Sur de Texas
Guarantees
Potential Exposure	100	93
Carrying Value	0	0
Bruce Power
Guarantees
Potential Exposure	88	88
Carrying Value	0	0
Other jointly-owned entities
Guarantees
Potential Exposure	81	80
Carrying Value	$ 3	$ 4

VARIABLE INTEREST ENTITIES - Na

VARIABLE INTEREST ENTITIES - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Jul. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	May 31, 2020
Variable Interest Entity [Line Items]
Variable interest entity ownership percentage	100%
Equity Investments	$ 9,535		$ 8,441
Coastal GasLink
Variable Interest Entity [Line Items]
Ownership interest percentage				35%
Coastal GasLink \| Canadian Natural Gas Pipelines
Variable Interest Entity [Line Items]
Equity Investments	$ 0		$ 386
Ownership interest percentage	35%	35%			35%

VARIABLE INTEREST ENTITIES - As

VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) $ in Millions, $ in Millions	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)
Current Assets
Cash and cash equivalents	$ 620		$ 673
Accounts receivable	3,624		3,092
Inventories	936		724
Other current assets	2,152		1,717
Total current assets	7,332		7,423
Plant, Property and Equipment	75,940		70,182
Equity Investments	9,535		8,441
Goodwill	12,843	$ 9,490	12,582	$ 9,941
Total assets	114,348		104,218
Current Liabilities
Accounts payable and other	7,149		5,099
Accrued interest	668		577
Current portion of long-term debt	1,898		1,320
Total current liabilities	16,907		13,041
Regulatory Liabilities	4,520		4,300
Deferred Income Tax Liabilities	7,648		6,142
Total liabilities	80,232		70,822
VIE, Primary Beneficiary
Current Assets
Cash and cash equivalents	60		72
Accounts receivable	98		70
Inventories	32		28
Other current assets	14		13
Total current assets	204		183
Plant, Property and Equipment	3,997		3,672
Equity Investments	748		890
Goodwill	449		421
Total assets	5,398		5,166
Current Liabilities
Accounts payable and other	234		232
Accrued interest	18		17
Current portion of long-term debt	31		29
Total current liabilities	283		278
Regulatory Liabilities	78		66
Other Long-Term Liabilities	1		1
Deferred Income Tax Liabilities	16		13
Long-Term Debt	2,136		2,025
Total liabilities	$ 2,514		$ 2,383

VARIABLE INTEREST ENTITIES - Ca

VARIABLE INTEREST ENTITIES - Carrying Value of Non-consolidated VIEs and Maximum Exposure (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Balance sheet
Loans receivable from affiliates (Note 12)	$ 0	$ 1,217
Equity Investments	9,535	8,441
Long-Term Loans Receivable from Affiliate (Notes 7 and 12)	0	238
Off-balance sheet
Maximum exposure to loss	12,314	10,519
VIE, not primary beneficiary
Balance sheet
Loans receivable from affiliates (Note 12)	0	1
Long-Term Loans Receivable from Affiliate (Notes 7 and 12)	0	238
Bruce Power
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	2,025	974
Bruce Power \| VIE, not primary beneficiary
Balance sheet
Equity Investments	5,783	4,493
Coastal GasLink
Balance sheet
Loans receivable from affiliates (Note 12)	250
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	3,300	3,037
Additional aggregate cost	3,300	3,300
Coastal GasLink \| Subordinated Loan Agreement \| Subordinated debt
Off-balance sheet
Carrying value	0
Coastal GasLink \| Subordinated Loan Agreement \| Subordinated debt \| Coastal GasLink
Off-balance sheet
Revolving credit facility, borrowing capacity	1,262
Coastal GasLink \| VIE, not primary beneficiary
Balance sheet
Equity Investments	0	386
Coastal GasLink \| VIE, not primary beneficiary \| Coastal GasLink
Balance sheet
Equity Investments	2,798
Pipeline Equity Investments And Other \| VIE, not primary beneficiary
Balance sheet
Equity Investments	1,148	1,219
Pipeline equity investments
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	$ 58	$ 171

SUBSEQUENT EVENT (Details)

SUBSEQUENT EVENT (Details) - Subsequent event - Mexico subsidiary $ in Millions	Jan. 17, 2023 USD ($)
Line of credit
Subsequent Event [Line Items]
Revolving credit facility, borrowing capacity	$ 500
Unsecured Term Loan
Subsequent Event [Line Items]
Revolving credit facility, borrowing capacity	$ 1,800