TransCanada Pipelines 40-F 15 Feb 22 2021 FY Annual report (Canada) Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2021shares
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
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 Rightsunder Shareholder Rights Plan) ofTC Energy Corporation
Trading Symbol	TRP
Security Exchange Name	NYSE
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	980,815,927
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	2021
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	940,063,806
Entity Central Index Key	0000099070
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Business Contact
Entity Information [Line Items]
Entity Address, Address Line One	700 Louisiana Street
Contact Personnel Name	TransCanada PipeLine USA Ltd
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002-2700
Entity Address, Address Line Two	Suite 700
City Area Code	832
Local Phone Number	320-5201

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues	$ 13,387	$ 12,999	$ 13,255
Income from Equity Investments (Note 10)	898	1,019	920
Operating and Other Expenses
Plant operating costs and other	4,098	3,878	3,913
Commodity purchases resold	87	0	365
Property taxes	774	727	727
Depreciation and amortization	2,522	2,590	2,464
Asset impairment charge and other (Note 6)	2,775	0	0
Total Operating and Other Expenses	10,256	7,195	7,469
Net Gain/(Loss) on Assets Sold/Held for Sale (Note 28)	30	(50)	(121)
Financial Charges
Interest expense (Note 19)	2,360	2,228	2,333
Allowance for funds used during construction	(267)	(349)	(475)
Interest income and other	(200)	(213)	(460)
Total Financial Charges	1,893	1,666	1,398
Income before Income Taxes	2,166	5,107	5,187
Income Tax Expense (Note 18)
Current	305	252	699
Deferred	(185)	(58)	55
Income Tax Expense	120	194	754
Net Income	2,046	4,913	4,433
Net income attributable to non-controlling interests (Note 21)	91	297	293
Net Income Attributable to Controlling Interests	1,955	4,616	4,140
Preferred share dividends	140	159	164
Net Income Attributable to Common Shares	$ 1,815	$ 4,457	$ 3,976
Net Income per Common Share (Note 22)
Basic (in dollars per share)	$ 1.87	$ 4.74	$ 4.28
Diluted (in dollars per share)	1.86	4.74	4.27
Dividends Declared per Common Share (in dollars per share)	$ 3.48	$ 3.24	$ 3
Weighted Average Number of Common Shares (millions) (Note 22)
Basic (in shares)	973	940	929
Diluted (in shares)	974	940	931
Canadian Natural Gas Pipelines
Revenues	$ 4,519	$ 4,469	$ 4,010
U.S. Natural Gas Pipelines
Revenues	5,233	5,031	4,978
Mexico Natural Gas Pipelines
Revenues	605	716	603
Liquids Pipelines
Revenues	2,306	2,371	2,879
Power and Storage
Revenues	$ 724	$ 412	$ 785

Consolidated statement of compr

Consolidated statement of comprehensive income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net Income	$ 2,046	$ 4,913	$ 4,433
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations	(108)	(609)	(944)
Reclassification to net income of foreign currency translation gains on disposal of foreign operations	0	0	(13)
Change in fair value of net investment hedges	(2)	36	35
Change in fair value of cash flow hedges	(10)	(583)	(62)
Reclassification to net income of gains and losses on cash flow hedges	55	489	14
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	158	12	(10)
Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans	14	17	10
Other comprehensive income/(loss) on equity investments	535	(280)	(82)
Other comprehensive income/(loss) (Note 24)	642	(918)	(1,052)
Comprehensive Income	2,688	3,995	3,381
Comprehensive income attributable to non-controlling interests	81	259	194
Comprehensive Income Attributable to Controlling Interests	2,607	3,736	3,187
Preferred share dividends	140	159	164
Comprehensive Income Attributable to Common Shares	$ 2,467	$ 3,577	$ 3,023

Consolidated statement of cash

Consolidated statement of cash flows $ in Millions, $ in Millions	12 Months Ended			24 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2020CAD ($)
Cash Generated from Operations
Net income	$ 2,046	$ 4,913	$ 4,433
Depreciation and amortization	2,522	2,590	2,464
Asset impairment charge and other (Note 6)	2,775	0	0
Deferred income taxes (Note 18)	(185)	(58)	55
Income from equity investments (Note 10)	(898)	(1,019)	(920)
Distributions received from operating activities of equity investments (Note 10)	975	1,123	1,213
Employee post-retirement benefits funding, net of expense (Note 25)	(5)	(19)	(45)
Net (gain)/loss on assets sold/held for sale (Note 28)	(30)	50	121
Equity allowance for funds used during construction	(191)	(235)	(299)
Unrealized losses/(gains) on financial instruments	194	(103)	(134)
Foreign exchange losses/(gains) on loan receivable from affiliate (Note 11)	41	86	(53)
Other	(67)	57	(46)
(Increase)/decrease in operating working capital (Note 27)	(287)	(327)	293
Net cash provided by operations	6,890	7,058	7,082
Investing Activities
Capital expenditures (Note 4)	(5,924)	(8,013)	(7,475)
Capital projects in development (Note 4)	0	(122)	(707)
Contributions to equity investments (Notes 4 and 10)	(1,210)	(765)	(602)
Proceeds from sales of assets, net of transaction costs	35	3,407	2,398
Loan to affiliate (Note 11)	(239)	0	0
Acquisition	0	(88)	0
Other distributions from equity investments (Note 10)	73	0	186
Payment for unredeemed shares of Columbia Pipeline Group, Inc. (Note 28)	0	0	(373)
Deferred amounts and other	(447)	(471)	(299)
Net cash used in investing activities	(7,712)	(6,052)	(6,872)
Financing Activities
Notes payable issued/(repaid), net	1,003	(220)	1,656
Long-term debt issued, net of issue costs	10,730	5,770	3,024
Long-term debt repaid	(7,758)	(3,977)	(3,502)
Junior subordinated notes issued, net of issue costs	495	0	1,436
Loss on settlement of financial instruments (Note 26)	(10)	(130)	0
Redeemable non-controlling interest repurchased (Note 6)	(633)	0	0
Contributions from redeemable non-controlling interest (Note 6)	0	1,033	0
Dividends on common shares	(3,317)	(2,987)	(1,798)
Dividends on preferred shares	(141)	(159)	(160)
Distributions to non-controlling interests	(74)	(221)	(216)
Distributions on Class C Interests (Note 6)	(16)	0	0
Common shares issued, net of issue costs	148	91	253
Preferred shares redeemed (Note 23)	(500)	0	0
Acquisition of TC PipeLines, LP transaction costs (Note 21)	(15)	0	0
Net cash (used in)/provided by financing activities	(88)	(800)	693
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	53	(19)	(6)
(Decrease)/Increase in Cash and Cash Equivalents	(857)	187	897
Cash and Cash Equivalents, Beginning of year	1,530	1,343	446	$ 446
Cash and Cash Equivalents, End of year	$ 673	$ 1,530	$ 1,343	$ 1,530

Consolidated balance sheet

Consolidated balance sheet - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 673	$ 1,530
Accounts receivable	3,092	2,162
Loans receivable from affiliates (Note 11)	1,217	0
Inventories	724	629
Other current assets (Note 7)	1,717	880
Total Current Assets	7,423	5,201
Plant, Property and Equipment (Note 8)	70,182	69,775
Equity Investments (Note 10)	8,441	6,677
Long-Term Loans Receivable from Affiliates (Note 11)	238	1,338
Restricted Investments	2,182	1,898
Regulatory Assets (Note 12)	1,767	1,753
Goodwill (Note 13)	12,582	12,679
Other Long-Term Assets (Note 14)	1,403	979
Total Assets	104,218	100,300
Current Liabilities
Notes payable (Note 15)	5,166	4,176
Accounts payable and other (Note 16)	5,099	3,816
Dividends payable	879	795
Accrued interest	577	595
Redeemable non-controlling interest	0	633
Current portion of long-term debt (Note 19)	1,320	1,972
Total Current Liabilities	13,041	11,987
Regulatory Liabilities (Note 12)	4,300	4,148
Other Long-Term Liabilities (Note 17)	1,059	1,475
Deferred Income Tax Liabilities (Note 18)	6,142	5,806
Long-Term Debt (Note 19)	37,341	34,913
Junior Subordinated Notes (Note 20)	8,939	8,498
Total Liabilities	70,822	66,827
Redeemable Non-Controlling Interest (Note 6)	0	393
EQUITY
Common shares, no par value (Note 22)	26,716	24,488
Preferred shares (Note 23)	3,487	3,980
Additional paid-in capital	729	2
Retained earnings	3,773	5,367
Accumulated other comprehensive loss (Note 24)	(1,434)	(2,439)
Controlling Interests	33,271	31,398
Non-controlling interests (Note 21)	125	1,682
Total Equity	33,396	33,080
Total Liabilities and Equity	$ 104,218	$ 100,300

Consolidated balance sheet (Par

Consolidated balance sheet (Parenthetical) - shares shares in Millions	Dec. 31, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Common shares issued (in shares)	981	940
Common shares outstanding (in shares)	981	940

Consolidated statement of equit

Consolidated statement of equity - CAD ($) $ in Millions	Total	Equity Attributable to Controlling Interests	Common Shares	Preferred Shares (Note 23)	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Loss (Note 24)	Equity Attributable to Non-Controlling Interests
Balance at beginning of year at Dec. 31, 2018			$ 23,174	$ 3,980	$ 17	$ 2,773	$ (606)	$ 1,655
Shares issued:
Exercise of stock options			282
Dividend reinvestment and share purchase plan			931
Issuance of stock options, net of exercises					(17)
Net income attributable to controlling interests	$ 4,140					4,140
Common share dividends						(2,794)
Preferred share dividends						(164)
Other comprehensive income/(loss) attributable to controlling interests	(1,052)						(953)
Net income attributable to non-controlling interests	(293)							293
Other comprehensive loss attributable to non-controlling interests								(99)
Distributions declared to non-controlling interests								(215)
Balance at end of year at Dec. 31, 2019	32,397	$ 30,763	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 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 21)			2,063		(398)		353	(1,563)
Exercise of stock options			165
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 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

DESCRIPTION OF TC ENERGY'S BUSI

DESCRIPTION OF TC ENERGY'S BUSINESS	12 Months Ended
	Dec. 31, 2021
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 Storage. 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 40,580 km (25,216 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 50,211 km (31,199 miles) of regulated natural gas pipelines, 535 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 2,503 km (1,554 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 Storage The Power and Storage segment primarily consists of the Company's investments in seven power generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These assets are located in Alberta, Ontario, Québec and New Brunswick.

ACCOUNTING POLICIES

ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2021
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, although certain non-controlling interests with redemption features are presented in mezzanine equity. TC Energy uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. Certain prior year amounts have been reclassified to conform to current year presentation. Use of Estimates and Judgments In preparing these consolidated financial statements, TC Energy is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Certain estimates and judgments have a material impact where the assumptions underlying these accounting estimates relate to matters that are highly uncertain at the time the estimate or judgment is made or are subjective. These estimates and judgments include, but are not limited to: • fair value of reporting units that contain goodwill (Notes 13 and 28) • fair value of assets and liabilities acquired in a business combination (Note 28). 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 8) • determining whether a contract contains a lease (Note 9) • fair value of equity investments (Note 10) • carrying value of regulatory assets and liabilities (Note 12) • carrying value of asset retirement obligations (Note 17) • provisions for income taxes, including valuation allowances and releases (Note 18) • assumptions used to measure retirement and other post-retirement benefit obligations (Note 25) • fair value of financial instruments (Note 26) • provisions for commitments, contingencies and guarantees (Note 29). 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. The impact of these changes are 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), formerly the National Energy Board (NEB), the Alberta Energy Regulator or the B.C. Oil and Gas Commission. In the U.S., regulated natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TC Energy's rate-regulated businesses which may differ from that otherwise recognized in non-rate-regulated businesses to reflect the economic impact of the regulators' decisions regarding revenues and tolls. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An operation qualifies for the use of RRA when it meets three criteria: • a regulator must establish or approve the rates for the regulated services or activities • the regulated rates must be designed to recover the cost of providing the services or products and • 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. 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. During 2019, TC Energy sold certain Columbia Midstream assets that were part of the acquisition of Columbia Pipeline Group, Inc.(Columbia) in 2016. Prior to the sale, revenues from the Company's midstream natural gas services, including gathering, treating, conditioning, processing, compression and liquids handling services, were generated from contractual arrangements and were recognized ratably over the term of the contract. Midstream natural gas service revenues were invoiced and received on a monthly basis. The Company did not take ownership of the natural gas for which it provided midstream services. Refer to Note 28, Acquisitions and dispositions, for additional information regarding the sale of the Columbia Midstream assets. Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Other The Company is contracted to provide operating services to a partially-owned entity for a fee which is recognized over time as services are provided. The Company's construction services to this entity have been performed and the related development fee has been recognized. 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 Storage Power Revenues from the Company's Power and Storage 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 and proprietary natural gas inventory in storage. 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 0.6 per cent to seven 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. Prior to its sale in 2019, plant, property and equipment for Columbia Midstream was carried at cost. Depreciation was calculated on a straight-line basis once the assets were ready for their intended use. Gathering and processing facilities were depreciated at annual rates ranging from 1.7 per cent to 2.5 per cent, and other plant and equipment were depreciated at various rates reflecting their estimated useful lives. When these assets were retired from plant, property and equipment, the original book cost and related accumulated depreciation were derecognized and any gain or loss was recorded in net income. Refer to Note 28, Acquisitions and dispositions, for additional information. 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 Storage Plant, property and equipment for Power and Storage 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 a construction stage is probable or costs are otherwise likely to be recoverable. The Company also 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 Lessee Accounting Policy The Company determines if an arrangement is a lease at inception of the contract. 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 expedients to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption and to not separate lease and non-lease components for all leases for which the Company is a lessee. Lessor Accounting Policy The Company is the lessor within certain contracts, including power purchase agreements (PPA), and these are accounted for as operating leases. The Company recognizes lease payments as income over the lease term on a straight-line basis. Variable lease payments are recognized as income in the period in which they occur. The Company applies the practical expedient to not separate lease and non-lease components for facilities and liquids tank terminals for which the Company is the lessor. Impairment of Long-Lived Assets The Company reviews long-lived assets such as plant, property and equipment, equity investments 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. 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. 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 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 supportable forecasts to determine any impairment, which is recognized in Plant operating costs and other. 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. 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 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. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability. 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 in the Consolidated statement of income. 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 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

ACCOUNTING CHANGES

ACCOUNTING CHANGES	12 Months Ended
	Dec. 31, 2021
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES Changes in Accounting Policies for 2021 Income Taxes In December 2019, the Financial Accounting Standards Board (FASB) issued new guidance that simplified the accounting for income taxes and clarified existing guidance. This new guidance was effective January 1, 2021, and did not have a material impact on the Company's consolidated financial statements. Reference Rate Reform In response to the expected cessation of the U.S. dollar London Interbank Offered Rate (LIBOR), for which certain rate settings ceased to be published at the end of 2021 with full cessation by mid-2023, the FASB issued new optional guidance in March 2020 that eases the potential burden in accounting for such reference rate reform. The new guidance provides optional expedients for contracts and hedging relationships that are affected by reference rate reform if certain criteria are met. Each of the expedients can be applied as of January 1, 2020 through December 31, 2022. For eligible hedging relationships existing as of January 1, 2020 and prospectively, the Company has applied an optional expedient allowing an entity to assume that the hedged forecasted transaction in a cash flow hedge is probable of occurring. The Company has completed necessary system changes to facilitate the adoption of the proposed standard market reference rates. The Company has also completed its analysis of contracts impacted by reference rate reform. Contract modifications, if required, will take place prior to the full cessation date in mid-2023. 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 consolidated financial statements; however, the Company will continue to monitor any new developments up to the full cessation date. Future Accounting Changes 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 is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Contract Assets and Liabilities from Contracts with Customers

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION year ended December 31, 2021 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Storage 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 Interest income and other 3 200 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 Interest income and other by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 11, 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 Storage 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 Interest income and other 3 213 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 Interest income and other by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 11, Loans receivable from affiliates, for additional information. year ended December 31, 2019 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Storage Corporate 1 Total (millions of Canadian $) Revenues 4,010 4,978 603 2,879 785 — 13,255 Intersegment revenues — 164 — — 19 (183) 2 — 4,010 5,142 603 2,879 804 (183) 13,255 Income/(loss) from equity investments 12 264 56 70 571 (53) 3 920 Plant operating costs and other (1,473) (1,581) (54) (728) (243) 166 2 (3,913) Commodity purchases resold — — — — (365) — (365) Property taxes (275) (345) — (101) (6) — (727) Depreciation and amortization (1,159) (754) (115) (341) (95) — (2,464) Net gain/(loss) on assets sold/held for sale — 21 — 69 (211) — (121) Segmented Earnings/(Losses) 1,115 2,747 490 1,848 455 (70) 6,585 Interest expense (2,333) Allowance for funds used during construction 475 Interest income and other 3 460 Income before Income Taxes 5,187 Income tax expense (754) Net Income 4,433 Net income attributable to non-controlling interests (293) Net Income Attributable to Controlling Interests 4,140 Preferred share dividends (164) Net Income Attributable to Common Shares 3,976 Capital Spending Capital expenditures 3,900 2,500 323 239 481 32 7,475 Capital projects in development 6 — — 701 — — 707 Contributions to equity investments — 16 34 14 538 — 602 3,906 2,516 357 954 1,019 32 8,784 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income/(loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains and losses on the peso-denominated loans from affiliates which are fully offset in Interest income and other by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 11, Loans receivable from affiliates, for additional information. at December 31 2021 2020 (millions of Canadian $) Total Assets by segment Canadian Natural Gas Pipelines 25,213 22,852 U.S. Natural Gas Pipelines 45,502 43,217 Mexico Natural Gas Pipelines 7,547 7,215 Liquids Pipelines 14,951 16,744 Power and Storage 6,563 5,062 Corporate 4,442 5,210 104,218 100,300 Geographic Information year ended December 31 2021 2020 2019 (millions of Canadian $) Revenues Canada – domestic 4,603 4,392 4,059 Canada – export 1,226 1,059 1,035 United States 6,953 6,832 7,558 Mexico 605 716 603 13,387 12,999 13,255 at December 31 2021 2020 (millions of Canadian $) Plant, Property and Equipment Canada 24,890 24,092 United States 39,335 39,698 Mexico 5,957 5,985 70,182 69,775

REVENUES

REVENUES	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
REVENUES	REVENUES Disaggregation of Revenues year ended December 31, 2021 Canadian U.S. Mexico Liquids Pipelines Power and Storage 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 28, Acquisitions and dispositions, for additional information. 2 Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 9, Leases, and Note 26, Risk management and financial instruments, for additional information on income from 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 12, year ended December 31, 2020 Canadian U.S. Mexico Liquids Pipelines Power and Storage 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 28, Acquisitions and dispositions, for additional information. 2 Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 9, Leases, and Note 26, Risk management and financial instruments, for additional information on income from 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 12, year ended December 31, 2019 Canadian U.S. Mexico Liquids Pipelines Power and Storage Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,010 4,245 601 2,423 — 11,279 Power generation — — — — 662 662 Natural gas storage and other — 650 2 4 73 729 4,010 4,895 603 2,427 735 12,670 Other revenues 1,2 — 83 — 452 50 585 4,010 4,978 603 2,879 785 13,255 1 Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 9, Leases, and Note 26, Risk management and financial instruments, for additional information on income from lease arrangements and financial instruments, respectively. 2 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 12, Contract Balances at December 31 2021 2020 Affected line item on the (millions of Canadian $) Receivables from contracts with customers 1,627 1,330 Accounts receivable Contract assets (Note 7) 202 132 Other current assets Long-term contract assets (Note 14) 249 192 Other long-term assets Contract liabilities 1 (Note 16) 90 129 Accounts payable and other Long-term contract liabilities (Note 17) 184 203 Other long-term liabilities 1 During the year ended December 31, 2021, $15 million (2020 – $18 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 relate to force majeure fixed capacity payments received on long-term capacity arrangements in Mexico. Future Revenues from Remaining Performance Obligations As at December 31, 2021, future revenues from long-term pipeline capacity arrangements and transportation as well as natural gas storage and other contracts extending through 2049 are approximately $23.8 billion, of which approximately $3.4 billion is expected to be recognized in 2022. 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.

KEYSTONE XL

KEYSTONE XL	12 Months Ended
	Dec. 31, 2021
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, and after a comprehensive review of options in consultation with its partner, the Government of Alberta, on June 9, 2021, the Company terminated the Keystone XL pipeline project. The Keystone XL investment was evaluated for impairment in 2021, along with TC Energy's investments in related capital projects, including Heartland Pipeline, TC Terminals and Keystone Hardisty Terminal. 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. Termination activities and related costs will continue through 2022 with any adjustments to the estimated fair value and future contractual and legal obligations expensed as determined. 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 1 n/a 342 282 175 2,775 2,134 1 In 2021, the Company paid $192 million towards contractual and legal obligations related to termination activities. The estimated fair value of $175 million related to plant and equipment is based on the price that is expected to be received from selling these assets in their current condition and is updated as required. 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. As the Company did not see the related capital projects in development proceeding at the time of the assessment in 2021, it recorded an asset impairment charge equal to the carrying value of these projects included in Other long-term assets on the Consolidated balance sheet as the estimated fair value of these related projects was determined to be nil. 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. At December 31, 2020, TC Energy had reclassified $630 million related to Class A Interests to Current liabilities on the Consolidated balance sheet to reflect the expectation that the Company would exercise its call right in January 2021 in accordance with contractual terms. For the year ended December 31, 2020, redeemable non-controlling interest in Current liabilities of $633 million also included $3 million of return accrued that was recorded in Interest expense in the Consolidated statement of income. On January 8, 2021, the Company exercised its call right 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 which were classified as Current liabilities on the Consolidated balance sheet at December 31, 2020. This transaction was funded by draws on the project-level credit facility. Following the revocation of the Presidential Permit for the Keystone XL pipeline project on January 20, 2021, the Company ceased accruing a return on the remaining Government of Alberta Class A Interests. 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. 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 entitle the Government of Alberta to future liquidation proceeds from specified Keystone XL project assets. The Class C Interests of $91 million, net of $16 million of related distributions to the Government of Alberta, were recorded in Accounts payable and other on the Consolidated balance sheet at December 31, 2021. 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. The changes in Redeemable non-controlling interest classified in mezzanine equity were as follows: year ended December 31 2021 2020 (millions of Canadian $) Balance at beginning of year 393 — Class A Interests issued — 1,033 Net income/(loss) attributable to redeemable non-controlling interest 1 1 (10) Class A Interests repurchased (394) — Class A Interests transferred to Current liabilities — (630) Balance at end of year — 393 1 Includes a return accrual and a foreign currency translation loss on Class A Interests, both of which were presented within Net income attributable to non-controlling interests in the Consolidated statement of income.

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2021
Other Assets [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS at December 31 2021 2020 (millions of Canadian $) Keystone XL contractual recoveries (Note 6) 640 — Cash provided as collateral 273 142 Contract assets (Note 5) 202 132 Fair value of derivative contracts (Note 26) 169 235 Keystone XL assets held for sale 138 — Prepaid expenses 112 126 Regulatory assets (Note 12) 53 131 Other 130 114 1,717 880

PLANT, PROPERTY AND EQUIPMENT

PLANT, PROPERTY AND EQUIPMENT	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
PLANT, PROPERTY AND EQUIPMENT	PLANT, PROPERTY AND EQUIPMENT at December 31 2021 2020 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 14,892 5,751 9,141 14,190 5,278 8,912 Compression 6,191 2,065 4,126 5,421 1,906 3,515 Metering and other 1,458 705 753 1,393 648 745 22,541 8,521 14,020 21,004 7,832 13,172 Under construction 2,285 — 2,285 1,402 — 1,402 24,826 8,521 16,305 22,406 7,832 14,574 Canadian Mainline Pipeline 10,423 7,698 2,725 10,297 7,443 2,854 Compression 4,165 3,125 1,040 3,930 3,000 930 Metering and other 652 264 388 637 239 398 15,240 11,087 4,153 14,864 10,682 4,182 Under construction 139 — 139 150 — 150 15,379 11,087 4,292 15,014 10,682 4,332 Other Canadian Natural Gas Pipelines 1 Other 1,937 1,567 370 1,885 1,508 377 Under construction 58 — 58 42 — 42 1,995 1,567 428 1,927 1,508 419 42,200 21,175 21,025 39,347 20,022 19,325 U.S. Natural Gas Pipelines Columbia Gas Pipeline 11,205 799 10,406 10,198 557 9,641 Compression 4,522 381 4,141 4,287 276 4,011 Metering and other 3,657 257 3,400 3,388 185 3,203 19,384 1,437 17,947 17,873 1,018 16,855 Under construction 433 — 433 1,070 — 1,070 19,817 1,437 18,380 18,943 1,018 17,925 ANR Pipeline 1,820 557 1,263 1,685 512 1,173 Compression 2,559 565 1,994 2,146 489 1,657 Metering and other 1,391 422 969 1,289 388 901 5,770 1,544 4,226 5,120 1,389 3,731 Under construction 833 — 833 431 — 431 6,603 1,544 5,059 5,551 1,389 4,162 at December 31 2021 2020 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Other U.S. Natural Gas Pipelines Columbia Gulf 2,749 178 2,571 2,638 151 2,487 GTN 2,701 1,071 1,630 2,330 1,008 1,322 Great Lakes 2,162 1,255 907 2,117 1,223 894 Other 2 1,755 657 1,098 1,568 578 990 9,367 3,161 6,206 8,653 2,960 5,693 Under construction 533 — 533 389 — 389 9,900 3,161 6,739 9,042 2,960 6,082 36,320 6,142 30,178 33,536 5,367 28,169 Mexico Natural Gas Pipelines Pipeline 2,957 476 2,481 2,952 411 2,541 Compression 480 80 400 480 69 411 Metering and other 626 155 471 624 133 491 4,063 711 3,352 4,056 613 3,443 Under construction 2,590 — 2,590 2,525 — 2,525 6,653 711 5,942 6,581 613 5,968 Liquids Pipelines Keystone Pipeline System Pipeline 9,209 1,758 7,451 9,254 1,579 7,675 Pumping equipment 1,020 252 768 1,025 228 797 Tanks and other 3,534 737 2,797 3,522 644 2,878 13,763 2,747 11,016 13,801 2,451 11,350 Under construction 3 72 — 72 2,870 — 2,870 13,835 2,747 11,088 16,671 2,451 14,220 Intra-Alberta Pipelines 199 14 185 198 9 189 14,034 2,761 11,273 16,869 2,460 14,409 Power and Storage Natural Gas 1,267 605 662 1,255 569 686 Natural Gas Storage and Other 797 216 581 780 194 586 2,064 821 1,243 2,035 763 1,272 Under construction 5 — 5 11 — 11 2,069 821 1,248 2,046 763 1,283 Corporate 836 320 516 993 372 621 102,112 31,930 70,182 99,372 29,597 69,775 1 Includes Foothills, Ventures LP and Great Lakes Canada. 2 Includes Portland, North Baja, Tuscarora, Crossroads and mineral rights.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2021
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 $) 2021 2020 Operating lease cost 1 105 124 Sublease income (8) (13) Net operating lease cost 97 111 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 $) 2021 2020 Cash paid for amounts included in the measurement of operating lease liabilities 69 77 ROU assets obtained in exchange for new operating lease liabilities 32 14 at December 31 2021 2020 Weighted average remaining lease term 9 years 10 years Weighted average discount rate 3.5 % 3.5 % Maturities of operating lease liabilities are as follows: (millions of Canadian $) 2021 2020 Less than one year 63 72 One to two years 60 61 Two to three years 58 59 Three to four years 55 58 Four to five years 54 54 More than five years 213 269 Total operating lease payments 503 573 Imputed interest (74) (90) Operating lease liabilities 429 483 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2021 2020 Accounts payable and other 49 56 Other long-term liabilities (Note 17) 380 427 429 483 As at December 31, 2021, the carrying value of the ROU assets recorded under operating leases was $415 million (2020 – $473 million) and is included in Plant, property and equipment on the Consolidated balance sheet. As a Lessor The Grandview and Bécancour power plants in the Power and Storage 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 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, 2021 was $126 million (2020 – $130 million; 2019 – $180 million). Future lease payments to be received under operating leases are as follows: (millions of Canadian $) 2021 2020 Less than one year 113 119 One to two years 111 111 Two to three years 110 109 Three to four years 94 109 Four to five years 70 94 More than five years — 70 498 612
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 $) 2021 2020 Operating lease cost 1 105 124 Sublease income (8) (13) Net operating lease cost 97 111 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 $) 2021 2020 Cash paid for amounts included in the measurement of operating lease liabilities 69 77 ROU assets obtained in exchange for new operating lease liabilities 32 14 at December 31 2021 2020 Weighted average remaining lease term 9 years 10 years Weighted average discount rate 3.5 % 3.5 % Maturities of operating lease liabilities are as follows: (millions of Canadian $) 2021 2020 Less than one year 63 72 One to two years 60 61 Two to three years 58 59 Three to four years 55 58 Four to five years 54 54 More than five years 213 269 Total operating lease payments 503 573 Imputed interest (74) (90) Operating lease liabilities 429 483 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows: at December 31 (millions of Canadian $) 2021 2020 Accounts payable and other 49 56 Other long-term liabilities (Note 17) 380 427 429 483 As at December 31, 2021, the carrying value of the ROU assets recorded under operating leases was $415 million (2020 – $473 million) and is included in Plant, property and equipment on the Consolidated balance sheet. As a Lessor The Grandview and Bécancour power plants in the Power and Storage 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 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, 2021 was $126 million (2020 – $130 million; 2019 – $180 million). Future lease payments to be received under operating leases are as follows: (millions of Canadian $) 2021 2020 Less than one year 113 119 One to two years 111 111 Two to three years 110 109 Three to four years 94 109 Four to five years 70 94 More than five years — 70 498 612

EQUITY INVESTMENTS

EQUITY INVESTMENTS	12 Months Ended
	Dec. 31, 2021
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	EQUITY INVESTMENTS (millions of Canadian $) Ownership Interest at December 31, 2021 Income from Equity Equity year ended December 31 at December 31 2021 2020 2019 2021 2020 Canadian Natural Gas Pipelines TQM 1 50.0 % 12 12 12 118 90 Coastal GasLink 1,2 35.0 % — — — 386 211 U.S. Natural Gas Pipelines Northern Border 3 50.0 % 80 100 91 505 521 Millennium 47.5 % 91 96 92 474 482 Iroquois 4 50.0 % 55 52 54 392 197 Other Various 18 16 27 137 120 Mexico Natural Gas Pipelines Sur de Texas 5 60.0 % 160 213 3 835 680 Liquids Pipelines Grand Rapids 1,6 50.0 % 54 53 56 980 998 Northern Courier 1,7 nil 16 22 14 — 53 Port Neches Link LLC 1,8 95.0 % — — — 103 — HoustonLink Pipeline 1 50.0 % 1 — — 18 19 Power and Storage Bruce Power 1,9 48.4 % 411 439 527 4,493 3,306 Portlands Energy Centre 1,10 nil — 12 35 — — TransCanada Turbines 11 100.0 % — 4 9 — — 898 1,019 920 8,441 6,677 1 Classified as a non-consolidated VIE. Refer to Note 30, Variable interest entities, for additional information. 2 In May 2020, TC Energy completed the sale of a 65 per cent equity interest in Coastal GasLink Pipeline Limited Partnership and subsequently applied the equity method to account for its 35 per cent retained equity interest in the jointly-controlled entity. Refer to Note 28, Acquisitions and dispositions, for additional information. At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Coastal GasLink Pipeline Limited Partnership was $167 million (2020 – $188 million) due mainly to the fair value assessment of assets at the time of partial monetization along with deferred development fee revenue accounting. 3 At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border was US$115 million (2020 – US$116 million) due mainly to the fair value assessment of assets at the time of acquisition. 4 At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$39 million (2020 – US$39 million) due mainly to the fair value assessment of the assets at the times of acquisition. 5 Sur de Texas was placed into service in September 2019. TC Energy has a 60 per cent equity interest and, as a jointly-controlled entity, applies the equity method of accounting. Income from equity investments recorded in the Corporate segment reflects 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 Interest income and other in the Consolidated statement of income. At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Sur de Texas was US$77 million (2020 – US$79 million) due mainly to the accounting for fees earned from the successful construction of the pipeline. 6 At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $96 million (2020 – $98 million) due mainly to interest capitalized during construction. 7 On November 30, 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 28, Acquisitions and dispositions, for additional information. At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Courier was $56 million due mainly to the fair value of guarantees and the fair value assessment of assets at the time of partial monetization. 8 On March 8, 2021, TC Energy entered a joint venture with Motiva Enterprises to construct the Port Neches Link pipeline system. TC Energy has a 95 per cent equity interest and, as a jointly-controlled entity, applies the equity method of accounting. 9 At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $755 million (2020 – $796 million) due mainly to capitalized interest and the fair value assessment of assets at the time of acquisition. 10 In April 2020, TC Energy sold its investment in Portlands Energy Centre. Refer to Note 28, Acquisitions and dispositions, for additional information. 11 In November 2020, TC Energy purchased the remaining 50 per cent ownership in TransCanada Turbines which was subsequently consolidated. Refer to Note 28, Acquisitions and dispositions, for additional information. Distributions and Contributions Distributions received from equity investments for the year ended December 31, 2021 were $1,048 million (2020 – $1,123 million; 2019 – $1,399 million). For the year ended December 31, 2021, $73 million (2020 – nil; 2019 – $186 million) was included in Investing activities in the Consolidated statement of cash flows relating to TC Energy's proportionate share of the Sur de Texas 2021 partial debt repayment, and in 2019, included distributions received from Bruce Power and Northern Border from their respective financing programs. Contributions made to equity investments for the year ended December 31, 2021 were $1,210 million (2020 – $765 million; 2019 – $602 million) and were included in Investing activities in the Consolidated statement of cash flows. For 2019, contributions of $32 million related to TC Energy's proportionate share of the Sur de Texas debt financing requirements. Summarized Financial Information of Equity Investments year ended December 31 2021 2020 2019 (millions of Canadian $) Income Revenues 5,447 5,838 5,693 Operating and other expenses (3,293) (3,341) (3,408) Net income 1,859 2,047 1,990 Net income attributable to TC Energy 898 1,019 920 at December 31 2021 2020 (millions of Canadian $) Balance Sheet Current assets 3,498 2,911 Non-current assets 30,165 26,957 Current liabilities (2,540) (3,727) Non-current liabilities (16,400) (15,309)

LOANS RECEIVABLE FROM AFFILIATE

LOANS RECEIVABLE FROM AFFILIATES	12 Months Ended
	Dec. 31, 2021
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 bears interest at a floating rate and matures in March 2022. At December 31, 2021, Loans receivable from affiliates under Current assets on the Company's Consolidated balance sheet reflected a MXN$19.7 billion or $1.2 billion loan receivable from the Sur de Texas joint venture which represents TC Energy's proportionate share of debt financing to the joint venture. At December 31, 2020, this loan was recorded as Long-term loans receivable from affiliates on the Company's Consolidated balance sheet and amounted to MXN$20.9 billion or $1.3 billion. The Company's Consolidated statement of income reflects the related interest income and foreign exchange impact on this loan receivable 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 $) 2021 2020 2019 Interest income 1 87 110 147 Interest income and other Interest expense 2 (87) (110) (147) Income from equity investments Foreign exchange (losses)/gains 1 (41) (86) 53 Interest income and other Foreign exchange gains/(losses) 1 41 86 (53) Income from equity investments 1 Included in the Corporate segment. 2 Included in the Mexico Natural Gas Pipelines segment. Coastal GasLink Pipeline Limited Partnership TC Energy holds a 35 per cent equity interest in Coastal GasLink Pipeline Limited Partnership (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 $500 million at December 31, 2021 with an outstanding balance of $1 million (December 31, 2020 – nil) reflected in Loans receivable from affiliates under Current assets on the Company's Consolidated balance sheet. Subordinated Loan Agreement On December 6, 2021, the Company entered into a subordinated loan agreement with Coastal GasLink LP to provide interim temporary financing, if necessary, of up to $3,275 million to fund incremental project costs as a bridge to a required increase in the project-level financing. Financing available to Coastal GasLink LP under this agreement is provided through a combination of interest-bearing facilities subject to floating market-based rates and non-interest-bearing facilities that are subject to a return to the Company under certain conditions at the time the final cost of the project is determined. At December 31, 2021, Long-term loans receivable from affiliates on the Company’s Consolidated balance sheet reflected $238 million in amounts outstanding under the subordinated loan agreement.

RATE-REGULATED BUSINESSES

RATE-REGULATED BUSINESSES	12 Months Ended
	Dec. 31, 2021
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). In August 2019, the CER and CER Act replaced the NEB and the National Energy Board Act, respectively. The impact assessment and decision-making for designated major transboundary pipeline projects also changed at that time with the implementation of the new Impact Assessment Act which required designated projects, on a prospective basis, to be assessed by the Impact Assessment Agency of Canada. 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 or NEB. 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, 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. NGTL System's 2019 results reflect the terms of the 2018-2019 Revenue Requirement Settlement which included an ROE of 10.1 per cent on 40 per cent deemed common equity, a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration amount and flow-through treatment of all other costs. Canadian Mainline The Canadian Mainline currently operates under the terms of the 2015-2030 Tolls Application approved in 2014 (the NEB 2014 Decision). The terms in the 2015-2020 six-year settlement of the NEB 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 NEB 2014 Decision. The NEB 2014 Decision also directed TC Energy to file an application to review tolls for the 2018-2020 period. In December 2018, an NEB 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 previous settlements, 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 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. In 2018, FERC prescribed changes (2018 FERC Actions) related to H.R.1, the Tax Cuts and Jobs Act (U.S. Tax Reform). The U.S. corporate income tax rate was reduced from 35 per cent to 21 per cent in 2017 as a result of U.S. Tax Reform. The U.S. regulated operations, where applicable, established regulatory liabilities amortized over the remaining average useful lives of the underlying property for the differences between the amounts previously recovered in rates and the expected deferred tax liabilities. Columbia Gas Columbia Gas' natural gas transportation and storage services are provided under a tariff at rates subject to FERC approval. A FERC-approved modernization settlement provided for cost recovery and return on investment of up to US$2.6 billion from 2013-2020 to modernize the Columbia Gas system thereby improving system integrity and enhancing service reliability and flexibility. In July 2020, Columbia Gas filed a general NGA Section 4 Rate Case with FERC requesting an increase on its maximum transportation rates to be effective February 1, 2021, subject to refund on completion of the rate proceeding. On October 29, 2021, Columbia Gas filed a petition with FERC requesting approval of the Stipulation and Agreement of Settlement (Columbia Gas Settlement) that reflects a rate case settlement with its customers and, if approved, will increase Columbia Gas’ maximum rates effective February 1, 2021. On December 17, 2021, the presiding Administrative Law Judge recommended the settlement for approval and certified it as uncontested to FERC for its review and approval. The Columbia Gas Settlement (a) extends Columbia’s modernization program allowing for the cost recovery and return on additional investment of up to US$1.2 billion over a four-year period through 2024 (b) establishes a rate case and tariff filing moratorium through April 1, 2025 and (c) requires Columbia Gas to file a general rate case under Section 4 of the NGA with new rates to be effective no later than April 1, 2026. ANR Pipeline ANR Pipeline operates under rates established through a FERC-approved rate settlement in 2016. 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 effective August 1, 2022, subject to refund. As the rate process progresses, the Company expects to engage in a collaborative process to achieve settlement with its customers, FERC and other stakeholders. 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 to take effect on August 1, 2020. This settlement establishes a rate case and tariff filing moratorium through 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 will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022. As a result of the 2018 FERC Actions, Great Lakes made a limited NGA Section 4 filing and reduced rates by two per cent effective February 1, 2019. Gas Transmission Northwest Gas Transmission Northwest (GTN) operates under a settlement approved by FERC in November 2018. GTN and its customers agreed upon a moratorium on further rate changes until December 31, 2021 and GTN is required to have new rates in effect on January 1, 2022. On September 29, 2021, GTN filed a rate settlement (2021 GTN Settlement) which was approved by FERC on November 18, 2021, extending the Company’s existing maximum transportation rates at their current levels, with GTN’s annual depreciation rates remaining unchanged. The 2021 GTN Settlement contains a moratorium until December 31, 2023, at which point GTN will be required to file for new rates to become effective no later than April 1, 2024. 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 were established based on CRE-approved contracts that provide for cost recovery, including a return of and on invested capital. Regulatory Assets and Liabilities at December 31 2021 2020 Remaining Recovery/ Settlement Period (years) (millions of Canadian $) Regulatory Assets Deferred income taxes 1 1,509 1,287 n/a Pensions and other post-retirement benefits 1,2 203 401 n/a Foreign exchange on long-term debt 1,3 3 7 1-8 Operating and debt-service regulatory assets 4 1 54 1 Other 104 135 n/a 1,820 1,884 Less: Current portion included in Other current assets (Note 7) 53 131 1,767 1,753 Regulatory Liabilities Pipeline abandonment trust balances 5 2,086 1,842 n/a Deferred income taxes – U.S. Tax Reform 6 1,141 1,170 n/a Canadian Mainline bridging amortization account 7 483 537 9 Cost of removal 8 254 246 n/a Canadian Mainline long-term adjustment account 7,9 186 223 5 Deferred income taxes 1 139 115 n/a Canadian Mainline short-term adjustment and toll-stabilization accounts 7,9,10 60 4 n/a ANR post-employment and retirement benefits other than pension 11 40 40 n/a Operating and debt-service regulatory liabilities 4 32 48 1 Pensions and other post-retirement benefits 2 13 18 n/a Other 66 58 n/a 4,500 4,301 Less: Current portion included in Accounts payable and other (Note 16) 200 153 4,300 4,148 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 regulatory liabilities will be 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, $223 million is amortized over the six-year settlement term and the residual of $4 million was transferred to the STAA at December 31, 2020. 10 Under the terms of the 2021-2026 Mainline Settlement, the STAA account will commence amortization over the remainder of the six-year settlement term when predetermined thresholds per the settlement agreement are met.

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL The Company has recorded the following Goodwill on its acquisitions: (millions of Canadian $) U.S. Natural Balance at January 1, 2020 12,887 Foreign exchange rate changes (208) Balance at December 31, 2020 12,679 Foreign exchange rate changes (97) Balance at December 31, 2021 12,582 As part of the annual goodwill impairment assessment at December 31, 2021, the Company evaluated qualitative factors impacting the fair value of the underlying reporting units for all its reporting units other than the Columbia 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. The Company elected to proceed directly to a quantitative annual goodwill impairment test at December 31, 2021 for the $9,303 million of goodwill related to the Columbia reporting unit following an uncontested rate case settlement with shippers in 2021. It was determined that the fair value of Columbia exceeded its carrying value, including goodwill at December 31, 2021. Sale of Columbia Midstream Assets In August 2019, TC Energy completed the sale of certain Columbia Midstream assets. As these assets constituted a business, and there was goodwill within this reporting unit, $595 million of Columbia's goodwill allocated to these assets was released and netted in the pre-tax gain on sale. The amount released was determined based on the relative fair values of the assets sold and the portion of the reporting unit retained. The fair value of the reporting unit was determined using a discounted cash flow analysis. Refer to Note 28, Acquisitions and dispositions, for additional details.

OTHER LONG-TERM ASSETS

OTHER LONG-TERM ASSETS	12 Months Ended
	Dec. 31, 2021
Intangible Assets, Net (Excluding Goodwill) [Abstract]
OTHER LONG-TERM ASSETS	OTHER LONG-TERM ASSETS at December 31 2021 2020 (millions of Canadian $) Deferred income tax assets (Note 18) 509 177 Employee post-retirement benefits (Note 25) 312 207 Long-term contract assets (Note 5) 249 192 Keystone XL contractual recoveries (Note 6) 50 — Fair value of derivative contracts (Note 26) 48 41 Capital projects in development 1 14 231 Other 221 131 1,403 979

NOTES PAYABLE

NOTES PAYABLE	12 Months Ended
	Dec. 31, 2021
Short-term Debt [Abstract]
NOTES PAYABLE	NOTES PAYABLE 2021 2020 (millions of Canadian $, unless otherwise noted) Outstanding at December 31 Weighted Outstanding at December 31 Weighted Canada 1 4,953 0.4 % 2,836 0.4 % U.S. (2021 – US$54; 2020 – US$900) 68 0.3 % 1,149 0.4 % Mexico (2021 – US$115; 2020 – US$150) 2 145 1.7 % 191 1.7 % 5,166 4,176 1 At December 31, 2021, Notes payable consisted of Canadian dollar-denominated notes of $1,989 million (2020 – $656 million) and U.S. dollar-denominated notes of US$2,341 million (2020 – US$1,709 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. At December 31, 2021 and 2020, Notes payable reflects short-term borrowings in Canada by TransCanada PipeLines Limited (TCPL), in the U.S. by TransCanada PipeLine USA Ltd. (TCPL USA) and in Mexico by a wholly-owned Mexican subsidiary. At December 31, 2021, total committed revolving and demand credit facilities were $12.4 billion (2020 – $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) 2021 2020 Borrower 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 2026 3.0 1.0 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 2022 US 4.5 US 2.1 US 4.5 TCPL / TCPL USA / Columbia / TransCanada American Investments Ltd. For general corporate purposes of the borrowers, guaranteed by TCPL December 2024 US 1.0 US 1.0 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 2.6 MXN 5.0 3 1 Net of commercial paper outstanding and facility draws. 2 Provisions of various 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 credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2021, the Company was in compliance with all debt covenants. 3 Or the U.S. dollar equivalent. For the year ended December 31, 2021, the cost to maintain the above facilities was $17 million (2020 – $21 million; 2019 – $11 million).

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2021
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER at December 31 2021 2020 (millions of Canadian $) Trade payables 4,183 3,057 Fair value of derivative contracts (Note 26) 221 72 Regulatory liabilities (Note 12) 200 153 Contract liabilities (Note 5) 90 129 Class C Interests (Note 6) 75 — Other 330 405 5,099 3,816

OTHER LONG-TERM LIABILITIES

OTHER LONG-TERM LIABILITIES	12 Months Ended
	Dec. 31, 2021
Deferred Costs, Noncurrent [Abstract]
OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES at December 31 2021 2020 (millions of Canadian $) Operating lease obligations (Note 9) 380 427 Long-term contract liabilities (Note 5) 184 203 Employee post-retirement benefits (Note 25) 174 503 Asset retirement obligations 61 54 Fair value of derivative contracts (Note 26) 47 59 Other 213 229 1,059 1,475

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Provision for Income Taxes year ended December 31 2021 2020 2019 (millions of Canadian $) Current Canada 29 (54) 84 Foreign 1 276 306 615 305 252 699 Deferred Canada (327) (224) (29) Foreign 142 166 84 (185) (58) 55 Income Tax Expense 120 194 754 1 The 2019 current foreign income tax expense mainly relates to the sale of certain Columbia Midstream assets in August 2019. Refer to Note 28, Acquisitions and dispositions, for additional information . Geographic Components of Income before Income Taxes year ended December 31 2021 2020 2019 (millions of Canadian $) Canada (292) 691 1,144 Foreign 2,458 4,416 4,043 Income before Income Taxes 2,166 5,107 5,187 Reconciliation of Income Tax Expense year ended December 31 2021 2020 2019 (millions of Canadian $) Income before income taxes 2,166 5,107 5,187 Federal and provincial statutory tax rate 23.0 % 24.0 % 26.5 % Expected income tax expense 498 1,226 1,375 Valuation allowance releases (8) (400) (259) Foreign income tax rate differentials (230) (258) (180) Income tax differential related to regulated operations (139) (228) (159) Income from non-controlling interests and equity investments (70) (141) (78) Alberta tax rate reduction — — (32) Non-taxable portion of capital gains — (62) (28) Non-deductible goodwill on the Columbia Midstream asset disposition — — 154 Impact of Mexico inflationary adjustments 32 7 13 Other 37 50 (52) Income Tax Expense 120 194 754 Deferred Income Tax Assets and Liabilities at December 31 2021 2020 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,163 1,389 Regulatory and other deferred amounts 537 532 Unrealized foreign exchange losses on long-term debt 130 154 Financial instruments — 48 Other 46 70 1,876 2,193 Less: Valuation allowance 229 243 1,647 1,950 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment 5,616 6,124 Equity investments 1,219 1,087 Taxes on future revenue requirement 333 287 Other 112 81 7,280 7,579 Net Deferred Income Tax Liabilities 5,633 5,629 The above deferred tax amounts have been classified on the Consolidated balance sheet as follows: at December 31 2021 2020 (millions of Canadian $) Deferred Income Tax Assets Other long-term assets (Note 14) 509 177 Deferred Income Tax Liabilities Deferred income tax liabilities 6,142 5,806 Net Deferred Income Tax Liabilities 5,633 5,629 At December 31, 2021, the Company has recognized the benefit of non-capital loss carryforwards of $4,067 million (2020 – $3,671 million) for federal and provincial purposes in Canada, which expire from 2030 to 2041. The Company has not yet recognized the benefit of capital loss carryforwards of $21 million (2020 – $253 million) for federal and provincial purposes in Canada which have no expiry date. The Company also has Ontario minimum tax credits of $113 million (2020 – $106 million), which expire from 2026 to 2041. At December 31, 2021, the Company has fully recognized the benefit of net operating loss carryforwards of US$446 million (2020 – US$849 million) for federal purposes in the U.S., which expire in 2037. At December 31, 2021, the Company has recognized the benefit of net operating loss carryforwards of US$10 million (2020 – US$13 million) in Mexico, which expire from 2024 to 2031. TC Energy recorded an income tax valuation allowance of $229 million and $243 million against the deferred income tax asset balances at December 31, 2021 and 2020, respectively. 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, 2021, 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 per cent equity interest in Coastal GasLink LP. Refer to Note 28, 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, 2021 by approximately $896 million (2020 – $684 million) if there had been a provision for these taxes. Income Tax Payments Income tax payments of $371 million, net of refunds, were made in 2021 (2020 – payments, net of refunds, of $252 million; 2019 – payments, net of refunds, of $713 million). Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2021 2020 2019 (millions of Canadian $) Unrecognized tax benefit at beginning of year 52 29 19 Gross increases – tax positions in prior years 5 26 13 Gross decreases – tax positions in prior years (1) (2) (1) Gross increases – tax positions in current year 26 1 — Lapse of statutes of limitations (2) (2) (2) Unrecognized Tax Benefit at End of Year 80 52 29 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, 2021 reflects $1 million interest expense (2020 – $4 million; 2019 – $4 million). At December 31, 2021, the Company had accrued $12 million in interest expense (2020 – $11 million; 2019 – $7 million). The Company incurred no penalties associated with income tax uncertainties related to Income tax expense for the years ended December 31, 2021, 2020 and 2019 and no penalties were accrued as at December 31, 2021, 2020 and 2019. 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 2013. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2014. Substantially all material Mexico income tax matters have been concluded for years through 2013, except as further described below. Mexico Tax Audit In 2019, the Mexican tax authority, 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 which 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. In January 2022, the Company received the tax court’s ruling on the 2013 tax return, which was in favour of the SAT. The Company believes this ruling is unreasonable and did not conform with Mexican tax regulations and will appeal this decision. In support of the Company’s position, the Mexican Tax Ombudsman (the PRODECON), previously determined that this subsidiary’s tax filings were appropriate. 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 tax, interest, penalties and financial charges. If the SAT continues to reassess the tax filings of this subsidiary for subsequent years on a similar basis, there is a risk of a material increase to the Company’s exposure. Based on recent discussions with the SAT, the Company believes that the areas of concern are confined to a subset of matters within these assessments. The Company will defend its position on these assessments and pursue all available legal tax remedies.  Based on the Company’s own judgment, as well as that of third-party advisors, management believes it is more likely than not that the Company’s tax position will be sustained and no provision with respect to this matter has been recognized in the consolidated financial statements.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT 2021 2020 Outstanding amounts 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 Debentures U.S. (2021 – nil; 2020 – US$400) — — 510 9.9 % Medium Term Notes Canadian 2022 to 2049 12,491 4.2 % 11,491 4.5 % Senior Unsecured Notes U.S. (2021 – US$16,542; 2020 – US$14,292) 2022 to 2049 20,936 4.8 % 18,227 5.3 % 33,427 30,228 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2021 and 2020 – US$200) 2023 254 7.9 % 255 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2021 and 2020 – US$33) 2026 41 7.5 % 42 7.5 % 899 901 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2021 and 2020 – US$1,500) 2 2025 to 2045 1,898 4.9 % 1,913 4.9 % TC PIPELINES, LP Unsecured Term Loan U.S. (2021 – nil; 2020 – US$450) — — 574 1.4 % Senior Unsecured Notes U.S. (2021 – US$850; 2020 – US$1,200) 2025 to 2027 1,076 4.2 % 1,530 4.4 % 1,076 2,104 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2021 – US$372; 2020 – US$672) 2024 to 2026 472 5.3 % 858 7.2 % GAS TRANSMISSION NORTHWEST LLC Senior Unsecured Notes U.S. (2021 and 2020 – US$325) 2030 to 2035 411 4.3 % 415 4.3 % 2021 2020 Outstanding amounts 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 Unsecured Loan Facility U.S. (2021 – nil; 2020 – US$25) 2023 — — 32 1.3 % Senior Unsecured Notes U.S. (2021 – US$250; 2020 – US$125) 2030 to 2031 316 2.8 % 159 2.8 % 316 191 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2021 – US$167; 2020 – US$198) 2028 to 2030 211 7.6 % 253 7.6 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2021 – US$36; 2020 – US$23) 2024 46 1.3 % 29 2.2 % NORTH BAJA PIPELINE, LLC Unsecured Term Loan U.S. (2021 – nil; 2020 – US$50) — — 64 1.2 % 38,756 36,956 Current portion of long-term debt (1,320) (1,972) Unamortized debt discount and issue costs (243) (238) Fair value adjustments 3 148 167 37,341 34,913 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 Related to the acquisition of Columbia. Principal Repayments At December 31, 2021, principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2022 2023 2024 2025 2026 Principal repayments on long-term debt 1,320 1,823 2,657 2,698 1,778 Long-Term Debt Issued The Company issued long-term debt over the three years ended December 31, 2021 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED 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 % September 2019 Medium Term Notes September 2029 700 3.00 % September 2019 Medium Term Notes July 2048 300 4.18 % 2 April 2019 Medium Term Notes October 2049 1,000 4.34 % 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 3 Various Project-Level Credit Facility June 2021 US 849 Floating COLUMBIA PIPELINE GROUP, INC. 4 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 5 April 2020 Senior Secured Credit Facilities April 2027 1,603 Floating NORTHERN COURIER PIPELINE LIMITED PARTNERSHIP 6 July 2019 Senior Secured Notes June 2042 1,000 3.365 % 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 Reflects coupon rate on re-opening of a pre-existing MTN issue. The MTNs were issued at a premium to par, resulting in a re-issuance yield of 3.991 per cent. 3 On January 4, 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. 4 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. 5 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 28, Acquisitions and dispositions, for additional information. 6 In July 2019, subsequent to the Senior Secured Notes issuance, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier and subsequently accounted for its remaining interest using the equity method. On November 30, 2021, the Company sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 28, 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, 2021 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED 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 % November 2019 Senior Unsecured Notes US 700 2.125 % November 2019 Senior Unsecured Notes US 550 Floating May 2019 Medium Term Notes 13 9.35 % March 2019 Debentures 100 10.50 % January 2019 Senior Unsecured Notes US 750 7.125 % January 2019 Senior Unsecured Notes US 400 3.125 % 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 % June 2019 Unsecured Term Loan US 50 Floating 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 % May 2019 Unsecured Term Loan US 35 Floating 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. On March 4, 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 2021 2020 2019 (millions of Canadian $) Interest on long-term debt 1,841 1,963 1,931 Interest on junior subordinated notes 453 470 427 Interest on short-term debt 10 46 106 Capitalized interest (22) (294) (186) Amortization and other financial charges 1 78 43 55 2,360 2,228 2,333 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 $2,299 million in 2021 (2020 – $2,203 million; 2019 – $2,295 million) on long-term debt, junior subordinated notes and short-term debt, net of interest capitalized.

JUNIOR SUBORDINATED NOTES

JUNIOR SUBORDINATED NOTES	12 Months Ended
	Dec. 31, 2021
Junior Subordinated Notes [Abstract]
JUNIOR SUBORDINATED NOTES	JUNIOR SUBORDINATED NOTES 2021 2020 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 1,265 4.0 % 1,275 4.1 % US$750 notes issued 2015 at 5.875% 3,4 2075 949 5.0 % 957 5.0 % US$1,200 notes issued 2016 at 6.125% 3,4 2076 1,519 5.8 % 1,530 5.8 % US$1,500 notes issued 2017 at 5.55% 3,4 2077 1,899 4.7 % 1,913 4.7 % $1,500 notes issued 2017 at 4.90% 3,4 2077 1,500 4.5 % 1,500 4.5 % US$1,100 notes issued 2019 at 5.75% 3,4 2079 1,392 5.4 % 1,403 5.4 % $500 notes issued 2021 at 4.45% 3,4 2081 500 4.0 % — — 9,024 8,578 Unamortized debt discount and issue costs (85) (80) 8,939 8,498 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, a financing trust subsidiary wholly owned by TCPL. While the obligations of TransCanada 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 . The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. In March 2021, TransCanada Trust (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 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. In September 2019, the Trust issued US$1.1 billion of Trust Notes – Series 2019-A to investors with a fixed interest rate of 5.50 per cent per annum for the first 10 years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$1.1 billion of junior subordinated notes of TCPL at an initial fixed rate of 5.75 per cent, including a 0.25 per cent administration charge. The rate will reset commencing September 2029 until September 2049 to the then three-month LIBOR plus 4.404 per cent per annum; from September 2049 until September 2079, the interest rate will reset to the then three-month LIBOR plus 5.154 per cent per annum. Refer to Note 3, Accounting changes, for additional information regarding the expected impact to the Company with certain rate settings of LIBOR which ceased to be published at the end of 2021 with full cessation by mid-2023. The junior subordinated notes are callable at TCPL's option at any time on or after September 15, 2029 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. Pursuant to the terms of the notes issued between the Trust and TCPL (the Trust Notes) and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TC Energy and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with any other outstanding first preferred shares of TCPL.

NON-CONTROLLING INTERESTS

NON-CONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2021
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 and 2019 – 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 2021 2020 2019 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 60 284 270 Non-controlling interest in PNGTS 30 23 23 Redeemable non-controlling interest (Note 6) 1 (10) — 91 297 293

COMMON SHARES

COMMON SHARES	12 Months Ended
	Dec. 31, 2021
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
COMMON SHARES	COMMON SHARES Number of Shares Amount (thousands) (millions of Canadian $) Outstanding at January 1, 2019 918,097 23,174 Dividend reinvestment and share purchase plan 15,165 931 Exercise of options 5,138 282 Outstanding at December 31, 2019 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 21) 37,955 2,063 Exercise of options 2,797 165 Outstanding at December 31, 2021 980,816 26,716 Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares without par value. 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 21, Non-controlling interests, for additional information. 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 October 31, 2019, common shares purchased with reinvested cash dividends under the Company's DRP are acquired on the open market at 100 per cent of the weighted average purchase price. From January 1, 2019 to October 31, 2019, common shares under the DRP were issued from treasury at a two per cent discount to market prices over a specified period. TC Energy Corporation At-the-Market Equity Issuance Program In December 2020, the Company established an At-the-Market Program (ATM Program) that allows, 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. This ATM program is effective for a 25-month period and will be utilized as appropriate to assist in managing the Company's capital structure. Under this program the Company could issue up to $1.0 billion in common shares or the U.S. dollar equivalent. No common shares were issued under this program in 2021 or 2020. 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 shares issuable under the DRP up to October 31, 2019 when participation was satisfied with common shares issued from treasury. Weighted Average Common Shares Outstanding (millions) 2021 2020 2019 Basic 973 940 929 Diluted 974 940 931 Stock Options Number of Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (thousands) (years) Options outstanding at January 1, 2021 8,996 $59.55 Options granted 1,679 $56.86 Options exercised (2,797) $53.10 Options forfeited/expired (109) $59.96 Options Outstanding at December 31, 2021 7,769 $61.29 4.2 Options Exercisable at December 31, 2021 4,410 $60.13 3.2 At December 31, 2021, an additional 4,826,189 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 applying the following weighted average assumptions: year ended December 31 2021 2020 2019 Weighted average fair value $7.39 $7.73 $6.37 Expected life (years) 1 5.4 5.7 5.7 Interest rate 0.5 % 1.5 % 1.9 % Volatility 2 25 % 17 % 19 % Dividend yield 6.0 % 4.2 % 5.0 % 1 Expected life is based on historical exercise activity. 2 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. The amount expensed for stock options, with a corresponding increase in Additional paid-in capital was $12 million in 2021 (2020 – $12 million; 2019 – $13 million). At December 31, 2021, unrecognized compensation costs related to non-vested stock options were $13 million. The cost is expected to be fully recognized over a weighted average period of 1.8 years. The following table summarizes additional stock option information: year ended December 31 2021 2020 2019 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 28 31 75 Total fair value of options that have vested 110 101 143 Total options vested 1.9 million 2.0 million 2.1 million As at December 31, 2021, the aggregate intrinsic value of the total options exercisable was $7 million and the aggregate intrinsic value of options outstanding was $12 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
	Dec. 31, 2021
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
PREFERRED SHARES	PREFERRED SHARES at 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 2021 2020 2019 (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 4 246 246 209 Series 4 4,003 Floating 4 Floating $25.00 June 30, 2025 Series 3 97 97 134 Series 5 12,071 1.949 % 5 $0.48725 $25.00 January 30, 2026 Series 6 294 310 310 Series 6 1,929 Floating 4 Floating $25.00 January 30, 2026 Series 5 48 32 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 — — — — — — — 493 493 Series 15 40,000 4.90 % $1.225 $25.00 May 31, 2022 Series 16 988 988 988 3,487 3,980 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), 2.96 per cent (Series 12), or 3.85 per cent (Series 16). 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), 2.96 per cent (Series 11), or 3.85 per cent, subject to a minimum of 4.90 per cent (Series 15). 3 Net of underwriting commissions and deferred income taxes. 4 The floating quarterly dividend rate for the Series 2 preferred shares is 2.049 per cent for the period starting December 31, 2021 to, but excluding, March 31, 2022. The floating quarterly dividend rate for the Series 4 preferred shares is 1.409 per cent for the period starting December 31, 2021 to, but excluding, March 31, 2022. The floating quarterly dividend rate for the Series 6 preferred shares is 1.686 per cent for the period starting October 30, 2021 to, but excluding, January 30, 2022. 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, 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, as previously declared on May 6, 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. On February 1, 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. On June 30, 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. On December 31, 2019, 173,954 Series 1 preferred shares were converted, on a one-for-one basis, into Series 2 preferred shares and 5,252,715 Series 2 preferred shares were converted, on a one-for-one basis, into Series 1 preferred shares.

OTHER COMPREHENSIVE INCOME _ (L

OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCI)	OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE 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, 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) year ended December 31, 2019 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 (914) (30) (944) Reclassification of foreign currency translation gains on disposal of foreign operations (13) — (13) Change in fair value of net investment hedges 46 (11) 35 Change in fair value of cash flow hedges (78) 16 (62) Reclassification to net income of gains and losses on cash flow hedges 19 (5) 14 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (15) 5 (10) Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans 14 (4) 10 Other comprehensive loss on equity investments (114) 32 (82) Other Comprehensive Loss (1,055) 3 (1,052) 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, 2019 107 (23) (314) (376) (606) Other comprehensive loss before reclassifications 2 (824) (49) (10) (86) (969) Amounts reclassified from AOCI (13) 14 10 5 16 Net current period other comprehensive loss (837) (35) — (81) (953) AOCI balance at December 31, 2019 (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 3 — 55 14 28 97 Net current period other comprehensive (loss)/income (98) 44 172 534 652 Acquisition of TC PipeLines, LP 4 362 (13) — 4 353 AOCI balance at December 31, 2021 (1,009) (112) (113) (200) (1,434) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 Other comprehensive (loss)/income before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling interest losses of $12 million (2020 – losses of $30 million; 2019 – losses of $85 million), gains of $1 million (2020 – losses of $16 million; 2019 – losses of $13 million), and gains of $1 million (2020 – gains of $1 million; 2019 – losses of $1 million ), respectively. 3 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $62 million ($47 million, net of tax) at December 31, 2021. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. 4 Represents the AOCI attributable to 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 21, Non-controlling interests, for additional information. Details about reclassifications out of AOCI into the Consolidated statement of income were as follows: year ended December 31 Amounts Reclassified From AOCI Affected Line Item in the Consolidated Statement of Income 1 2021 2020 2019 (millions of Canadian $) Cash flow hedges Commodities (22) (1) (7) Revenues (Power and Storage) Interest rate (46) (28) (12) Interest expense Interest rate — (613) — Net gain/(loss) on assets sold/held for sale 2 (68) (642) (19) Total before tax 13 160 5 Income tax expense 2 (55) (482) (14) Net of tax 3 Pension and other post-retirement benefit plan adjustments Amortization of actuarial losses (22) (23) (14) Plant operating costs and other 4 Settlement gain 2 — — Plant operating costs and other 4 (20) (23) (14) Total before tax 6 6 4 Income tax expense (14) (17) (10) Net of tax Equity investments Equity income (37) (15) (8) Income from equity investments 9 4 3 Income tax expense (28) (11) (5) Net of tax 3 Currency translation adjustments Foreign currency translation gains on disposal of foreign operations — — 13 Net gain/(loss) on assets sold/held for sale — — — Income tax expense — — 13 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 28, Acquisitions and dispositions, for additional information. 3 Amounts reclassified from AOCI on cash flow hedges are net of non-controlling interest of nil (2020 – losses of $7 million; 2019 – nil). 4 These AOCI components are included in the computation of net benefit cost. Refer to Note 25, Employee post-retirement benefits, for additional information.

EMPLOYEE POST-RETIREMENT BENEFI

EMPLOYEE POST-RETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2021
Retirement Benefits [Abstract]
EMPLOYEE POST-RETIREMENT BENEFITS	EMPLOYEE POST-RETIREMENT BENEFITS The Company sponsors DB Plans for certain of its 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 11 years at December 31, 2021 (2020 and 2019 – 11 years). In 2021, the Company expensed $58 million (2020 – $58 million; 2019 – $61 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 2021 2020 2019 (millions of Canadian $) DB Plans 105 124 122 Other post-retirement benefit plans 8 9 22 Savings and DC Plans 58 58 61 171 191 205 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. As such, in addition to the cash contributions noted above, the Company provided a $20 million letter of credit to the Canadian DB Plan in 2021 (2020 – $13 million; 2019 – $12 million), resulting in a total of $322 million provided to the Canadian DB Plan under letters of credit at December 31, 2021. The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2021 and the next required valuation will be as at January 1, 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, a settlement and curtailment occurred for the U.S. DB Plan in December 2021. 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. Employee participation in the VRP also resulted in a curtailment in the U.S. other post-retirement benefits plan (OPEB) in December 2021. The curtailment loss decreased the Plan'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 $) 2021 2020 2021 2020 Change in Benefit Obligation 1 Benefit obligation – beginning of year 4,326 4,058 457 427 Service cost 171 155 6 6 Interest cost 119 133 12 14 Employee contributions 6 6 1 — Benefits paid (372) (249) (21) (21) Actuarial (gain)/loss (208) 242 (35) 36 Curtailment (5) — 3 — Foreign exchange rate changes (10) (19) (4) (5) Benefit obligation – end of year 4,027 4,326 419 457 Change in Plan Assets Plan assets at fair value – beginning of year 4,038 3,693 441 406 Actual return on plan assets 376 485 5 56 Employer contributions 2 105 124 8 9 Employee contributions 6 6 1 — Benefits paid (372) (249) (21) (21) Foreign exchange rate changes (8) (21) (3) (9) Plan assets at fair value – end of year 4,145 4,038 431 441 Funded Status – Plan Surplus/(Deficit) 118 (288) 12 (16) 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 $20 million letter of credit provided to the Canadian DB Plan for funding purposes (2020 – $13 million). The actuarial gain realized on the defined benefit plan obligation is primarily attributable to an increase in the weighted average discount rate from 2.70 per cent in 2020 to 3.05 per cent in 2021. 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 2.75 per cent in 2020 to 3.10 per cent in 2021. 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 $) 2021 2020 2021 2020 Other long-term assets (Note 14) 119 29 193 178 Accounts payable and other — — (8) (8) Other long-term liabilities (Note 17) (1) (317) (173) (186) 118 (288) 12 (16) 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 $) 2021 2020 2021 2020 Projected benefit obligation 1 (2,687) (3,292) (183) (194) Plan assets at fair value 2,686 2,975 — — Funded Status – Plan Deficit (1) (317) (183) (194) 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 2021 2020 (millions of Canadian $) Accumulated benefit obligation (3,714) (3,957) Plan assets at fair value 4,145 4,038 Funded Status – Plan Surplus 431 81 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, 2021 and December 31, 2020. The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: at December 31 Percentage of Target Allocations 2021 2020 2021 Debt securities 34 % 33 % 25% to 45% Equity securities 53 % 57 % 35% to 65% Alternatives 13 % 10 % 10% to 20% 100 % 100 % Debt and equity securities include the Company's debt and common shares as follows: at December 31 Percentage of (millions of Canadian $) 2021 2020 2021 2020 Debt securities 7 13 0.2 % 0.3 % Equity securities 5 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 the use of leveraged derivatives is prohibited. 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 26, Risk management and financial instruments. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 Asset Category Cash and Cash Equivalents 68 87 2 — — — 70 87 2 2 Equity Securities: Canadian 269 276 148 177 — — 417 453 9 10 U.S. 649 594 164 211 — — 813 805 18 18 International 126 114 354 380 — — 480 494 10 11 Global 111 116 313 368 — — 424 484 9 11 Emerging 25 35 120 125 — — 145 160 3 4 Fixed Income Securities: Canadian Bonds: Federal — — 226 207 — — 226 207 5 5 Provincial — — 331 283 — — 331 283 7 6 Municipal — — 16 13 — — 16 13 — — Corporate — — 147 151 — — 147 151 4 3 U.S. Bonds: Federal 433 444 15 14 — — 448 458 10 10 Municipal — — 1 2 — — 1 2 — — Corporate 67 72 143 143 — — 210 215 5 5 International: Government 6 8 7 6 — — 13 14 — — Corporate — — 73 48 — — 73 48 2 1 Mortgage backed 42 47 5 4 — — 47 51 1 1 Other Investments: Real estate — — — — 283 213 283 213 6 5 Infrastructure — — — — 281 203 281 203 6 5 Private equity funds — — — — 1 1 1 1 — — Derivatives — — — (8) — — — (8) — — Funds held on deposit 150 145 — — — — 150 145 3 3 1,946 1,938 2,065 2,124 565 417 4,576 4,479 100 100 The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Balance at December 31, 2019 379 Purchases and sales 42 Realized and unrealized losses (4) Balance at December 31, 2020 417 Purchases and sales 100 Realized and unrealized gains 48 Balance at December 31, 2021 565 The Company's expected funding contributions in 2022 are approximately $76 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $55 million for the savings plans and DC Plans. The Company expects to provide an additional estimated $20 million letter 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 2022 208 25 2023 211 25 2024 216 24 2025 220 24 2026 224 24 2027 to 2031 1,171 114 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, 2021. 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 2021 2020 2021 2020 Discount rate 3.05 % 2.70 % 3.10 % 2.75 % Rate of compensation increase 2.95 % 2.60 % — — 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 2021 2020 2019 2021 2020 2019 Discount rate 2.70 % 3.20 % 3.90 % 2.80 % 3.35 % 4.10 % Expected long-term rate of return on plan assets 6.15 % 6.40 % 6.60 % 3.00 % 3.50 % 4.30 % Rate of compensation increase 2.60 % 3.00 % 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 5.60 per cent weighted-average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2022 measurement purposes. The rate was assumed to decrease gradually to 5.00 per cent by 2029 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 $) 2021 2020 2019 2021 2020 2019 Service cost 1 171 155 126 6 6 5 Other components of net benefit cost 1 Interest cost 119 133 142 12 14 17 Expected return on plan assets (234) (230) (222) (13) (14) (15) Amortization of actuarial loss 23 21 12 2 2 2 Amortization of regulatory asset 27 25 14 2 2 2 Curtailment gain (5) — — — — — Settlement gain – AOCI (2) — — — — — (72) (51) (54) 3 4 6 Net Benefit Cost Recognized 99 104 72 9 10 11 1 Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income. Pre-tax amounts recognized in AOCI were as follows: at December 31 2021 2020 2019 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Net loss 147 5 358 22 398 20 Pre-tax amounts recognized in OCI were as follows: at December 31 2021 2020 2019 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Amortization of net loss from AOCI to net income (23) (2) (21) (2) (12) (2) Curtailment — 3 — — — — Settlement 2 — — — — — Funded status adjustment (190) (18) (18) 3 52 (37) (211) (17) (39) 1 40 (39)

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2021
Risk Management and Financial Instruments [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Risk Management Overview TC Energy has exposure to market risk and counterparty credit risk, 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. Market risk and counterparty credit risk are managed within limits that are established by the Company's Board of Directors, implemented by senior management and monitored by the Company's risk management, internal audit and business segment groups. The Board of Directors' Audit Committee oversees how management monitors compliance with market risk and counterparty credit 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 supply of 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 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. Many of TC Energy's financial instruments and contractual obligations with variable rate components reference U.S. dollar LIBOR, of which certain rate settings have ceased to be published at the end of 2021 with full cessation by mid-2023. 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 small portion of the Company's Mexico Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while the functional currency for our 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. This exposure is 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, foreign exchange forwards 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 2021 2020 Fair 1,2 Notional Amount Fair 1,2 Notional Amount (millions of Canadian $, unless otherwise noted) U.S. dollar foreign exchange options (maturing 2022 to 2023) (4) US 3,800 45 US 2,200 U.S. dollar cross-currency interest rate swaps (maturing 2022 to 2025) 3 23 US 400 23 US 400 19 US 4,200 68 US 2,600 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2021, Net income includes net realized gains of $1 million (2020 – 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 2021 2020 (millions of Canadian $, unless otherwise noted) Notional amount 30,700 (US 24,200) 27,700 (US 21,800) Fair value 35,500 (US 28,100) 33,800 (US 26,500) 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 and loans receivable. The sustained impact of the COVID-19 pandemic and related global energy demand and supply disruption continues to contribute to market uncertainty impacting a number of TC Energy's customers. While the majority of the Company's credit exposure is to large creditworthy entities, TC Energy has increased its monitoring and communication with those counterparties experiencing greater financial pressures. 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 • competitive position of the Company's assets and the demand for the Company's services and • 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 supportable forecasts to determine any impairment, which is recognized in Plant operating costs and other. At December 31, 2021 and 2020, there were no significant credit losses, no significant credit risk concentrations and no significant amounts past due or impaired. TC Energy has significant credit and performance exposure to financial institutions because they 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. 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 affiliates, Restricted investments, Other long-term assets, Notes payable, Accounts payable and other, Dividends payable, Accrued interest and Other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity. 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 2021 2020 Carrying Amount Fair Value Carrying Fair (millions of Canadian $) Long-term debt, including current portion (Note 19) (38,661) (45,615) (36,885) (46,054) Junior subordinated notes (Note 20) (8,939) (9,236) (8,498) (8,908) (47,600) (54,851) (45,383) (54,962) 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 2021 2020 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 — 26 — 17 Maturing within 1-5 years 8 107 — 66 Maturing within 5-10 years 1,150 — 985 — Maturing after 10 years 84 — 85 — Fair value of equity securities 2,4 817 — 736 — 2,059 133 1,806 83 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 2021 2020 2019 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized gains/(losses) 45 (2) 130 1 32 3 Net realized gains 3 3 — 20 1 60 — 1 Gains 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 as regulatory assets. 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. 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 recovered or refunded 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 ratepayers 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, 2021 Cash Flow Hedges Net Held for Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 — — 122 122 Foreign exchange — 10 37 47 — 10 159 169 Other long-term assets (Note 14) Commodities 2 — — 8 8 Foreign exchange — 32 6 38 Interest rate 3 2 — — 2 2 32 14 48 Total Derivative Assets 2 42 173 217 Accounts payable and other (Note 16) Commodities 2 (23) — (138) (161) Foreign exchange — (4) (46) (50) Interest rate 3 (10) — — (10) (33) (4) (184) (221) Other long-term liabilities (Note 17) Commodities 2 (4) — (6) (10) Foreign exchange — (19) (10) (29) Interest rate 3 (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. 3 For the year ended December 31, 2021, a $10 million payment to settle a loss on financial instruments was included in Net cash (used in)/provided by financing activities in the Consolidated statement of cash flows. The balance sheet classification of the fair value of derivative instruments was as follows: at December 31, 2020 Cash Flow Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 — — 13 13 Foreign exchange — 47 175 222 — 47 188 235 Other long-term assets (Note 14) Foreign exchange — 22 19 41 — 22 19 41 Total Derivative Assets — 69 207 276 Accounts payable and other (Note 16) Commodities 2 (8) — (32) (40) Foreign exchange — (1) (10) (11) Interest rate 3 (21) — — (21) (29) (1) (42) (72) Other long-term liabilities (Note 17) Commodities 2 (6) — (4) (10) Interest rate 3 (49) — — (49) (55) — (4) (59) Total Derivative Liabilities (84) (1) (46) (131) Total Derivatives (84) 68 161 145 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. 3 For the year ended December 31, 2020, a $130 million payment to settle a loss on financial instruments was included in Net cash (used in)/provided by financing activities in the Consolidated statement of cash flows. 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. 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, 2021 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 553 104 34 — — Sales 1 1,043 52 38 — — 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. at December 31, 2020 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 185 13 26 — — Sales 1 1,786 14 30 — — Millions of U.S. dollars — — — 4,432 1,100 Millions of Mexican pesos — — — 1,700 — Maturity dates 2021-2025 2021-2027 2021 2021-2022 2022-2026 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively. Unrealized and Realized Gains/(Losses) on Derivative Instruments The following summary does not include hedges of the net investment in foreign operations: year ended December 31 2021 2020 2019 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized gains/(losses) in the year Commodities 9 (23) (111) Foreign exchange (203) 126 245 Amount of realized gains/(losses) in the year Commodities 287 183 378 Foreign exchange 240 (33) (70) Derivative instruments in hedging relationships 2 Amount of realized (losses)/gains in the year Commodities (44) 6 (6) Interest rate (32) (16) 2 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 Interest income and other. 2 In 2021, 2020 and 2019, 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. Derivatives in cash flow hedging relationships The components of OCI (Note 24) 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 2021 2020 2019 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI 1 Commodities (35) (5) (15) Interest rate 22 (766) (63) (13) (771) (78) 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 2021 2020 2019 (millions of Canadian $) Fair Value Hedges Interest rate contracts 1 Hedged items — (3) (19) Derivatives designated as hedging instruments — 1 1 Cash Flow Hedges Reclassification of losses on derivative instruments from AOCI to net income 2,3 Interest rate contracts 1 (46) (648) (12) Commodity contracts 4 (22) (1) (7) 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 assets sold/held for sale. Refer to Note 28, Acquisitions and dispositions, for additional information. 2 Refer to Note 24, Other comprehensive income/(loss) and accumulated other comprehensive 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 Storage) 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, 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. at December 31, 2020 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative instrument assets Commodities 13 (7) 6 Foreign exchange 263 (11) 252 276 (18) 258 Derivative instrument liabilities Commodities (50) 7 (43) Foreign exchange (11) 11 — Interest rate (70) — (70) (131) 18 (113) 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 $144 million and letters of credit of $130 million at December 31, 2021 (2020 – $54 million and $15 million, respectively) to its counterparties. At December 31, 2021, the Company held no cash collateral and a $6 million balance in letters of credit (2020 – nil and nil, 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, 2021, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $5 million (2020 – $4 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, 2021, 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 mainly 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, 2021 Quoted Prices in Active Markets 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. at December 31, 2020 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 3 10 — 13 Foreign exchange — 263 — 263 Derivative instrument liabilities Commodities (15) (31) (4) (50) Foreign exchange — (11) — (11) Interest rate — (70) — (70) (12) 161 (4) 145 1 There were no transfers from Level II to Level III for the year ended December 31, 2020. 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) 2021 2020 Balance at beginning of year (4) (7) Total (losses)/gains included in Net income (3) 3 Settlements 1 — Balance at end of year 1 (6) (4) 1 Revenues include unrealized losses of $3 million attributed to derivatives in the Level III category that were still held at December 31, 2021 (2020 – unrealized gains of $3 million) .

CHANGES IN OPERATING WORKING CA

CHANGES IN OPERATING WORKING CAPITAL	12 Months Ended
	Dec. 31, 2021
CHANGES IN OPERATING WORKING CAPITAL
CHANGES IN OPERATING WORKING CAPITAL	CHANGES IN OPERATING WORKING CAPITAL year ended December 31 2021 2020 2019 (millions of Canadian $) (Increase)/decrease in Accounts receivable (925) 129 31 Increase in Inventories (93) (55) (42) Increase in Other current assets (141) (221) (15) Increase/(decrease) in Accounts payable and other 890 (162) 352 Decrease in Accrued interest (18) (18) (33) (Increase)/Decrease in Operating Working Capital (287) (327) 293

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2021
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 assets sold/held for sale 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. U.S. Natural Gas Pipelines Columbia Midstream Assets In August 2019, TC Energy completed the sale of certain Columbia Midstream assets to a third party for approximately US$1.3 billion before post-closing adjustments. The Company recorded a pre-tax gain on sale of $21 million ($152 million after-tax loss) including the impact of $4 million of foreign currency translation gains that were reclassified from AOCI to net income and the release of $595 million of Columbia goodwill allocated to these assets that was not deductible for income tax purposes. The pre-tax gain was included in Net gain/(loss) on assets sold/held for sale in the Consolidated statement of income. This sale did not include any interest in Columbia Energy Ventures Company, the Company's minerals business in the Appalachian basin. In 2020, upon finalizing its 2019 annual tax returns for its U.S. operations, the Company recorded an $18 million income tax recovery related to the sale. Columbia Pipeline Group, Inc. At the time of the July 2016 acquisition of Columbia, certain Columbia shareholders dissented from the transaction and did not tender their shares. In October 2019, TC Energy made a payment to the dissenting Columbia shareholders in the amount of $373 million (US$284 million), representing the appraised value of their shares pursuant to a court decision, which affirmed the original Columbia share purchase price of US$25.50 per share plus accrued interest. Liquids Pipelines Northern Courier In July 2019, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier pipeline to a third party for gross proceeds of $144 million before post-closing adjustments resulting in a pre-tax gain of $69 million after recording the Company’s remaining 15 per cent interest at fair value. The pre-tax gain was included in Net gain/(loss) on assets sold/held for sale in the Consolidated statement of income. On an after-tax basis, the gain of $115 million reflected the utilization of previously unrecognized tax loss benefits. Preceding the equity sale, Northern Courier pipeline issued $1.0 billion of long-term, non-recourse debt with all proceeds paid to TC Energy. On November 30, 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 assets sold/held for sale in the Consolidated statement of income. Power and Storage 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 assets sold/held for sale for sale in the Consolidated statement of income. This loss may be amended in the future upon the settlement of existing insurance claims. Coolidge Generating Station In May 2019, the Company completed the sale of its Coolidge generating station in Arizona to Salt River Project Agriculture Improvement and Power District (SRP), the PPA counterparty, as per the terms of SRP’s contractual right of first refusal, for proceeds of US$448 million before post-closing adjustments. As a result, the Company recorded a pre-tax gain on sale of $68 million ($54 million after tax) including the impact of $9 million of foreign currency translation gains which were reclassified from AOCI to net income. The pre-tax gain was included in Net gain/(loss) on assets sold/held for sale in the Consolidated statement of income.

COMMITMENTS, CONTINGENCIES AND

COMMITMENTS, CONTINGENCIES AND GUARANTEES	12 Months Ended
	Dec. 31, 2021
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 2021 were $239 million (2020 – $224 million; 2019 – $236 million). The Company has entered into PPAs with solar and wind-power generating facilities ranging from eight 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, 2021, TC Energy had the following capital expenditure commitments: • approximately $1.5 billion for its Canadian natural gas pipelines, primarily related to construction costs associated with NGTL System expansion projects • approximately $0.1 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with ANR and Columbia Gas pipeline projects • approximately $0.1 billion for its Mexico natural gas pipelines, primarily related to construction of the Tula and Villa de Reyes pipelines • approximately $0.1 billion for its Liquids pipelines, primarily related to capital projects in the U.S. Gulf Coast • approximately $0.1 billion for its Power and Storage 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. As at December 31, 2021, the Company had accrued approximately $30 million (2020 – $24 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, excluding the legal proceeding related to Keystone XL described below, will not have a material impact on the Company's consolidated financial position or results of operations. On November 22, 2021, TC Energy filed a Request for Arbitration to formally initiate a legacy North American Free Trade Agreement (NAFTA) claim to recover economic damages resulting from the revocation of the Presidential Permit for the Keystone XL pipeline project. The Company will be seeking to recover more than US$15 billion in damages as a result of the U.S. Government's breach of its NAFTA obligations. This claim is in a preliminary stage and the timing of outcome is unknown at present. Guarantees On November 30, 2021, TC Energy completed the sale of its remaining 15 per cent equity interest in the Northern Courier pipeline and subsequently released all associated guarantees. Refer to Note 28, Acquisitions and dispositions, for additional information. As part of its role as operator of the Northern Courier pipeline prior to the sale, TC Energy had guaranteed the financial performance of the pipeline related to delivery and terminalling of bitumen and diluent and contingent financial obligations under sub-lease agreements. 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. 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 2021 2020 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas to 2043 93 — 100 — Bruce Power to 2023 88 — 88 — Other jointly-owned entities to 2043 80 4 78 4 Northern Courier pipeline 2 — — 300 26 261 4 566 30 1 TC Energy's share of the potential estimated current or contingent exposure.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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. In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are considered non-consolidated VIEs and are accounted for as equity investments. Consolidated VIEs The Company's consolidated VIEs consist of legal entities where the Company is 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. 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 $) 2021 2020 ASSETS Current Assets Cash and cash equivalents 72 254 Accounts receivable 70 61 Inventories 28 26 Other current assets 13 11 183 352 Plant, Property and Equipment 3,672 3,325 Equity Investments 890 714 Goodwill 421 424 Other Long-Term Assets — 8 5,166 4,823 LIABILITIES Current Liabilities Accounts payable and other 232 109 Redeemable non-controlling interest — 633 Accrued interest 17 21 Current portion of long-term debt 29 579 278 1,342 Regulatory Liabilities 66 60 Other Long-Term Liabilities 1 11 Deferred Income Tax Liabilities 13 12 Long-Term Debt 2,025 2,468 2,383 3,893 At December 31, 2020, certain consolidated VIEs had a redeemable non-controlling interest that ranked above the Company's equity interest. Refer to Note 6, Keystone XL, for additional information. Non-Consolidated VIEs The Company’s non-consolidated VIEs consist of legal entities where the Company is not the primary beneficiary as it does not have the power 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. 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 $) 2021 2020 Balance sheet Loan receivable from affiliate (Note 11) 1 — Equity investments Bruce Power 4,493 3,306 Pipeline equity investments and other 1 1,605 1,371 Long-term loan receivable from affiliate (Note 11) 238 — Off-balance sheet 2 Coastal GasLink 3 3,037 1,107 Bruce Power 974 1,183 Pipeline equity investments 1 171 399 Maximum exposure to loss 10,519 7,366 1 On November 30, 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 28, Acquisitions and dispositions, for additional information. 2 Includes maximum potential exposure to guarantees and future funding commitments.

ACCOUNTING POLICIES (Policies)

ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2021
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, although certain non-controlling interests with redemption features are presented in mezzanine equity. TC Energy uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. Certain prior year amounts have been reclassified to conform to current year presentation.
Use of Estimates and Judgments	Use of Estimates and Judgments In preparing these consolidated financial statements, TC Energy is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Certain estimates and judgments have a material impact where the assumptions underlying these accounting estimates relate to matters that are highly uncertain at the time the estimate or judgment is made or are subjective. These estimates and judgments include, but are not limited to: • fair value of reporting units that contain goodwill (Notes 13 and 28) • fair value of assets and liabilities acquired in a business combination (Note 28). 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 8) • determining whether a contract contains a lease (Note 9) • fair value of equity investments (Note 10) • carrying value of regulatory assets and liabilities (Note 12) • carrying value of asset retirement obligations (Note 17) • provisions for income taxes, including valuation allowances and releases (Note 18) • assumptions used to measure retirement and other post-retirement benefit obligations (Note 25) • fair value of financial instruments (Note 26) • provisions for commitments, contingencies and guarantees (Note 29). 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. The impact of these changes are 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), formerly the National Energy Board (NEB), the Alberta Energy Regulator or the B.C. Oil and Gas Commission. In the U.S., regulated natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TC Energy's rate-regulated businesses which may differ from that otherwise recognized in non-rate-regulated businesses to reflect the economic impact of the regulators' decisions regarding revenues and tolls. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An operation qualifies for the use of RRA when it meets three criteria: • a regulator must establish or approve the rates for the regulated services or activities • the regulated rates must be designed to recover the cost of providing the services or products and • 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. 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. During 2019, TC Energy sold certain Columbia Midstream assets that were part of the acquisition of Columbia Pipeline Group, Inc.(Columbia) in 2016. Prior to the sale, revenues from the Company's midstream natural gas services, including gathering, treating, conditioning, processing, compression and liquids handling services, were generated from contractual arrangements and were recognized ratably over the term of the contract. Midstream natural gas service revenues were invoiced and received on a monthly basis. The Company did not take ownership of the natural gas for which it provided midstream services. Refer to Note 28, Acquisitions and dispositions, for additional information regarding the sale of the Columbia Midstream assets. Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. Other The Company is contracted to provide operating services to a partially-owned entity for a fee which is recognized over time as services are provided. The Company's construction services to this entity have been performed and the related development fee has been recognized. 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 Storage Power Revenues from the Company's Power and Storage 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.
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 and proprietary natural gas inventory in storage. Inventories are carried at the lower of cost and net realizable value.
Impairment of Long-Lived Assets and Financial Assets	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. Impairment of Long-Lived Assets The Company reviews long-lived assets such as plant, property and equipment, equity investments 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 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 supportable forecasts to determine any impairment, which is recognized in Plant operating costs and other.
Plant, Property and Equipment and Capital Projects in Development	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 0.6 per cent to seven 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. Prior to its sale in 2019, plant, property and equipment for Columbia Midstream was carried at cost. Depreciation was calculated on a straight-line basis once the assets were ready for their intended use. Gathering and processing facilities were depreciated at annual rates ranging from 1.7 per cent to 2.5 per cent, and other plant and equipment were depreciated at various rates reflecting their estimated useful lives. When these assets were retired from plant, property and equipment, the original book cost and related accumulated depreciation were derecognized and any gain or loss was recorded in net income. Refer to Note 28, Acquisitions and dispositions, for additional information. 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 Storage Plant, property and equipment for Power and Storage 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 a construction stage is probable or costs are otherwise likely to be recoverable. The Company also 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, Lessee Accounting Policy	Leases Lessee Accounting Policy The Company determines if an arrangement is a lease at inception of the contract. 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 expedients to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption and to not separate lease and non-lease components for all leases for which the Company is a lessee.
Leases, Lessor Accounting Policy	Lessor Accounting Policy The Company is the lessor within certain contracts, including power purchase agreements (PPA), and these are accounted for as operating leases. The Company recognizes lease payments as income over the lease term on a straight-line basis. Variable lease payments are recognized as income in the period in which they occur. The Company applies the practical expedient to not separate lease and non-lease components for facilities and liquids tank terminals for which the Company is the lessor.
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. 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.
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	Environmental Liabilities 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. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.
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.
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.
Accounting Changes	ACCOUNTING CHANGES Changes in Accounting Policies for 2021 Income Taxes In December 2019, the Financial Accounting Standards Board (FASB) issued new guidance that simplified the accounting for income taxes and clarified existing guidance. This new guidance was effective January 1, 2021, and did not have a material impact on the Company's consolidated financial statements. Reference Rate Reform In response to the expected cessation of the U.S. dollar London Interbank Offered Rate (LIBOR), for which certain rate settings ceased to be published at the end of 2021 with full cessation by mid-2023, the FASB issued new optional guidance in March 2020 that eases the potential burden in accounting for such reference rate reform. The new guidance provides optional expedients for contracts and hedging relationships that are affected by reference rate reform if certain criteria are met. Each of the expedients can be applied as of January 1, 2020 through December 31, 2022. For eligible hedging relationships existing as of January 1, 2020 and prospectively, the Company has applied an optional expedient allowing an entity to assume that the hedged forecasted transaction in a cash flow hedge is probable of occurring. The Company has completed necessary system changes to facilitate the adoption of the proposed standard market reference rates. The Company has also completed its analysis of contracts impacted by reference rate reform. Contract modifications, if required, will take place prior to the full cessation date in mid-2023. 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 consolidated financial statements; however, the Company will continue to monitor any new developments up to the full cessation date. Future Accounting Changes 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 is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements. Contract Assets and Liabilities from Contracts with Customers

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	year ended December 31, 2021 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Storage 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 Interest income and other 3 200 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 Interest income and other by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 11, 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 Storage 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 Interest income and other 3 213 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 Interest income and other by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 11, Loans receivable from affiliates, for additional information. year ended December 31, 2019 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Storage Corporate 1 Total (millions of Canadian $) Revenues 4,010 4,978 603 2,879 785 — 13,255 Intersegment revenues — 164 — — 19 (183) 2 — 4,010 5,142 603 2,879 804 (183) 13,255 Income/(loss) from equity investments 12 264 56 70 571 (53) 3 920 Plant operating costs and other (1,473) (1,581) (54) (728) (243) 166 2 (3,913) Commodity purchases resold — — — — (365) — (365) Property taxes (275) (345) — (101) (6) — (727) Depreciation and amortization (1,159) (754) (115) (341) (95) — (2,464) Net gain/(loss) on assets sold/held for sale — 21 — 69 (211) — (121) Segmented Earnings/(Losses) 1,115 2,747 490 1,848 455 (70) 6,585 Interest expense (2,333) Allowance for funds used during construction 475 Interest income and other 3 460 Income before Income Taxes 5,187 Income tax expense (754) Net Income 4,433 Net income attributable to non-controlling interests (293) Net Income Attributable to Controlling Interests 4,140 Preferred share dividends (164) Net Income Attributable to Common Shares 3,976 Capital Spending Capital expenditures 3,900 2,500 323 239 481 32 7,475 Capital projects in development 6 — — 701 — — 707 Contributions to equity investments — 16 34 14 538 — 602 3,906 2,516 357 954 1,019 32 8,784 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income/(loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains and losses on the peso-denominated loans from affiliates which are fully offset in Interest income and other by the corresponding foreign exchange losses and gains on the affiliate receivable balance. Refer to Note 11, Loans receivable from affiliates, for additional information. at December 31 2021 2020 (millions of Canadian $) Total Assets by segment Canadian Natural Gas Pipelines 25,213 22,852 U.S. Natural Gas Pipelines 45,502 43,217 Mexico Natural Gas Pipelines 7,547 7,215 Liquids Pipelines 14,951 16,744 Power and Storage 6,563 5,062 Corporate 4,442 5,210 104,218 100,300
Revenue from External Customers by Geographic Areas	year ended December 31 2021 2020 2019 (millions of Canadian $) Revenues Canada – domestic 4,603 4,392 4,059 Canada – export 1,226 1,059 1,035 United States 6,953 6,832 7,558 Mexico 605 716 603 13,387 12,999 13,255
Schedule of Long-Lived Assets by Country	at December 31 2021 2020 (millions of Canadian $) Plant, Property and Equipment Canada 24,890 24,092 United States 39,335 39,698 Mexico 5,957 5,985 70,182 69,775

REVENUES (Tables)

REVENUES (Tables)	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenues	Disaggregation of Revenues year ended December 31, 2021 Canadian U.S. Mexico Liquids Pipelines Power and Storage 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 28, Acquisitions and dispositions, for additional information. 2 Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 9, Leases, and Note 26, Risk management and financial instruments, for additional information on income from 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 12, year ended December 31, 2020 Canadian U.S. Mexico Liquids Pipelines Power and Storage 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 28, Acquisitions and dispositions, for additional information. 2 Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 9, Leases, and Note 26, Risk management and financial instruments, for additional information on income from 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 12, year ended December 31, 2019 Canadian U.S. Mexico Liquids Pipelines Power and Storage Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,010 4,245 601 2,423 — 11,279 Power generation — — — — 662 662 Natural gas storage and other — 650 2 4 73 729 4,010 4,895 603 2,427 735 12,670 Other revenues 1,2 — 83 — 452 50 585 4,010 4,978 603 2,879 785 13,255 1 Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 9, Leases, and Note 26, Risk management and financial instruments, for additional information on income from lease arrangements and financial instruments, respectively. 2 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 12,
Contract Balances	Contract Balances at December 31 2021 2020 Affected line item on the (millions of Canadian $) Receivables from contracts with customers 1,627 1,330 Accounts receivable Contract assets (Note 7) 202 132 Other current assets Long-term contract assets (Note 14) 249 192 Other long-term assets Contract liabilities 1 (Note 16) 90 129 Accounts payable and other Long-term contract liabilities (Note 17) 184 203 Other long-term liabilities 1 During the year ended December 31, 2021, $15 million (2020 – $18 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
	Dec. 31, 2021
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 1 n/a 342 282 175 2,775 2,134 1 In 2021, the Company paid $192 million towards contractual and legal obligations related to termination activities.
Schedule of Redeemable Non-controlling Interest	The changes in Redeemable non-controlling interest classified in mezzanine equity were as follows: year ended December 31 2021 2020 (millions of Canadian $) Balance at beginning of year 393 — Class A Interests issued — 1,033 Net income/(loss) attributable to redeemable non-controlling interest 1 1 (10) Class A Interests repurchased (394) — Class A Interests transferred to Current liabilities — (630) Balance at end of year — 393 1 Includes a return accrual and a foreign currency translation loss on Class A Interests, both of which were presented within Net income attributable to non-controlling interests in the Consolidated statement of income.

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2021
Other Assets [Abstract]
Schedule of Other Current Assets	at December 31 2021 2020 (millions of Canadian $) Keystone XL contractual recoveries (Note 6) 640 — Cash provided as collateral 273 142 Contract assets (Note 5) 202 132 Fair value of derivative contracts (Note 26) 169 235 Keystone XL assets held for sale 138 — Prepaid expenses 112 126 Regulatory assets (Note 12) 53 131 Other 130 114 1,717 880

PLANT, PROPERTY AND EQUIPMENT (

PLANT, PROPERTY AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Schedule of Plant, Property and Equipment	at December 31 2021 2020 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 14,892 5,751 9,141 14,190 5,278 8,912 Compression 6,191 2,065 4,126 5,421 1,906 3,515 Metering and other 1,458 705 753 1,393 648 745 22,541 8,521 14,020 21,004 7,832 13,172 Under construction 2,285 — 2,285 1,402 — 1,402 24,826 8,521 16,305 22,406 7,832 14,574 Canadian Mainline Pipeline 10,423 7,698 2,725 10,297 7,443 2,854 Compression 4,165 3,125 1,040 3,930 3,000 930 Metering and other 652 264 388 637 239 398 15,240 11,087 4,153 14,864 10,682 4,182 Under construction 139 — 139 150 — 150 15,379 11,087 4,292 15,014 10,682 4,332 Other Canadian Natural Gas Pipelines 1 Other 1,937 1,567 370 1,885 1,508 377 Under construction 58 — 58 42 — 42 1,995 1,567 428 1,927 1,508 419 42,200 21,175 21,025 39,347 20,022 19,325 U.S. Natural Gas Pipelines Columbia Gas Pipeline 11,205 799 10,406 10,198 557 9,641 Compression 4,522 381 4,141 4,287 276 4,011 Metering and other 3,657 257 3,400 3,388 185 3,203 19,384 1,437 17,947 17,873 1,018 16,855 Under construction 433 — 433 1,070 — 1,070 19,817 1,437 18,380 18,943 1,018 17,925 ANR Pipeline 1,820 557 1,263 1,685 512 1,173 Compression 2,559 565 1,994 2,146 489 1,657 Metering and other 1,391 422 969 1,289 388 901 5,770 1,544 4,226 5,120 1,389 3,731 Under construction 833 — 833 431 — 431 6,603 1,544 5,059 5,551 1,389 4,162 at December 31 2021 2020 Cost Accumulated Net Book Value Cost Accumulated Net Book Value (millions of Canadian $) Other U.S. Natural Gas Pipelines Columbia Gulf 2,749 178 2,571 2,638 151 2,487 GTN 2,701 1,071 1,630 2,330 1,008 1,322 Great Lakes 2,162 1,255 907 2,117 1,223 894 Other 2 1,755 657 1,098 1,568 578 990 9,367 3,161 6,206 8,653 2,960 5,693 Under construction 533 — 533 389 — 389 9,900 3,161 6,739 9,042 2,960 6,082 36,320 6,142 30,178 33,536 5,367 28,169 Mexico Natural Gas Pipelines Pipeline 2,957 476 2,481 2,952 411 2,541 Compression 480 80 400 480 69 411 Metering and other 626 155 471 624 133 491 4,063 711 3,352 4,056 613 3,443 Under construction 2,590 — 2,590 2,525 — 2,525 6,653 711 5,942 6,581 613 5,968 Liquids Pipelines Keystone Pipeline System Pipeline 9,209 1,758 7,451 9,254 1,579 7,675 Pumping equipment 1,020 252 768 1,025 228 797 Tanks and other 3,534 737 2,797 3,522 644 2,878 13,763 2,747 11,016 13,801 2,451 11,350 Under construction 3 72 — 72 2,870 — 2,870 13,835 2,747 11,088 16,671 2,451 14,220 Intra-Alberta Pipelines 199 14 185 198 9 189 14,034 2,761 11,273 16,869 2,460 14,409 Power and Storage Natural Gas 1,267 605 662 1,255 569 686 Natural Gas Storage and Other 797 216 581 780 194 586 2,064 821 1,243 2,035 763 1,272 Under construction 5 — 5 11 — 11 2,069 821 1,248 2,046 763 1,283 Corporate 836 320 516 993 372 621 102,112 31,930 70,182 99,372 29,597 69,775 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
	Dec. 31, 2021
Leases [Abstract]
Operating Lease Cost and Other Information	Operating lease cost was as follows: year ended December 31 (millions of Canadian $) 2021 2020 Operating lease cost 1 105 124 Sublease income (8) (13) Net operating lease cost 97 111 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 $) 2021 2020 Cash paid for amounts included in the measurement of operating lease liabilities 69 77 ROU assets obtained in exchange for new operating lease liabilities 32 14 at December 31 2021 2020 Weighted average remaining lease term 9 years 10 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 $) 2021 2020 Accounts payable and other 49 56 Other long-term liabilities (Note 17) 380 427 429 483
Maturities of Operating Lease Liabilities	Maturities of operating lease liabilities are as follows: (millions of Canadian $) 2021 2020 Less than one year 63 72 One to two years 60 61 Two to three years 58 59 Three to four years 55 58 Four to five years 54 54 More than five years 213 269 Total operating lease payments 503 573 Imputed interest (74) (90) Operating lease liabilities 429 483
Future Lease Payments to be Received Under Operating Leases	Future lease payments to be received under operating leases are as follows: (millions of Canadian $) 2021 2020 Less than one year 113 119 One to two years 111 111 Two to three years 110 109 Three to four years 94 109 Four to five years 70 94 More than five years — 70 498 612

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2021
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Investments	(millions of Canadian $) Ownership Interest at December 31, 2021 Income from Equity Equity year ended December 31 at December 31 2021 2020 2019 2021 2020 Canadian Natural Gas Pipelines TQM 1 50.0 % 12 12 12 118 90 Coastal GasLink 1,2 35.0 % — — — 386 211 U.S. Natural Gas Pipelines Northern Border 3 50.0 % 80 100 91 505 521 Millennium 47.5 % 91 96 92 474 482 Iroquois 4 50.0 % 55 52 54 392 197 Other Various 18 16 27 137 120 Mexico Natural Gas Pipelines Sur de Texas 5 60.0 % 160 213 3 835 680 Liquids Pipelines Grand Rapids 1,6 50.0 % 54 53 56 980 998 Northern Courier 1,7 nil 16 22 14 — 53 Port Neches Link LLC 1,8 95.0 % — — — 103 — HoustonLink Pipeline 1 50.0 % 1 — — 18 19 Power and Storage Bruce Power 1,9 48.4 % 411 439 527 4,493 3,306 Portlands Energy Centre 1,10 nil — 12 35 — — TransCanada Turbines 11 100.0 % — 4 9 — — 898 1,019 920 8,441 6,677 1 Classified as a non-consolidated VIE. Refer to Note 30, Variable interest entities, for additional information. 2 In May 2020, TC Energy completed the sale of a 65 per cent equity interest in Coastal GasLink Pipeline Limited Partnership and subsequently applied the equity method to account for its 35 per cent retained equity interest in the jointly-controlled entity. Refer to Note 28, Acquisitions and dispositions, for additional information. At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Coastal GasLink Pipeline Limited Partnership was $167 million (2020 – $188 million) due mainly to the fair value assessment of assets at the time of partial monetization along with deferred development fee revenue accounting. 3 At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border was US$115 million (2020 – US$116 million) due mainly to the fair value assessment of assets at the time of acquisition. 4 At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$39 million (2020 – US$39 million) due mainly to the fair value assessment of the assets at the times of acquisition. 5 Sur de Texas was placed into service in September 2019. TC Energy has a 60 per cent equity interest and, as a jointly-controlled entity, applies the equity method of accounting. Income from equity investments recorded in the Corporate segment reflects 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 Interest income and other in the Consolidated statement of income. At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Sur de Texas was US$77 million (2020 – US$79 million) due mainly to the accounting for fees earned from the successful construction of the pipeline. 6 At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $96 million (2020 – $98 million) due mainly to interest capitalized during construction. 7 On November 30, 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 28, Acquisitions and dispositions, for additional information. At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Courier was $56 million due mainly to the fair value of guarantees and the fair value assessment of assets at the time of partial monetization. 8 On March 8, 2021, TC Energy entered a joint venture with Motiva Enterprises to construct the Port Neches Link pipeline system. TC Energy has a 95 per cent equity interest and, as a jointly-controlled entity, applies the equity method of accounting. 9 At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $755 million (2020 – $796 million) due mainly to capitalized interest and the fair value assessment of assets at the time of acquisition. 10 In April 2020, TC Energy sold its investment in Portlands Energy Centre. Refer to Note 28, Acquisitions and dispositions, for additional information. 11 In November 2020, TC Energy purchased the remaining 50 per cent ownership in TransCanada Turbines which was subsequently consolidated. Refer to Note 28, Acquisitions and dispositions, for additional information. Summarized Financial Information of Equity Investments year ended December 31 2021 2020 2019 (millions of Canadian $) Income Revenues 5,447 5,838 5,693 Operating and other expenses (3,293) (3,341) (3,408) Net income 1,859 2,047 1,990 Net income attributable to TC Energy 898 1,019 920 at December 31 2021 2020 (millions of Canadian $) Balance Sheet Current assets 3,498 2,911 Non-current assets 30,165 26,957 Current liabilities (2,540) (3,727) Non-current liabilities (16,400) (15,309)

LOANS RECEIVABLE FROM AFFILIA_2

LOANS RECEIVABLE FROM AFFILIATES (Tables)	12 Months Ended
	Dec. 31, 2021
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 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 $) 2021 2020 2019 Interest income 1 87 110 147 Interest income and other Interest expense 2 (87) (110) (147) Income from equity investments Foreign exchange (losses)/gains 1 (41) (86) 53 Interest income and other Foreign exchange gains/(losses) 1 41 86 (53) Income from equity investments 1 Included in the Corporate segment. 2 Included in the Mexico Natural Gas Pipelines segment.

RATE-REGULATED BUSINESSES (Tabl

RATE-REGULATED BUSINESSES (Tables)	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	at December 31 2021 2020 Remaining Recovery/ Settlement Period (years) (millions of Canadian $) Regulatory Assets Deferred income taxes 1 1,509 1,287 n/a Pensions and other post-retirement benefits 1,2 203 401 n/a Foreign exchange on long-term debt 1,3 3 7 1-8 Operating and debt-service regulatory assets 4 1 54 1 Other 104 135 n/a 1,820 1,884 Less: Current portion included in Other current assets (Note 7) 53 131 1,767 1,753 Regulatory Liabilities Pipeline abandonment trust balances 5 2,086 1,842 n/a Deferred income taxes – U.S. Tax Reform 6 1,141 1,170 n/a Canadian Mainline bridging amortization account 7 483 537 9 Cost of removal 8 254 246 n/a Canadian Mainline long-term adjustment account 7,9 186 223 5 Deferred income taxes 1 139 115 n/a Canadian Mainline short-term adjustment and toll-stabilization accounts 7,9,10 60 4 n/a ANR post-employment and retirement benefits other than pension 11 40 40 n/a Operating and debt-service regulatory liabilities 4 32 48 1 Pensions and other post-retirement benefits 2 13 18 n/a Other 66 58 n/a 4,500 4,301 Less: Current portion included in Accounts payable and other (Note 16) 200 153 4,300 4,148 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 regulatory liabilities will be 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, $223 million is amortized over the six-year settlement term and the residual of $4 million was transferred to the STAA at December 31, 2020. 10 Under the terms of the 2021-2026 Mainline Settlement, the STAA account will commence amortization over the remainder of the six-year settlement term when predetermined thresholds per the settlement agreement are met.

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	The Company has recorded the following Goodwill on its acquisitions: (millions of Canadian $) U.S. Natural Balance at January 1, 2020 12,887 Foreign exchange rate changes (208) Balance at December 31, 2020 12,679 Foreign exchange rate changes (97) Balance at December 31, 2021 12,582

OTHER LONG-TERM ASSETS (Tables)

OTHER LONG-TERM ASSETS (Tables)	12 Months Ended
	Dec. 31, 2021
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Schedule of Other Long-Term Assets	at December 31 2021 2020 (millions of Canadian $) Deferred income tax assets (Note 18) 509 177 Employee post-retirement benefits (Note 25) 312 207 Long-term contract assets (Note 5) 249 192 Keystone XL contractual recoveries (Note 6) 50 — Fair value of derivative contracts (Note 26) 48 41 Capital projects in development 1 14 231 Other 221 131 1,403 979

NOTES PAYABLE (Tables)

NOTES PAYABLE (Tables)	12 Months Ended
	Dec. 31, 2021
Short-term Debt [Abstract]
Schedule of Notes Payable	2021 2020 (millions of Canadian $, unless otherwise noted) Outstanding at December 31 Weighted Outstanding at December 31 Weighted Canada 1 4,953 0.4 % 2,836 0.4 % U.S. (2021 – US$54; 2020 – US$900) 68 0.3 % 1,149 0.4 % Mexico (2021 – US$115; 2020 – US$150) 2 145 1.7 % 191 1.7 % 5,166 4,176 1 At December 31, 2021, Notes payable consisted of Canadian dollar-denominated notes of $1,989 million (2020 – $656 million) and U.S. dollar-denominated notes of US$2,341 million (2020 – US$1,709 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) 2021 2020 Borrower 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 2026 3.0 1.0 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 2022 US 4.5 US 2.1 US 4.5 TCPL / TCPL USA / Columbia / TransCanada American Investments Ltd. For general corporate purposes of the borrowers, guaranteed by TCPL December 2024 US 1.0 US 1.0 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 2.6 MXN 5.0 3 1 Net of commercial paper outstanding and facility draws. 2 Provisions of various 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 credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2021, the Company was in compliance with all debt covenants. 3 Or the U.S. dollar equivalent.

ACCOUNTS PAYABLE AND OTHER (Tab

ACCOUNTS PAYABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2021
Payables and Accruals [Abstract]
Schedule of Accounts Payable and Other	at December 31 2021 2020 (millions of Canadian $) Trade payables 4,183 3,057 Fair value of derivative contracts (Note 26) 221 72 Regulatory liabilities (Note 12) 200 153 Contract liabilities (Note 5) 90 129 Class C Interests (Note 6) 75 — Other 330 405 5,099 3,816

OTHER LONG-TERM LIABILITIES (Ta

OTHER LONG-TERM LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2021
Deferred Costs, Noncurrent [Abstract]
Schedule of Other Long-Term Liabilities	at December 31 2021 2020 (millions of Canadian $) Operating lease obligations (Note 9) 380 427 Long-term contract liabilities (Note 5) 184 203 Employee post-retirement benefits (Note 25) 174 503 Asset retirement obligations 61 54 Fair value of derivative contracts (Note 26) 47 59 Other 213 229 1,059 1,475

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	year ended December 31 2021 2020 2019 (millions of Canadian $) Current Canada 29 (54) 84 Foreign 1 276 306 615 305 252 699 Deferred Canada (327) (224) (29) Foreign 142 166 84 (185) (58) 55 Income Tax Expense 120 194 754 1 The 2019 current foreign income tax expense mainly relates to the sale of certain Columbia Midstream assets in August 2019. Refer to Note 28, Acquisitions and dispositions, for additional information .
Schedule of Geographic Components of Income	year ended December 31 2021 2020 2019 (millions of Canadian $) Canada (292) 691 1,144 Foreign 2,458 4,416 4,043 Income before Income Taxes 2,166 5,107 5,187
Reconciliation of Income Tax Expense	year ended December 31 2021 2020 2019 (millions of Canadian $) Income before income taxes 2,166 5,107 5,187 Federal and provincial statutory tax rate 23.0 % 24.0 % 26.5 % Expected income tax expense 498 1,226 1,375 Valuation allowance releases (8) (400) (259) Foreign income tax rate differentials (230) (258) (180) Income tax differential related to regulated operations (139) (228) (159) Income from non-controlling interests and equity investments (70) (141) (78) Alberta tax rate reduction — — (32) Non-taxable portion of capital gains — (62) (28) Non-deductible goodwill on the Columbia Midstream asset disposition — — 154 Impact of Mexico inflationary adjustments 32 7 13 Other 37 50 (52) Income Tax Expense 120 194 754
Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet	at December 31 2021 2020 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,163 1,389 Regulatory and other deferred amounts 537 532 Unrealized foreign exchange losses on long-term debt 130 154 Financial instruments — 48 Other 46 70 1,876 2,193 Less: Valuation allowance 229 243 1,647 1,950 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment 5,616 6,124 Equity investments 1,219 1,087 Taxes on future revenue requirement 333 287 Other 112 81 7,280 7,579 Net Deferred Income Tax Liabilities 5,633 5,629 The above deferred tax amounts have been classified on the Consolidated balance sheet as follows: at December 31 2021 2020 (millions of Canadian $) Deferred Income Tax Assets Other long-term assets (Note 14) 509 177 Deferred Income Tax Liabilities Deferred income tax liabilities 6,142 5,806 Net Deferred Income Tax Liabilities 5,633 5,629
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 2021 2020 2019 (millions of Canadian $) Unrecognized tax benefit at beginning of year 52 29 19 Gross increases – tax positions in prior years 5 26 13 Gross decreases – tax positions in prior years (1) (2) (1) Gross increases – tax positions in current year 26 1 — Lapse of statutes of limitations (2) (2) (2) Unrecognized Tax Benefit at End of Year 80 52 29

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	2021 2020 Outstanding amounts 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 Debentures U.S. (2021 – nil; 2020 – US$400) — — 510 9.9 % Medium Term Notes Canadian 2022 to 2049 12,491 4.2 % 11,491 4.5 % Senior Unsecured Notes U.S. (2021 – US$16,542; 2020 – US$14,292) 2022 to 2049 20,936 4.8 % 18,227 5.3 % 33,427 30,228 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2021 and 2020 – US$200) 2023 254 7.9 % 255 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2021 and 2020 – US$33) 2026 41 7.5 % 42 7.5 % 899 901 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2021 and 2020 – US$1,500) 2 2025 to 2045 1,898 4.9 % 1,913 4.9 % TC PIPELINES, LP Unsecured Term Loan U.S. (2021 – nil; 2020 – US$450) — — 574 1.4 % Senior Unsecured Notes U.S. (2021 – US$850; 2020 – US$1,200) 2025 to 2027 1,076 4.2 % 1,530 4.4 % 1,076 2,104 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2021 – US$372; 2020 – US$672) 2024 to 2026 472 5.3 % 858 7.2 % GAS TRANSMISSION NORTHWEST LLC Senior Unsecured Notes U.S. (2021 and 2020 – US$325) 2030 to 2035 411 4.3 % 415 4.3 % 2021 2020 Outstanding amounts 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 Unsecured Loan Facility U.S. (2021 – nil; 2020 – US$25) 2023 — — 32 1.3 % Senior Unsecured Notes U.S. (2021 – US$250; 2020 – US$125) 2030 to 2031 316 2.8 % 159 2.8 % 316 191 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2021 – US$167; 2020 – US$198) 2028 to 2030 211 7.6 % 253 7.6 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2021 – US$36; 2020 – US$23) 2024 46 1.3 % 29 2.2 % NORTH BAJA PIPELINE, LLC Unsecured Term Loan U.S. (2021 – nil; 2020 – US$50) — — 64 1.2 % 38,756 36,956 Current portion of long-term debt (1,320) (1,972) Unamortized debt discount and issue costs (243) (238) Fair value adjustments 3 148 167 37,341 34,913 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 Related to the acquisition of Columbia. The Company issued long-term debt over the three years ended December 31, 2021 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED 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 % September 2019 Medium Term Notes September 2029 700 3.00 % September 2019 Medium Term Notes July 2048 300 4.18 % 2 April 2019 Medium Term Notes October 2049 1,000 4.34 % 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 3 Various Project-Level Credit Facility June 2021 US 849 Floating COLUMBIA PIPELINE GROUP, INC. 4 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 5 April 2020 Senior Secured Credit Facilities April 2027 1,603 Floating NORTHERN COURIER PIPELINE LIMITED PARTNERSHIP 6 July 2019 Senior Secured Notes June 2042 1,000 3.365 % 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 Reflects coupon rate on re-opening of a pre-existing MTN issue. The MTNs were issued at a premium to par, resulting in a re-issuance yield of 3.991 per cent. 3 On January 4, 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. 4 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. 5 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 28, Acquisitions and dispositions, for additional information.
Schedule of Repayments of Long-Term Debt	At December 31, 2021, principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2022 2023 2024 2025 2026 Principal repayments on long-term debt 1,320 1,823 2,657 2,698 1,778
Schedule of Retired Long-Term Debt	The Company retired/repaid long-term debt over the three years ended December 31, 2021 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED 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 % November 2019 Senior Unsecured Notes US 700 2.125 % November 2019 Senior Unsecured Notes US 550 Floating May 2019 Medium Term Notes 13 9.35 % March 2019 Debentures 100 10.50 % January 2019 Senior Unsecured Notes US 750 7.125 % January 2019 Senior Unsecured Notes US 400 3.125 % 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 % June 2019 Unsecured Term Loan US 50 Floating 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 % May 2019 Unsecured Term Loan US 35 Floating 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	year ended December 31 2021 2020 2019 (millions of Canadian $) Interest on long-term debt 1,841 1,963 1,931 Interest on junior subordinated notes 453 470 427 Interest on short-term debt 10 46 106 Capitalized interest (22) (294) (186) Amortization and other financial charges 1 78 43 55 2,360 2,228 2,333 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
	Dec. 31, 2021
Junior Subordinated Notes [Abstract]
Schedule of Junior Subordinated Notes	2021 2020 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 1,265 4.0 % 1,275 4.1 % US$750 notes issued 2015 at 5.875% 3,4 2075 949 5.0 % 957 5.0 % US$1,200 notes issued 2016 at 6.125% 3,4 2076 1,519 5.8 % 1,530 5.8 % US$1,500 notes issued 2017 at 5.55% 3,4 2077 1,899 4.7 % 1,913 4.7 % $1,500 notes issued 2017 at 4.90% 3,4 2077 1,500 4.5 % 1,500 4.5 % US$1,100 notes issued 2019 at 5.75% 3,4 2079 1,392 5.4 % 1,403 5.4 % $500 notes issued 2021 at 4.45% 3,4 2081 500 4.0 % — — 9,024 8,578 Unamortized debt discount and issue costs (85) (80) 8,939 8,498 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, a financing trust subsidiary wholly owned by TCPL. While the obligations of TransCanada 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 .

NON-CONTROLLING INTERESTS (Tabl

NON-CONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 2020 2019 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 60 284 270 Non-controlling interest in PNGTS 30 23 23 Redeemable non-controlling interest (Note 6) 1 (10) — 91 297 293

COMMON SHARES (Tables)

COMMON SHARES (Tables)	12 Months Ended
	Dec. 31, 2021
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Schedule of Common Shares	Number of Shares Amount (thousands) (millions of Canadian $) Outstanding at January 1, 2019 918,097 23,174 Dividend reinvestment and share purchase plan 15,165 931 Exercise of options 5,138 282 Outstanding at December 31, 2019 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 21) 37,955 2,063 Exercise of options 2,797 165 Outstanding at December 31, 2021 980,816 26,716
Schedule of Weighted Average Shares	Weighted Average Common Shares Outstanding (millions) 2021 2020 2019 Basic 973 940 929 Diluted 974 940 931
Schedule of Stock Options Activity	Number of Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (thousands) (years) Options outstanding at January 1, 2021 8,996 $59.55 Options granted 1,679 $56.86 Options exercised (2,797) $53.10 Options forfeited/expired (109) $59.96 Options Outstanding at December 31, 2021 7,769 $61.29 4.2 Options Exercisable at December 31, 2021 4,410 $60.13 3.2
Schedule of Options Valuation Assumptions	The Company used a binomial model for determining the fair value of options granted applying the following weighted average assumptions: year ended December 31 2021 2020 2019 Weighted average fair value $7.39 $7.73 $6.37 Expected life (years) 1 5.4 5.7 5.7 Interest rate 0.5 % 1.5 % 1.9 % Volatility 2 25 % 17 % 19 % Dividend yield 6.0 % 4.2 % 5.0 % 1 Expected life is based on historical exercise activity. 2 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.
Schedule of Additional Option Information	The following table summarizes additional stock option information: year ended December 31 2021 2020 2019 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 28 31 75 Total fair value of options that have vested 110 101 143 Total options vested 1.9 million 2.0 million 2.1 million

PREFERRED SHARES (Tables)

PREFERRED SHARES (Tables)	12 Months Ended
	Dec. 31, 2021
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Schedule of Preferred Shares	at 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 2021 2020 2019 (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 4 246 246 209 Series 4 4,003 Floating 4 Floating $25.00 June 30, 2025 Series 3 97 97 134 Series 5 12,071 1.949 % 5 $0.48725 $25.00 January 30, 2026 Series 6 294 310 310 Series 6 1,929 Floating 4 Floating $25.00 January 30, 2026 Series 5 48 32 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 — — — — — — — 493 493 Series 15 40,000 4.90 % $1.225 $25.00 May 31, 2022 Series 16 988 988 988 3,487 3,980 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), 2.96 per cent (Series 12), or 3.85 per cent (Series 16). 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), 2.96 per cent (Series 11), or 3.85 per cent, subject to a minimum of 4.90 per cent (Series 15). 3 Net of underwriting commissions and deferred income taxes. 4 The floating quarterly dividend rate for the Series 2 preferred shares is 2.049 per cent for the period starting December 31, 2021 to, but excluding, March 31, 2022. The floating quarterly dividend rate for the Series 4 preferred shares is 1.409 per cent for the period starting December 31, 2021 to, but excluding, March 31, 2022. The floating quarterly dividend rate for the Series 6 preferred shares is 1.686 per cent for the period starting October 30, 2021 to, but excluding, January 30, 2022. 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 LOSS (Tables)	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Components of Other Comprehensive (Loss)/Income	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, 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) year ended December 31, 2019 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 (914) (30) (944) Reclassification of foreign currency translation gains on disposal of foreign operations (13) — (13) Change in fair value of net investment hedges 46 (11) 35 Change in fair value of cash flow hedges (78) 16 (62) Reclassification to net income of gains and losses on cash flow hedges 19 (5) 14 Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (15) 5 (10) Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans 14 (4) 10 Other comprehensive loss on equity investments (114) 32 (82) Other Comprehensive Loss (1,055) 3 (1,052)
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, 2019 107 (23) (314) (376) (606) Other comprehensive loss before reclassifications 2 (824) (49) (10) (86) (969) Amounts reclassified from AOCI (13) 14 10 5 16 Net current period other comprehensive loss (837) (35) — (81) (953) AOCI balance at December 31, 2019 (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 3 — 55 14 28 97 Net current period other comprehensive (loss)/income (98) 44 172 534 652 Acquisition of TC PipeLines, LP 4 362 (13) — 4 353 AOCI balance at December 31, 2021 (1,009) (112) (113) (200) (1,434) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 Other comprehensive (loss)/income before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling interest losses of $12 million (2020 – losses of $30 million; 2019 – losses of $85 million), gains of $1 million (2020 – losses of $16 million; 2019 – losses of $13 million), and gains of $1 million (2020 – gains of $1 million; 2019 – losses of $1 million ), respectively. 3 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $62 million ($47 million, net of tax) at December 31, 2021. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement. 4 Represents the AOCI attributable to 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 21, Non-controlling interests, for additional information.
Schedule of Reclassifications out of Accumulated Other Comprehensive Income	Details about reclassifications out of AOCI into the Consolidated statement of income were as follows: year ended December 31 Amounts Reclassified From AOCI Affected Line Item in the Consolidated Statement of Income 1 2021 2020 2019 (millions of Canadian $) Cash flow hedges Commodities (22) (1) (7) Revenues (Power and Storage) Interest rate (46) (28) (12) Interest expense Interest rate — (613) — Net gain/(loss) on assets sold/held for sale 2 (68) (642) (19) Total before tax 13 160 5 Income tax expense 2 (55) (482) (14) Net of tax 3 Pension and other post-retirement benefit plan adjustments Amortization of actuarial losses (22) (23) (14) Plant operating costs and other 4 Settlement gain 2 — — Plant operating costs and other 4 (20) (23) (14) Total before tax 6 6 4 Income tax expense (14) (17) (10) Net of tax Equity investments Equity income (37) (15) (8) Income from equity investments 9 4 3 Income tax expense (28) (11) (5) Net of tax 3 Currency translation adjustments Foreign currency translation gains on disposal of foreign operations — — 13 Net gain/(loss) on assets sold/held for sale — — — Income tax expense — — 13 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 28, Acquisitions and dispositions, for additional information. 3 Amounts reclassified from AOCI on cash flow hedges are net of non-controlling interest of nil (2020 – losses of $7 million; 2019 – nil). 4 These AOCI components are included in the computation of net benefit cost. Refer to Note 25, Employee post-retirement benefits, for additional information.

EMPLOYEE POST-RETIREMENT BENE_2

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 2020 2019 (millions of Canadian $) DB Plans 105 124 122 Other post-retirement benefit plans 8 9 22 Savings and DC Plans 58 58 61 171 191 205
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 $) 2021 2020 2021 2020 Change in Benefit Obligation 1 Benefit obligation – beginning of year 4,326 4,058 457 427 Service cost 171 155 6 6 Interest cost 119 133 12 14 Employee contributions 6 6 1 — Benefits paid (372) (249) (21) (21) Actuarial (gain)/loss (208) 242 (35) 36 Curtailment (5) — 3 — Foreign exchange rate changes (10) (19) (4) (5) Benefit obligation – end of year 4,027 4,326 419 457 Change in Plan Assets Plan assets at fair value – beginning of year 4,038 3,693 441 406 Actual return on plan assets 376 485 5 56 Employer contributions 2 105 124 8 9 Employee contributions 6 6 1 — Benefits paid (372) (249) (21) (21) Foreign exchange rate changes (8) (21) (3) (9) Plan assets at fair value – end of year 4,145 4,038 431 441 Funded Status – Plan Surplus/(Deficit) 118 (288) 12 (16) 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 $20 million letter of credit provided to the Canadian DB Plan for funding purposes (2020 – $13 million).
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 $) 2021 2020 2021 2020 Other long-term assets (Note 14) 119 29 193 178 Accounts payable and other — — (8) (8) Other long-term liabilities (Note 17) (1) (317) (173) (186) 118 (288) 12 (16)
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 $) 2021 2020 2021 2020 Projected benefit obligation 1 (2,687) (3,292) (183) (194) Plan assets at fair value 2,686 2,975 — — Funded Status – Plan Deficit (1) (317) (183) (194) 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 2021 2020 (millions of Canadian $) Accumulated benefit obligation (3,714) (3,957) Plan assets at fair value 4,145 4,038 Funded Status – Plan Surplus 431 81
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 2021 2020 2021 Debt securities 34 % 33 % 25% to 45% Equity securities 53 % 57 % 35% to 65% Alternatives 13 % 10 % 10% to 20% 100 % 100 %
Schedule of Allocation of Plan Assets, Employer and Related Party Securities	Debt and equity securities include the Company's debt and common shares as follows: at December 31 Percentage of (millions of Canadian $) 2021 2020 2021 2020 Debt securities 7 13 0.2 % 0.3 % Equity securities 5 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 26, Risk management and financial instruments. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 Asset Category Cash and Cash Equivalents 68 87 2 — — — 70 87 2 2 Equity Securities: Canadian 269 276 148 177 — — 417 453 9 10 U.S. 649 594 164 211 — — 813 805 18 18 International 126 114 354 380 — — 480 494 10 11 Global 111 116 313 368 — — 424 484 9 11 Emerging 25 35 120 125 — — 145 160 3 4 Fixed Income Securities: Canadian Bonds: Federal — — 226 207 — — 226 207 5 5 Provincial — — 331 283 — — 331 283 7 6 Municipal — — 16 13 — — 16 13 — — Corporate — — 147 151 — — 147 151 4 3 U.S. Bonds: Federal 433 444 15 14 — — 448 458 10 10 Municipal — — 1 2 — — 1 2 — — Corporate 67 72 143 143 — — 210 215 5 5 International: Government 6 8 7 6 — — 13 14 — — Corporate — — 73 48 — — 73 48 2 1 Mortgage backed 42 47 5 4 — — 47 51 1 1 Other Investments: Real estate — — — — 283 213 283 213 6 5 Infrastructure — — — — 281 203 281 203 6 5 Private equity funds — — — — 1 1 1 1 — — Derivatives — — — (8) — — — (8) — — Funds held on deposit 150 145 — — — — 150 145 3 3 1,946 1,938 2,065 2,124 565 417 4,576 4,479 100 100
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, 2019 379 Purchases and sales 42 Realized and unrealized losses (4) Balance at December 31, 2020 417 Purchases and sales 100 Realized and unrealized gains 48 Balance at December 31, 2021 565
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 2022 208 25 2023 211 25 2024 216 24 2025 220 24 2026 224 24 2027 to 2031 1,171 114
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 2021 2020 2021 2020 Discount rate 3.05 % 2.70 % 3.10 % 2.75 % Rate of compensation increase 2.95 % 2.60 % — —
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 2021 2020 2019 2021 2020 2019 Discount rate 2.70 % 3.20 % 3.90 % 2.80 % 3.35 % 4.10 % Expected long-term rate of return on plan assets 6.15 % 6.40 % 6.60 % 3.00 % 3.50 % 4.30 % Rate of compensation increase 2.60 % 3.00 % 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 $) 2021 2020 2019 2021 2020 2019 Service cost 1 171 155 126 6 6 5 Other components of net benefit cost 1 Interest cost 119 133 142 12 14 17 Expected return on plan assets (234) (230) (222) (13) (14) (15) Amortization of actuarial loss 23 21 12 2 2 2 Amortization of regulatory asset 27 25 14 2 2 2 Curtailment gain (5) — — — — — Settlement gain – AOCI (2) — — — — — (72) (51) (54) 3 4 6 Net Benefit Cost Recognized 99 104 72 9 10 11 1 Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income.
Schedule of the Pre-Tax Amounts Recognized in AOCI	Pre-tax amounts recognized in AOCI were as follows: at December 31 2021 2020 2019 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Net loss 147 5 358 22 398 20
Schedule of the Pre-Tax Amounts Recognized in OCI	Pre-tax amounts recognized in OCI were as follows: at December 31 2021 2020 2019 Pension Other Post- Pension Other Post- Pension Other Post- (millions of Canadian $) Amortization of net loss from AOCI to net income (23) (2) (21) (2) (12) (2) Curtailment — 3 — — — — Settlement 2 — — — — — Funded status adjustment (190) (18) (18) 3 52 (37) (211) (17) (39) 1 40 (39)

RISK MANAGEMENT AND FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 2020 Fair 1,2 Notional Amount Fair 1,2 Notional Amount (millions of Canadian $, unless otherwise noted) U.S. dollar foreign exchange options (maturing 2022 to 2023) (4) US 3,800 45 US 2,200 U.S. dollar cross-currency interest rate swaps (maturing 2022 to 2025) 3 23 US 400 23 US 400 19 US 4,200 68 US 2,600 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2021, Net income includes net realized gains of $1 million (2020 – 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 2021 2020 (millions of Canadian $, unless otherwise noted) Notional amount 30,700 (US 24,200) 27,700 (US 21,800) Fair value 35,500 (US 28,100) 33,800 (US 26,500) 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, 2021 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 553 104 34 — — Sales 1 1,043 52 38 — — 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. at December 31, 2020 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 185 13 26 — — Sales 1 1,786 14 30 — — Millions of U.S. dollars — — — 4,432 1,100 Millions of Mexican pesos — — — 1,700 — Maturity dates 2021-2025 2021-2027 2021 2021-2022 2022-2026 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.
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 2021 2020 Carrying Amount Fair Value Carrying Fair (millions of Canadian $) Long-term debt, including current portion (Note 19) (38,661) (45,615) (36,885) (46,054) Junior subordinated notes (Note 20) (8,939) (9,236) (8,498) (8,908) (47,600) (54,851) (45,383) (54,962) 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 2021 2020 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 — 26 — 17 Maturing within 1-5 years 8 107 — 66 Maturing within 5-10 years 1,150 — 985 — Maturing after 10 years 84 — 85 — Fair value of equity securities 2,4 817 — 736 — 2,059 133 1,806 83 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, 2021 Cash Flow Hedges Net Held for Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 — — 122 122 Foreign exchange — 10 37 47 — 10 159 169 Other long-term assets (Note 14) Commodities 2 — — 8 8 Foreign exchange — 32 6 38 Interest rate 3 2 — — 2 2 32 14 48 Total Derivative Assets 2 42 173 217 Accounts payable and other (Note 16) Commodities 2 (23) — (138) (161) Foreign exchange — (4) (46) (50) Interest rate 3 (10) — — (10) (33) (4) (184) (221) Other long-term liabilities (Note 17) Commodities 2 (4) — (6) (10) Foreign exchange — (19) (10) (29) Interest rate 3 (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. 3 For the year ended December 31, 2021, a $10 million payment to settle a loss on financial instruments was included in Net cash (used in)/provided by financing activities in the Consolidated statement of cash flows. The balance sheet classification of the fair value of derivative instruments was as follows: at December 31, 2020 Cash Flow Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 — — 13 13 Foreign exchange — 47 175 222 — 47 188 235 Other long-term assets (Note 14) Foreign exchange — 22 19 41 — 22 19 41 Total Derivative Assets — 69 207 276 Accounts payable and other (Note 16) Commodities 2 (8) — (32) (40) Foreign exchange — (1) (10) (11) Interest rate 3 (21) — — (21) (29) (1) (42) (72) Other long-term liabilities (Note 17) Commodities 2 (6) — (4) (10) Interest rate 3 (49) — — (49) (55) — (4) (59) Total Derivative Liabilities (84) (1) (46) (131) Total Derivatives (84) 68 161 145 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. 3 For the year ended December 31, 2020, a $130 million payment to settle a loss on financial instruments was included in Net cash (used in)/provided by financing activities in the Consolidated statement of cash flows.
Unrealized Gain (Loss) on Investments	year ended December 31 2021 2020 2019 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized gains/(losses) 45 (2) 130 1 32 3 Net realized gains 3 3 — 20 1 60 — 1 Gains 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 as regulatory assets. 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 2021 2020 2019 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized gains/(losses) 45 (2) 130 1 32 3 Net realized gains 3 3 — 20 1 60 — 1 Gains 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 as regulatory assets. 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 summary does not include hedges of the net investment in foreign operations: year ended December 31 2021 2020 2019 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized gains/(losses) in the year Commodities 9 (23) (111) Foreign exchange (203) 126 245 Amount of realized gains/(losses) in the year Commodities 287 183 378 Foreign exchange 240 (33) (70) Derivative instruments in hedging relationships 2 Amount of realized (losses)/gains in the year Commodities (44) 6 (6) Interest rate (32) (16) 2 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 Interest income and other. 2 In 2021, 2020 and 2019, 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. 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 2021 2020 2019 (millions of Canadian $) Fair Value Hedges Interest rate contracts 1 Hedged items — (3) (19) Derivatives designated as hedging instruments — 1 1 Cash Flow Hedges Reclassification of losses on derivative instruments from AOCI to net income 2,3 Interest rate contracts 1 (46) (648) (12) Commodity contracts 4 (22) (1) (7) 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 assets sold/held for sale. Refer to Note 28, Acquisitions and dispositions, for additional information. 2 Refer to Note 24, Other comprehensive income/(loss) and accumulated other comprehensive 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 Storage) in the Consolidated statement of income.
Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships	The components of OCI (Note 24) 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 2021 2020 2019 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI 1 Commodities (35) (5) (15) Interest rate 22 (766) (63) (13) (771) (78) 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, 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. at December 31, 2020 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative instrument assets Commodities 13 (7) 6 Foreign exchange 263 (11) 252 276 (18) 258 Derivative instrument liabilities Commodities (50) 7 (43) Foreign exchange (11) 11 — Interest rate (70) — (70) (131) 18 (113) 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, 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. at December 31, 2020 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative instrument assets Commodities 13 (7) 6 Foreign exchange 263 (11) 252 276 (18) 258 Derivative instrument liabilities Commodities (50) 7 (43) Foreign exchange (11) 11 — Interest rate (70) — (70) (131) 18 (113) 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, 2021 Quoted Prices in Active Markets 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. at December 31, 2020 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 3 10 — 13 Foreign exchange — 263 — 263 Derivative instrument liabilities Commodities (15) (31) (4) (50) Foreign exchange — (11) — (11) Interest rate — (70) — (70) (12) 161 (4) 145 1 There were no transfers from Level II to Level III for the year ended December 31, 2020.
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) 2021 2020 Balance at beginning of year (4) (7) Total (losses)/gains included in Net income (3) 3 Settlements 1 — Balance at end of year 1 (6) (4) 1 Revenues include unrealized losses of $3 million attributed to derivatives in the Level III category that were still held at December 31, 2021 (2020 – unrealized gains of $3 million) .

CHANGES IN OPERATING WORKING _2

CHANGES IN OPERATING WORKING CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2021
CHANGES IN OPERATING WORKING CAPITAL
Schedule of changes in operating working capital	year ended December 31 2021 2020 2019 (millions of Canadian $) (Increase)/decrease in Accounts receivable (925) 129 31 Increase in Inventories (93) (55) (42) Increase in Other current assets (141) (221) (15) Increase/(decrease) in Accounts payable and other 890 (162) 352 Decrease in Accrued interest (18) (18) (33) (Increase)/Decrease in Operating Working Capital (287) (327) 293

COMMITMENTS, CONTINGENCIES AN_2

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 2020 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Sur de Texas to 2043 93 — 100 — Bruce Power to 2023 88 — 88 — Other jointly-owned entities to 2043 80 4 78 4 Northern Courier pipeline 2 — — 300 26 261 4 566 30 1 TC Energy's share of the potential estimated current or contingent exposure.

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2021
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 $) 2021 2020 ASSETS Current Assets Cash and cash equivalents 72 254 Accounts receivable 70 61 Inventories 28 26 Other current assets 13 11 183 352 Plant, Property and Equipment 3,672 3,325 Equity Investments 890 714 Goodwill 421 424 Other Long-Term Assets — 8 5,166 4,823 LIABILITIES Current Liabilities Accounts payable and other 232 109 Redeemable non-controlling interest — 633 Accrued interest 17 21 Current portion of long-term debt 29 579 278 1,342 Regulatory Liabilities 66 60 Other Long-Term Liabilities 1 11 Deferred Income Tax Liabilities 13 12 Long-Term Debt 2,025 2,468 2,383 3,893 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 $) 2021 2020 Balance sheet Loan receivable from affiliate (Note 11) 1 — Equity investments Bruce Power 4,493 3,306 Pipeline equity investments and other 1 1,605 1,371 Long-term loan receivable from affiliate (Note 11) 238 — Off-balance sheet 2 Coastal GasLink 3 3,037 1,107 Bruce Power 974 1,183 Pipeline equity investments 1 171 399 Maximum exposure to loss 10,519 7,366 1 On November 30, 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 28, Acquisitions and dispositions, for additional information. 2 Includes maximum potential exposure to guarantees and future funding commitments.

DESCRIPTION OF TC ENERGY'S BU_2

DESCRIPTION OF TC ENERGY'S BUSINESS (Details)	12 Months Ended
	Dec. 31, 2021segmentplantmikmBcf
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	40,580
Investments of regulated natural gas pipelines (in miles) | mi	25,216
U.S. Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) | km	50,211
Investments of regulated natural gas pipelines (in miles) | mi	31,199
Investments of regulated natural gas storage facilities (in billion cubic feet) | Bcf	535
Mexico Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) | km	2,503
Investments of regulated natural gas pipelines (in miles) | mi	1,554
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 Storage
Segment Reporting Information [Line Items]
Number of electrical power generation plants (in plants) | plant	7
Non-regulated natural gas storage facilities (in billion cubic feet) | Bcf	118

ACCOUNTING POLICIES (Details)

ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2021
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	10.00%
Corporate | Minimum
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	4.00%
Corporate | Maximum
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	20.00%
Natural Gas Pipelines | Pipeline | Minimum
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	0.60%
Natural Gas Pipelines | Pipeline | Maximum
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	7.00%
Midstream | Pipeline | Minimum
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	1.70%
Midstream | Pipeline | Maximum
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	2.50%
Liquids Pipelines | Pipeline | Minimum
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	2.00%
Liquids Pipelines | Pipeline | Maximum
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	2.50%
Power and Storage | Power generation and natural gas storage plant, equipment and structures | Minimum
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	2.00%
Power and Storage | Power generation and natural gas storage plant, equipment and structures | Maximum
Property, Plant and Equipment [Line Items]
Annual depreciation rate on straight-line basis	20.00%

SEGMENTED INFORMATION (Details)

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segmented information
Revenues	$ 13,387	$ 12,999	$ 13,255
Income from equity investments	898	1,019	920
Plant operating costs and other	(4,098)	(3,878)	(3,913)
Commodity purchases resold	(87)	0	(365)
Property taxes	(774)	(727)	(727)
Depreciation and amortization	(2,522)	(2,590)	(2,464)
Asset impairment charge and other (Note 6)	2,775	0	0
Net gain/(loss) on assets sold/held for sale	30	(50)	(121)
Segmented Earnings/(Losses)	4,059	6,773	6,585
Interest expense	(2,360)	(2,228)	(2,333)
Allowance for funds used during construction	267	349	475
Interest income and other	200	213	460
Income before Income Taxes	2,166	5,107	5,187
Income tax expense	(120)	(194)	(754)
Net Income	2,046	4,913	4,433
Net income attributable to non-controlling interests	(91)	(297)	(293)
Net Income Attributable to Controlling Interests	1,955	4,616	4,140
Preferred share dividends	(140)	(159)	(164)
Net Income Attributable to Common Shares	1,815	4,457	3,976
Capital Spending
Capital expenditures	5,924	8,013	7,475
Capital projects in development	0	122	707
Contributions to equity investments	1,210	765	602
Capital Spending	7,134	8,900	8,784
Assets	104,218	100,300
Geographic Information
Plant, Property and Equipment	70,182	69,775
Canada
Geographic Information
Plant, Property and Equipment	24,890	24,092
Canada – domestic
Segmented information
Revenues	4,603	4,392	4,059
Canada – export
Segmented information
Revenues	1,226	1,059	1,035
United States
Segmented information
Revenues	6,953	6,832	7,558
Geographic Information
Plant, Property and Equipment	39,335	39,698
Mexico
Segmented information
Revenues	605	716	603
Geographic Information
Plant, Property and Equipment	5,957	5,985
Intersegment eliminations
Segmented information
Revenues	(159)	(185)	(183)
Corporate
Segmented information
Revenues	(159)	(185)	(183)
Income from equity investments	41	86	(53)
Plant operating costs and other	72	169	166
Commodity purchases resold	0		0
Property taxes	0	0	0
Depreciation and amortization	0	0	0
Asset impairment charge and other (Note 6)	0
Net gain/(loss) on assets sold/held for sale	0	0	0
Segmented Earnings/(Losses)	(46)	70	(70)
Capital Spending
Capital expenditures	35	58	32
Capital projects in development		0	0
Contributions to equity investments	0	0	0
Capital Spending	35	58	32
Assets	4,442	5,210
Geographic Information
Plant, Property and Equipment	516	621
Canadian Natural Gas Pipelines
Segmented information
Revenues	4,519	4,469	4,010
Canadian Natural Gas Pipelines | Operating segments
Segmented information
Revenues	4,519	4,469	4,010
Income from equity investments	12	12	12
Plant operating costs and other	(1,567)	(1,631)	(1,473)
Commodity purchases resold	0		0
Property taxes	(289)	(284)	(275)
Depreciation and amortization	(1,226)	(1,273)	(1,159)
Asset impairment charge and other (Note 6)	0
Net gain/(loss) on assets sold/held for sale	0	364	0
Segmented Earnings/(Losses)	1,449	1,657	1,115
Capital Spending
Capital expenditures	2,629	3,503	3,900
Capital projects in development		0	6
Contributions to equity investments	108	105	0
Capital Spending	2,737	3,608	3,906
Assets	25,213	22,852
Geographic Information
Plant, Property and Equipment	21,025	19,325
Canadian Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues	0	0	0
U.S. Natural Gas Pipelines
Segmented information
Revenues	5,233	5,031	4,978
U.S. Natural Gas Pipelines | Operating segments
Segmented information
Revenues	5,378	5,196	5,142
Income from equity investments	244	264	264
Plant operating costs and other	(1,393)	(1,485)	(1,581)
Commodity purchases resold	0		0
Property taxes	(367)	(337)	(345)
Depreciation and amortization	(791)	(801)	(754)
Asset impairment charge and other (Note 6)	0
Net gain/(loss) on assets sold/held for sale	0	0	21
Segmented Earnings/(Losses)	3,071	2,837	2,747
Capital Spending
Capital expenditures	2,611	2,785	2,500
Capital projects in development		0	0
Contributions to equity investments	209	0	16
Capital Spending	2,820	2,785	2,516
Assets	45,502	43,217
Geographic Information
Plant, Property and Equipment	30,178	28,169
U.S. Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues	(145)	(165)	(164)
Mexico Natural Gas Pipelines
Segmented information
Revenues	605	716	603
Mexico Natural Gas Pipelines | Operating segments
Segmented information
Revenues	605	716	603
Income from equity investments	119	127	56
Plant operating costs and other	(55)	(57)	(54)
Commodity purchases resold	(3)		0
Property taxes	0	0	0
Depreciation and amortization	(109)	(117)	(115)
Asset impairment charge and other (Note 6)	0
Net gain/(loss) on assets sold/held for sale	0	0	0
Segmented Earnings/(Losses)	557	669	490
Capital Spending
Capital expenditures	129	173	323
Capital projects in development		0	0
Contributions to equity investments	0	0	34
Capital Spending	129	173	357
Assets	7,547	7,215
Geographic Information
Plant, Property and Equipment	5,942	5,968
Mexico Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues	0	0	0
Liquids Pipelines
Segmented information
Revenues	2,306	2,371	2,879
Liquids Pipelines | Operating segments
Segmented information
Revenues	2,306	2,371	2,879
Income from equity investments	71	75	70
Plant operating costs and other	(700)	(654)	(728)
Commodity purchases resold	(84)		0
Property taxes	(113)	(101)	(101)
Depreciation and amortization	(318)	(332)	(341)
Asset impairment charge and other (Note 6)	2,775
Net gain/(loss) on assets sold/held for sale	13	0	69
Segmented Earnings/(Losses)	(1,600)	1,359	1,848
Capital Spending
Capital expenditures	488	1,315	239
Capital projects in development		122	701
Contributions to equity investments	83	5	14
Capital Spending	571	1,442	954
Assets	14,951	16,744
Geographic Information
Plant, Property and Equipment	11,273	14,409
Liquids Pipelines | Intersegment eliminations
Segmented information
Revenues	0	0	0
Power and Storage
Segmented information
Revenues	724	412	785
Power and Storage | Operating segments
Segmented information
Revenues	738	432	804
Income from equity investments	411	455	571
Plant operating costs and other	(455)	(220)	(243)
Commodity purchases resold	0		(365)
Property taxes	(5)	(5)	(6)
Depreciation and amortization	(78)	(67)	(95)
Asset impairment charge and other (Note 6)	0
Net gain/(loss) on assets sold/held for sale	17	(414)	(211)
Segmented Earnings/(Losses)	628	181	455
Capital Spending
Capital expenditures	32	179	481
Capital projects in development		0	0
Contributions to equity investments	810	655	538
Capital Spending	842	834	1,019
Assets	6,563	5,062
Geographic Information
Plant, Property and Equipment	1,248	1,283
Power and Storage | Intersegment eliminations
Segmented information
Revenues	$ (14)	$ (20)	$ (19)

REVENUES - Disaggregation of Re

REVENUES - Disaggregation of Revenues (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	May 31, 2020
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 12,952	$ 12,647	$ 12,670
Other revenues	435	352	585
Revenues	13,387	12,999	13,255
Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	11,172	11,522	11,279
Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	324	192	662
Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1,456	933	729
Fee revenue from affiliates	87	138
Natural gas storage and other | Sur de Texas
Disaggregation of Revenue [Line Items]
Fee revenue from affiliates		77
Natural gas storage and other | Coastal GasLink
Disaggregation of Revenue [Line Items]
Fee revenue from affiliates		61
Canadian Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,519	4,469	4,010
Other revenues	0	0	0
Revenues	$ 4,519	4,469	4,010
Canadian Natural Gas Pipelines | Coastal GasLink
Disaggregation of Revenue [Line Items]
Ownership interest percentage	35.00%			35.00%
Canadian Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 4,432	4,408	4,010
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	87	61	0
U.S. Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	5,196	4,955	4,895
Other revenues	37	76	83
Revenues	5,233	5,031	4,978
U.S. Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,139	4,301	4,245
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	1,057	654	650
Mexico Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	605	716	603
Other revenues	0	0	0
Revenues	$ 605	716	603
Mexico Natural Gas Pipelines | Sur de Texas
Disaggregation of Revenue [Line Items]
Ownership interest percentage	60.00%
Mexico Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 576	607	601
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	29	109	2
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,030	2,209	2,427
Other revenues	276	162	452
Revenues	2,306	2,371	2,879
Liquids Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,025	2,206	2,423
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	5	3	4
Power and Storage
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	602	298	735
Other revenues	122	114	50
Revenues	724	412	785
Power and Storage | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Power and Storage | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	324	192	662
Power and Storage | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 278	$ 106	$ 73

REVENUES - Contract Balances (D

REVENUES - Contract Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 1,627	$ 1,330
Contract assets (Note 7)	202	132
Long-term contract assets (Note 14)	249	192
Contract liabilities	90	129
Long-term contract liabilities (Note 17)	184	203
Revenue recognized	$ 15	$ 18

REVENUES - Remaining Performanc

REVENUES - Remaining Performance Obligations - Narrative (Details) $ in Billions	Dec. 31, 2021CAD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 23.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 3.4
Future revenues, expected timing of satisfaction, period	1 year

KEYSTONE XL - Narrative (Detail

KEYSTONE XL - Narrative (Details) $ in Millions, $ in Millions	Jan. 08, 2021CAD ($)	Jan. 08, 2021USD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Jun. 30, 2021USD ($)	Jun. 09, 2021CAD ($)	Jan. 04, 2021USD ($)
Property, Plant and Equipment [Line Items]
Asset impairment charge and other (Note 6)			$ 2,775		$ 0	$ 0
Property, plant and equipment, net			70,182		69,775
Proceeds from sales of assets, net of transaction costs			35		3,407	2,398
Amount reclassified to interest expense					(3)
Redeemable non-controlling interest			0		633
Repurchase of Class A Interests			633		0	0
Payments to noncontrolling interests			16		$ 0	$ 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
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 A Interests | Government of Alberta | Additional Paid-In Capital
Property, Plant and Equipment [Line Items]
Aggregate transaction value			394
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
Proceeds from issuance of debt			1,028	$ 849
Keystone XL | Class C Interests | Government of Alberta
Property, Plant and Equipment [Line Items]
Stock issued during period			91
Payments to noncontrolling interests			16
Keystone XL | Liquids Pipelines
Property, Plant and Equipment [Line Items]
Asset impairment charge and other (Note 6)			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, 2021	Dec. 31, 2020	Dec. 31, 2019	Jun. 09, 2021
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment	$ 70,182	$ 69,775
Asset impairment charge and other, Pre-tax
Asset impairment charge and other (Note 6)	2,775	0	$ 0
Asset impairment charge and other, After-tax
Proceeds from sales of assets, net of transaction costs	35	$ 3,407	$ 2,398
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
Asset impairment charge and other (Note 6)	3,126
Contractual recoveries	(693)
Contractual and legal obligations related to termination activities	342
Asset impairment charge and other (Note 6)	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
Contractual and legal costs related to termination activities	192
Keystone XL | Liquids Pipelines | Fair Value
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment				175
Keystone XL | Liquids Pipelines | Power generation and natural gas storage plant, equipment and structures | Fair Value
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment	175
Keystone XL | Liquids Pipelines | Under construction
Asset impairment charge and other, Pre-tax
Asset impairment charge and other (Note 6)	$ 2,896
Keystone XL | Liquids Pipelines | Under construction | Fair Value
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment				0
Keystone XL | Liquids Pipelines | Other capitalized costs | Fair Value
Estimated Fair Value of Plant, Property and Equipment
Plant, Property and Equipment				0
Keystone XL | Liquids Pipelines | Capitalized interest | Fair Value
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Increase (Decrease) in Temporary Equity [Roll Forward]
Balance at beginning of year	$ 393	$ 0
Class A Interests issued	0	1,033
Net income/(loss) attributable to redeemable non-controlling interest	1	(10)	$ 0
Class A Interests repurchased	(394)	0
Class A Interests transferred to Current liabilities	0	(630)
Balance at end of year	$ 0	$ 393	$ 0

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Other Assets [Abstract]
Keystone XL contractual recoveries	$ 640	$ 0
Cash provided as collateral	273	142
Contract assets (Note 5)	202	132
Fair value of derivative contracts (Note 26)	169	235
Keystone XL assets held for sale	138	0
Prepaid expenses	112	126
Regulatory assets (Note 12)	53	131
Other	130	114
Other current assets	$ 1,717	$ 880

PLANT, PROPERTY AND EQUIPMENT_2

PLANT, PROPERTY AND EQUIPMENT (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Jun. 09, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Cost	$ 102,112		$ 99,372
Accumulated Depreciation	31,930		29,597
Net Book Value	70,182		69,775
Liquids Pipelines | Keystone XL
Property, Plant and Equipment [Line Items]
Net Book Value		$ 175
Asset impairment charges	3,126
Related capital projects in development	230
Liquids Pipelines | Under construction | Keystone XL
Property, Plant and Equipment [Line Items]
Asset impairment charges	2,896
Operating segments | Canadian Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	42,200		39,347
Accumulated Depreciation	21,175		20,022
Net Book Value	21,025		19,325
Operating segments | Canadian Natural Gas Pipelines | NGTL System
Property, Plant and Equipment [Line Items]
Cost	24,826		22,406
Accumulated Depreciation	8,521		7,832
Net Book Value	16,305		14,574
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	15,379		15,014
Accumulated Depreciation	11,087		10,682
Net Book Value	4,292		4,332
Operating segments | Canadian Natural Gas Pipelines | Other
Property, Plant and Equipment [Line Items]
Cost	1,937		1,885
Accumulated Depreciation	1,567		1,508
Net Book Value	370		377
Operating segments | Canadian Natural Gas Pipelines | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	1,995		1,927
Accumulated Depreciation	1,567		1,508
Net Book Value	428		419
Operating segments | Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | NGTL System
Property, Plant and Equipment [Line Items]
Cost	22,541		21,004
Accumulated Depreciation	8,521		7,832
Net Book Value	14,020		13,172
Operating segments | Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	15,240		14,864
Accumulated Depreciation	11,087		10,682
Net Book Value	4,153		4,182
Operating segments | Canadian Natural Gas Pipelines | Pipeline | NGTL System
Property, Plant and Equipment [Line Items]
Cost	14,892		14,190
Accumulated Depreciation	5,751		5,278
Net Book Value	9,141		8,912
Operating segments | Canadian Natural Gas Pipelines | Pipeline | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	10,423		10,297
Accumulated Depreciation	7,698		7,443
Net Book Value	2,725		2,854
Operating segments | Canadian Natural Gas Pipelines | Compression | NGTL System
Property, Plant and Equipment [Line Items]
Cost	6,191		5,421
Accumulated Depreciation	2,065		1,906
Net Book Value	4,126		3,515
Operating segments | Canadian Natural Gas Pipelines | Compression | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	4,165		3,930
Accumulated Depreciation	3,125		3,000
Net Book Value	1,040		930
Operating segments | Canadian Natural Gas Pipelines | Metering and other | NGTL System
Property, Plant and Equipment [Line Items]
Cost	1,458		1,393
Accumulated Depreciation	705		648
Net Book Value	753		745
Operating segments | Canadian Natural Gas Pipelines | Metering and other | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	652		637
Accumulated Depreciation	264		239
Net Book Value	388		398
Operating segments | Canadian Natural Gas Pipelines | Under construction | NGTL System
Property, Plant and Equipment [Line Items]
Cost	2,285		1,402
Accumulated Depreciation	0		0
Net Book Value	2,285		1,402
Operating segments | Canadian Natural Gas Pipelines | Under construction | Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost	139		150
Accumulated Depreciation	0		0
Net Book Value	139		150
Operating segments | Canadian Natural Gas Pipelines | Under construction | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	58		42
Accumulated Depreciation	0		0
Net Book Value	58		42
Operating segments | U.S. Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	36,320		33,536
Accumulated Depreciation	6,142		5,367
Net Book Value	30,178		28,169
Operating segments | U.S. Natural Gas Pipelines | Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	9,900		9,042
Accumulated Depreciation	3,161		2,960
Net Book Value	6,739		6,082
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	19,817		18,943
Accumulated Depreciation	1,437		1,018
Net Book Value	18,380		17,925
Operating segments | U.S. Natural Gas Pipelines | ANR
Property, Plant and Equipment [Line Items]
Cost	6,603		5,551
Accumulated Depreciation	1,544		1,389
Net Book Value	5,059		4,162
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	9,367		8,653
Accumulated Depreciation	3,161		2,960
Net Book Value	6,206		5,693
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	19,384		17,873
Accumulated Depreciation	1,437		1,018
Net Book Value	17,947		16,855
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | ANR
Property, Plant and Equipment [Line Items]
Cost	5,770		5,120
Accumulated Depreciation	1,544		1,389
Net Book Value	4,226		3,731
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Other
Property, Plant and Equipment [Line Items]
Cost	1,755		1,568
Accumulated Depreciation	657		578
Net Book Value	1,098		990
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	11,205		10,198
Accumulated Depreciation	799		557
Net Book Value	10,406		9,641
Operating segments | U.S. Natural Gas Pipelines | Pipeline | ANR
Property, Plant and Equipment [Line Items]
Cost	1,820		1,685
Accumulated Depreciation	557		512
Net Book Value	1,263		1,173
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Columbia Gulf
Property, Plant and Equipment [Line Items]
Cost	2,749		2,638
Accumulated Depreciation	178		151
Net Book Value	2,571		2,487
Operating segments | U.S. Natural Gas Pipelines | Pipeline | GTN
Property, Plant and Equipment [Line Items]
Cost	2,701		2,330
Accumulated Depreciation	1,071		1,008
Net Book Value	1,630		1,322
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Great Lakes
Property, Plant and Equipment [Line Items]
Cost	2,162		2,117
Accumulated Depreciation	1,255		1,223
Net Book Value	907		894
Operating segments | U.S. Natural Gas Pipelines | Compression | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	4,522		4,287
Accumulated Depreciation	381		276
Net Book Value	4,141		4,011
Operating segments | U.S. Natural Gas Pipelines | Compression | ANR
Property, Plant and Equipment [Line Items]
Cost	2,559		2,146
Accumulated Depreciation	565		489
Net Book Value	1,994		1,657
Operating segments | U.S. Natural Gas Pipelines | Metering and other | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	3,657		3,388
Accumulated Depreciation	257		185
Net Book Value	3,400		3,203
Operating segments | U.S. Natural Gas Pipelines | Metering and other | ANR
Property, Plant and Equipment [Line Items]
Cost	1,391		1,289
Accumulated Depreciation	422		388
Net Book Value	969		901
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	533		389
Accumulated Depreciation	0		0
Net Book Value	533		389
Operating segments | U.S. Natural Gas Pipelines | Under construction | Columbia Gas
Property, Plant and Equipment [Line Items]
Cost	433		1,070
Accumulated Depreciation	0		0
Net Book Value	433		1,070
Operating segments | U.S. Natural Gas Pipelines | Under construction | ANR
Property, Plant and Equipment [Line Items]
Cost	833		431
Net Book Value	833		431
Operating segments | Mexico Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost	6,653		6,581
Accumulated Depreciation	711		613
Net Book Value	5,942		5,968
Operating segments | Mexico Natural Gas Pipelines | Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost	4,063		4,056
Accumulated Depreciation	711		613
Net Book Value	3,352		3,443
Operating segments | Mexico Natural Gas Pipelines | Pipeline
Property, Plant and Equipment [Line Items]
Cost	2,957		2,952
Accumulated Depreciation	476		411
Net Book Value	2,481		2,541
Operating segments | Mexico Natural Gas Pipelines | Compression
Property, Plant and Equipment [Line Items]
Cost	480		480
Accumulated Depreciation	80		69
Net Book Value	400		411
Operating segments | Mexico Natural Gas Pipelines | Metering and other
Property, Plant and Equipment [Line Items]
Cost	626		624
Accumulated Depreciation	155		133
Net Book Value	471		491
Operating segments | Mexico Natural Gas Pipelines | Under construction
Property, Plant and Equipment [Line Items]
Cost	2,590		2,525
Accumulated Depreciation	0		0
Net Book Value	2,590		2,525
Operating segments | Liquids Pipelines
Property, Plant and Equipment [Line Items]
Cost	14,034		16,869
Accumulated Depreciation	2,761		2,460
Net Book Value	11,273		14,409
Operating segments | Liquids Pipelines | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	13,835		16,671
Accumulated Depreciation	2,747		2,451
Net Book Value	11,088		14,220
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines
Property, Plant and Equipment [Line Items]
Cost	199		198
Accumulated Depreciation	14		9
Net Book Value	185		189
Operating segments | Liquids Pipelines | Property, plant and equipment excluding under construction | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	13,763		13,801
Accumulated Depreciation	2,747		2,451
Net Book Value	11,016		11,350
Operating segments | Liquids Pipelines | Pipeline | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	9,209		9,254
Accumulated Depreciation	1,758		1,579
Net Book Value	7,451		7,675
Operating segments | Liquids Pipelines | Pumping equipment | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	1,020		1,025
Accumulated Depreciation	252		228
Net Book Value	768		797
Operating segments | Liquids Pipelines | Tanks and other | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	3,534		3,522
Accumulated Depreciation	737		644
Net Book Value	2,797		2,878
Operating segments | Liquids Pipelines | Under construction | Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost	72		2,870
Accumulated Depreciation	0		0
Net Book Value	72		2,870
Operating segments | Power and Storage
Property, Plant and Equipment [Line Items]
Cost	2,069		2,046
Accumulated Depreciation	821		763
Net Book Value	1,248		1,283
Operating segments | Power and Storage | Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost	2,064		2,035
Accumulated Depreciation	821		763
Net Book Value	1,243		1,272
Operating segments | Power and Storage | Natural Gas
Property, Plant and Equipment [Line Items]
Cost	1,267		1,255
Accumulated Depreciation	605		569
Net Book Value	662		686
Operating segments | Power and Storage | Natural Gas Storage and Other
Property, Plant and Equipment [Line Items]
Cost	797		780
Accumulated Depreciation	216		194
Net Book Value	581		586
Operating segments | Power and Storage | Under construction
Property, Plant and Equipment [Line Items]
Cost	5		11
Accumulated Depreciation	0		0
Net Book Value	5		11
Corporate
Property, Plant and Equipment [Line Items]
Cost	836		993
Accumulated Depreciation	320		372
Net Book Value	$ 516		$ 621

LEASES - (Lessee) Narrative (De

LEASES - (Lessee) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Operating lease termination period	1 year
Right-of-use asset	$ 415	$ 473
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, 2021	Dec. 31, 2020
Operating lease cost
Operating lease cost	$ 105	$ 124
Sublease income	(8)	(13)
Net operating lease cost	97	111
Cash paid for amounts included in the measurement of operating lease liabilities	69	77
ROU assets obtained in exchange for new operating lease liabilities	$ 32	$ 14
Weighted average remaining lease term	9 years	10 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, 2021	Dec. 31, 2020
Leases [Abstract]
Less than one year	$ 63	$ 72
One to two years	60	61
Two to three years	58	59
Three to four years	55	58
Four to five years	54	54
More than five years	213	269
Total operating lease payments	503	573
Imputed interest	(74)	(90)
Operating lease liabilities	429	483
Operating lease, reported as accounts payable and other	49	56
Operating lease, reported as other long-term liabilities	$ 380	$ 427
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts payable and other (Note 16)	Accounts payable and other (Note 16)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other Long-Term Liabilities (Note 17)	Other Long-Term Liabilities (Note 17)

LEASES - (Lessor) Narrative (De

LEASES - (Lessor) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Fixed portion of the operating lease income	$ 126	$ 130	$ 180
Cost for facilities accounted for as operating leases	812	858
Accumulated depreciation for facilities accounted for as operating leases	$ 340	$ 327

LEASES - (Lessor) Future Lease

LEASES - (Lessor) Future Lease Payments to be Received Under Operating Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Less than one year	$ 113	$ 119
One to two years	111	111
Two to three years	110	109
Three to four years	94	109
Four to five years	70	94
More than five years	0	70
Total payments to be received	$ 498	$ 612

EQUITY INVESTMENTS - Ownership

EQUITY INVESTMENTS - Ownership Information of Equity Investments (Details) $ in Millions, $ in Millions	Nov. 30, 2021	Nov. 30, 2021	Jul. 31, 2019	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Nov. 13, 2020	May 31, 2020
Equity Investments
Income from Equity Investments				$ 898	$ 1,019	$ 920
Equity Investments				$ 8,441	6,677
Northern Courier
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets					56
Canadian Natural Gas Pipelines | TQM
Equity Investments
Ownership interest percentage				50.00%			50.00%
Income from Equity Investments				$ 12	12	12
Equity Investments				$ 118	90
Canadian Natural Gas Pipelines | Coastal GasLink
Equity Investments
Ownership interest percentage				35.00%			35.00%			35.00%
Income from Equity Investments				$ 0	0	0
Equity Investments				386	211
Difference between the carrying value of the investment and the underlying equity in the net assets				$ 167	188
U.S. Natural Gas Pipelines | Northern Border
Equity Investments
Ownership interest percentage				50.00%			50.00%
Income from Equity Investments				$ 80	100	91
Equity Investments				$ 505	521
Difference between the carrying value of the investment and the underlying equity in the net assets							$ 115	$ 116
U.S. Natural Gas Pipelines | Millennium
Equity Investments
Ownership interest percentage				47.50%			47.50%
Income from Equity Investments				$ 91	96	92
Equity Investments				$ 474	482
U.S. Natural Gas Pipelines | Iroquois
Equity Investments
Ownership interest percentage				50.00%			50.00%
Income from Equity Investments				$ 55	52	54
Equity Investments				392	197
Difference between the carrying value of the investment and the underlying equity in the net assets							$ 39	39
U.S. Natural Gas Pipelines | Other
Equity Investments
Income from Equity Investments				18	16	27
Equity Investments				$ 137	120
Mexico Natural Gas Pipelines | Sur de Texas
Equity Investments
Ownership interest percentage				60.00%			60.00%
Income from Equity Investments				$ 160	213	3
Equity Investments				$ 835	680
Difference between the carrying value of the investment and the underlying equity in the net assets							$ 77	$ 79
Liquids Pipelines | Grand Rapids
Equity Investments
Ownership interest percentage				50.00%			50.00%
Income from Equity Investments				$ 54	53	56
Equity Investments				980	998
Difference between the carrying value of the investment and the underlying equity in the net assets				96	98
Liquids Pipelines | Northern Courier
Equity Investments
Ownership interest percentage			15.00%
Income from Equity Investments				16	22	14
Equity Investments				$ 0	53
Ownership interest sold		15.00%
Liquids Pipelines | Port Neches Link LLC
Equity Investments
Ownership interest percentage				95.00%			95.00%
Income from Equity Investments				$ 0	0	0
Equity Investments				$ 103	0
Liquids Pipelines | HoustonLink Pipeline
Equity Investments
Ownership interest percentage				50.00%			50.00%
Income from Equity Investments				$ 1	0	0
Equity Investments				$ 18	19
Power and Storage | TransCanada Turbines
Equity Investments
Business acquisition, percentage of voting interests acquired									50.00%
Power and Storage | Bruce Power
Equity Investments
Ownership interest percentage				48.40%			48.40%
Income from Equity Investments				$ 411	439	527
Equity Investments				4,493	3,306
Difference between the carrying value of the investment and the underlying equity in the net assets				755	796
Power and Storage | Portlands Energy
Equity Investments
Income from Equity Investments				0	12	35
Equity Investments				$ 0	0
Power and Storage | TransCanada Turbines
Equity Investments
Ownership interest percentage				100.00%			100.00%
Income from Equity Investments				$ 0	4	$ 9
Equity Investments				$ 0	$ 0
Northern Courier | Disposal group, disposed of by sale, not discontinued operations
Equity Investments
Ownership interest sold	15.00%		85.00%

EQUITY INVESTMENTS - Narrative

EQUITY INVESTMENTS - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Equity Investments
Distributions received from equity investments	$ 1,048	$ 1,123	$ 1,399
Returns of capital	73	0	186
Contributions to equity investments	$ 1,210	$ 765	602
Sur de Texas
Equity Investments
Contributions to equity investments			$ 32

EQUITY INVESTMENTS - Summarized

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income
Revenues	$ 13,387	$ 12,999	$ 13,255
Operating and other expenses	(10,256)	(7,195)	(7,469)
Net income	1,955	4,616	4,140
Income from equity investments	898	1,019	920
Balance Sheet
Current assets	7,423	5,201
Current liabilities	(13,041)	(11,987)
Group of Investees
Income
Revenues	5,447	5,838	5,693
Operating and other expenses	(3,293)	(3,341)	(3,408)
Net income	1,859	2,047	1,990
Income from equity investments	898	1,019	$ 920
Balance Sheet
Current assets	3,498	2,911
Non-current assets	30,165	26,957
Current liabilities	(2,540)	(3,727)
Non-current liabilities	$ (16,400)	$ (15,309)

LOANS RECEIVABLE FROM AFFILIA_3

LOANS RECEIVABLE FROM AFFILIATES - Narrative (Details)	Dec. 31, 2021CAD ($)	Dec. 31, 2021MXN ($)	Dec. 06, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020MXN ($)	Dec. 31, 2017MXN ($)
Loans and Leases Receivable Disclosure [Line Items]
Long-term loans receivable	$ 238,000,000			$ 1,338,000,000
Loans receivable from affiliates (Note 11)	1,217,000,000			0
Subordinated Debt | Subordinated Loan Agreement | Coastal GasLink
Loans and Leases Receivable Disclosure [Line Items]
Debt instrument, face amount			$ 3,275,000,000
Revolving credit facility | Line of credit | Coastal GasLink
Loans and Leases Receivable Disclosure [Line Items]
Revolving credit facility, borrowing capacity	500,000,000
Loans receivable from affiliates (Note 11)	1,000,000			0
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
Equity method investee | Coastal GasLink
Loans and Leases Receivable Disclosure [Line Items]
Long-term loans receivable	$ 238,000,000
Sur de Texas | Mexico Natural Gas Pipelines
Loans and Leases Receivable Disclosure [Line Items]
Ownership interest percentage	60.00%	60.00%
Sur de Texas | Joint venture
Loans and Leases Receivable Disclosure [Line Items]
Loan receivable from affiliate	$ 1,200,000,000	$ 19,700,000,000		$ 1,300,000,000	$ 20,900,000,000

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Loans and Leases Receivable Disclosure [Line Items]
Foreign exchange losses/(gains) on loan receivable from affiliate (Note 11)	$ 41	$ 86	$ (53)
Sur de Texas | Interest income and other | Joint venture
Loans and Leases Receivable Disclosure [Line Items]
Interest income	87	110	147
Foreign exchange losses/(gains) on loan receivable from affiliate (Note 11)	(41)	(86)	53
Sur de Texas | Income from equity investments | Joint venture
Loans and Leases Receivable Disclosure [Line Items]
Interest expense	(87)	(110)	(147)
Foreign exchange losses/(gains) on loan receivable from affiliate (Note 11)	$ (41)	$ (86)	$ 53

RATE-REGULATED BUSINESSES - Nar

RATE-REGULATED BUSINESSES - Narrative (Details) $ in Millions, $ in Billions	Dec. 17, 2021USD ($)	Apr. 30, 2020	Dec. 31, 2018	Nov. 30, 2018	Dec. 31, 2021	Dec. 31, 2019	Dec. 31, 2014CAD ($)	Dec. 31, 2013USD ($)
Columbia Gas Transmission
Public Utilities, General Disclosures [Line Items]
Maximum cost recovery and return on investment	$ 1.2							$ 2.6
Remaining Recovery/ Settlement Period (years)	4 years
NGTL System
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity					10.10%	10.10%
Deemed common equity, percent					40.00%	40.00%
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity					10.10%		10.10%
Deemed common equity, percent					40.00%		40.00%
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, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020CAD ($)
Regulatory Assets
Regulatory Assets	$ 1,820		$ 1,884
Less: Current portion included in Other current assets (Note 7)	53		131
Regulatory Assets, noncurrent	1,767		1,753
Regulatory Liabilities
Regulatory Liabilities	4,500		4,301
Less: Current portion included in Accounts payable and other (Note 16)	200		153
Regulatory Liabilities, noncurrent	4,300		4,148
Pipeline abandonment trust balances
Regulatory Liabilities
Regulatory Liabilities	2,086		1,842
Deferred income taxes - U.S. Tax Reform
Regulatory Liabilities
Regulatory Liabilities	1,141		1,170
Bridging amortization account
Regulatory Liabilities
Regulatory Liabilities	$ 483		537
Remaining Recovery/ Settlement Period (years)	9 years	9 years
Cost of removal
Regulatory Liabilities
Regulatory Liabilities	$ 254		246
Long term adjustment account
Regulatory Liabilities
Regulatory Liabilities	$ 186		223
Remaining Recovery/ Settlement Period (years)	5 years	5 years
Deferred income taxes
Regulatory Liabilities
Regulatory Liabilities	$ 139		115
Canadian Mainline short-term adjustment and toll-stabilization accounts
Regulatory Liabilities
Regulatory Liabilities	$ 60		4
Remaining Recovery/ Settlement Period (years)	6 years	6 years
Pensions and other post retirement benefits
Regulatory Liabilities
Regulatory Liabilities	$ 13		18
Pensions and other post retirement benefits | ANR PIPELINE COMPANY
Regulatory Liabilities
Regulatory Liabilities	40		40
Operating and debt-service regulatory liabilities
Regulatory Liabilities
Regulatory Liabilities	$ 32		48
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Other
Regulatory Liabilities
Regulatory Liabilities	$ 66		58
Long term adjustment account, amount to be amortized over one year
Regulatory Liabilities
Regulatory Liabilities	$ 223
Remaining Recovery/ Settlement Period (years)	6 years	6 years
Long term adjustment account, short term adjustments accounts
Regulatory Liabilities
Regulatory Liabilities	$ 4
Postretirement benefit costs | ANR PIPELINE COMPANY
Regulatory Liabilities
Amount to be addressed In next settlement	40	$ 32
Deferred income taxes
Regulatory Assets
Regulatory Assets	1,509		1,287
Pensions and other post retirement benefits
Regulatory Assets
Regulatory Assets	203		401
Foreign exchange on long-term debt
Regulatory Assets
Regulatory Assets	$ 3		7
Foreign exchange on long-term debt | Minimum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Foreign exchange on long-term debt | Maximum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	8 years	8 years
Operating and debt-service regulatory assets
Regulatory Assets
Regulatory Assets	$ 1		54
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Other
Regulatory Assets
Regulatory Assets	$ 104		$ 135

GOODWILL - Acquisitions (Detail

GOODWILL - Acquisitions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Goodwill
Balance at the beginning of the period	$ 12,679
Balance at the end of the period	12,582	$ 12,679
U.S. Natural Gas Pipelines
Goodwill
Balance at the beginning of the period	12,679	12,887
Foreign exchange rate changes	(97)	(208)
Balance at the end of the period	$ 12,582	$ 12,679

GOODWILL - Narrative (Details)

GOODWILL - Narrative (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Aug. 31, 2019
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	$ 12,582	$ 12,679
Columbia
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	$ 9,303
Midstream
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill			$ 595

OTHER LONG-TERM ASSETS - Summar

OTHER LONG-TERM ASSETS - Summary (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Deferred income tax assets (Note 18)	$ 509	$ 177
Employee post-retirement benefits (Note 25)	312	207
Long-term contract assets (Note 5)	249	192
Keystone XL contractual recoveries (Note 6)	50	0
Fair value of derivative contracts (Note 26)	48	41
Capital projects in development1	14	231
Other	221	131
Total other assets	$ 1,403	$ 979

OTHER LONG-TERM ASSETS - Narrat

OTHER LONG-TERM ASSETS - Narrative (Details) - Keystone XL - Liquids Pipelines $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)
Finite-Lived Intangible Assets [Line Items]
Asset impairment charges	$ 3,126
Under construction
Finite-Lived Intangible Assets [Line Items]
Asset impairment charges	$ 2,896

NOTES PAYABLE (Details)

NOTES PAYABLE (Details)	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2021MXN ($)	Dec. 31, 2020USD ($)	Dec. 31, 2020MXN ($)
Notes payable
Outstanding	$ 5,166,000,000	$ 4,176,000,000
Revolving credit facility
Notes payable
Cost to maintain	17,000,000	21,000,000	$ 11,000,000
Notes payable
Notes payable
Denominated value	1,989,000,000	656,000,000		$ 2,341,000,000		$ 1,709,000,000
Revolving and demand credit facility
Notes payable
Total Facilities	12,400,000,000	12,400,000,000
TCPL | Revolving credit facility | Maturing December 2026
Notes payable
Total Facilities	3,000,000,000	3,000,000,000
Unused Capacity	1,000,000,000
TCPL | Notes payable
Notes payable
Outstanding	$ 4,953,000,000	$ 2,836,000,000
Weighted average interest rate per annum	0.40%	0.40%		0.40%	0.40%	0.40%	0.40%
USA | Notes payable
Notes payable
Outstanding	$ 68,000,000	$ 1,149,000,000		$ 54,000,000		$ 900,000,000
Weighted average interest rate per annum	0.30%	0.40%		0.30%	0.30%	0.40%	0.40%
Mexico subsidiary | Revolving credit facility
Notes payable
Total Facilities					$ 5,000,000,000		$ 5,000,000,000
Unused Capacity					$ 2,600,000,000
Mexico subsidiary | Notes payable
Notes payable
Outstanding	$ 145,000,000	$ 191,000,000		$ 115,000,000		$ 150,000,000
Weighted average interest rate per annum	1.70%	1.70%		1.70%	1.70%	1.70%	1.70%
TCPL / TCPL USA / Columbia / TransCanada American Investments Ltd. | Revolving credit facility | Maturing December 2022
Notes payable
Total Facilities				$ 4,500,000,000		$ 4,500,000,000
Unused Capacity				2,100,000,000
TCPL / TCPL USA / Columbia / TransCanada American Investments Ltd. | Revolving credit facility | Maturing December 2024
Notes payable
Total Facilities				1,000,000,000		$ 1,000,000,000
Unused Capacity				$ 1,000,000,000
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 (Det

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Payables and Accruals [Abstract]
Trade payables	$ 4,183	$ 3,057
Fair value of derivative contracts (Note 26)	221	72
Regulatory liabilities (Note 12)	200	153
Contract liabilities (Note 5)	90	129
Class C Interests (Note 6)	75	0
Other	330	405
Accounts payable and other	$ 5,099	$ 3,816

OTHER LONG-TERM LIABILITIES (De

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred Costs, Noncurrent [Abstract]
Operating lease obligations (Note 9)	$ 380	$ 427
Long-term contract liabilities (Note 5)	184	203
Employee post-retirement benefits (Note 25)	174	503
Asset retirement obligations	61	54
Fair value of derivative contracts (Note 26)	47	59
Other	213	229
Other long-term liabilities	$ 1,059	$ 1,475

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current
Canada	$ 29	$ (54)	$ 84
Foreign	276	306	615
Total	305	252	699
Deferred
Canada	(327)	(224)	(29)
Foreign	142	166	84
Total	(185)	(58)	55
Income Tax Expense	$ 120	$ 194	$ 754

INCOME TAXES - Geographic Compo

INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Canada	$ (292)	$ 691	$ 1,144
Foreign	2,458	4,416	4,043
Income before Income Taxes	$ 2,166	$ 5,107	$ 5,187

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income before income taxes	$ 2,166	$ 5,107	$ 5,187
Federal and provincial statutory tax rate	23.00%	24.00%	26.50%
Expected income tax expense	$ 498	$ 1,226	$ 1,375
Valuation allowance releases	(8)	(400)	(259)
Foreign income tax rate differentials	(230)	(258)	(180)
Income tax differential related to regulated operations	(139)	(228)	(159)
Income from non-controlling interests and equity investments	(70)	(141)	(78)
Alberta tax rate reduction	0	0	(32)
Non-taxable portion of capital gains	0	(62)	(28)
Non-deductible goodwill on the Columbia Midstream asset disposition	0	0	154
Impact of Mexico inflationary adjustments	32	7	13
Other	37	50	(52)
Income Tax Expense	$ 120	$ 194	$ 754

INCOME TAXES - Deferred Assets

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred Income Tax Assets
Tax loss and credit carryforwards	$ 1,163	$ 1,389
Regulatory and other deferred amounts	537	532
Unrealized foreign exchange losses on long-term debt	130	154
Financial instruments	0	48
Other	46	70
Deferred tax assets, gross	1,876	2,193
Less: Valuation allowance	229	243
Deferred tax assets, net of Valuation allowance	1,647	1,950
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment	5,616	6,124
Equity investments	1,219	1,087
Taxes on future revenue requirement	333	287
Other	112	81
Deferred tax liabilities, gross	7,280	7,579
Net Deferred Income Tax Liabilities	5,633	5,629
Deferred Income Tax Assets
Other long-term assets (Note 14)	509	177
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities	$ 6,142	$ 5,806

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) $ in Millions	May 22, 2020	May 31, 2020	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Net operating loss carryforwards
Valuation allowance			$ 229,000,000	$ 243,000,000
Decrease in valuation allowance				(400,000,000)
Deferred income tax liabilities on the unremitted earnings of foreign investments			896,000,000	684,000,000
Income tax payments, net of refunds			371,000,000	252,000,000	$ 713,000,000
Interest expense (recovery) reflected within net tax expense			1,000,000	4,000,000	4,000,000
Accrued interest expense			12,000,000	11,000,000	7,000,000
Income tax penalties expense			0	0	0
Income tax penalties accrued			0	$ 0	$ 0
Disposal group, disposed of by sale, not discontinued operations | Coastal GasLink
Net operating loss carryforwards
Ownership interest sold	65.00%	65.00%		65.00%
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards			4,067,000,000	$ 3,671,000,000
Capital loss carryforwards unrecognized			21,000,000	253,000,000
Canada federal and provincial | Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits			$ 113,000,000	$ 106,000,000
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards						$ 446	$ 849
Mexican Tax Authority (SAT)
Net operating loss carryforwards
Unused net operating loss carryforwards						10	$ 13
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

INCOME TAXES - Reconciliation_2

INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefit at beginning of year	$ 52	$ 29	$ 19
Gross increases – tax positions in prior years	5	26	13
Gross decreases – tax positions in prior years	(1)	(2)	(1)
Gross increases – tax positions in current year	26	1	0
Lapse of statutes of limitations	(2)	(2)	(2)
Unrecognized Tax Benefit at End of Year	$ 80	$ 52	$ 29

LONG-TERM DEBT - Amounts Outsta

LONG-TERM DEBT - Amounts Outstanding and Principal Repayments (Details) $ in Millions, $ in Millions	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)
Debt Instrument [Line Items]
Outstanding	$ 38,756		$ 36,956
Current portion of long-term debt	(1,320)		(1,972)
Unamortized debt discount and issue costs	(243)		(238)
Fair value adjustments	148		167
Noncurrent portion of long-term debt	37,341		34,913
Repayments of Long-term Debt [Abstract]
2022	1,320
2023	1,823
2024	2,657
2025	2,698
2026	1,778
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	33,427		30,228
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Date of 2021
Debt Instrument [Line Items]
Outstanding	$ 0	$ 0	$ 510	$ 400
Interest Rate	0.00%	0.00%	9.90%	9.90%
TRANSCANADA PIPELINES LIMITED | Medium Term Notes
Debt Instrument [Line Items]
Outstanding	$ 12,491		$ 11,491
Interest Rate	4.20%	4.20%	4.50%	4.50%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 20,936	$ 16,542	$ 18,227	$ 14,292
Interest Rate	4.80%	4.80%	5.30%	5.30%
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	$ 899		$ 901
NOVA GAS TRANSMISSION LTD. | Debentures and Notes, Maturity Date of 2024
Debt Instrument [Line Items]
Outstanding	$ 100		$ 100
Interest Rate	9.90%	9.90%	9.90%	9.90%
NOVA GAS TRANSMISSION LTD. | Debentures and Notes, Maturity Date of 2023
Debt Instrument [Line Items]
Outstanding	$ 254	$ 200	$ 255	$ 200
Interest Rate	7.90%	7.90%	7.90%	7.90%
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity between 2025 and 2030
Debt Instrument [Line Items]
Outstanding	$ 504		$ 504
Interest Rate	7.40%	7.40%	7.40%	7.40%
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity Date of 2026
Debt Instrument [Line Items]
Outstanding	$ 41	$ 33	$ 42	$ 33
Interest Rate	7.50%	7.50%	7.50%	7.50%
COLUMBIA PIPELINE GROUP, INC. | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 1,898	$ 1,500	$ 1,913	$ 1,500
Interest Rate	4.90%	4.90%	4.90%	4.90%
TC PIPELINES, LP
Debt Instrument [Line Items]
Outstanding	$ 1,076		$ 2,104
TC PIPELINES, LP | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 1,076	$ 850	$ 1,530	$ 1,200
Interest Rate	4.20%	4.20%	4.40%	4.40%
TC PIPELINES, LP | Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding	$ 0	$ 0	$ 574	$ 450
Interest Rate	0.00%	0.00%	1.40%	1.40%
ANR PIPELINE COMPANY | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 472	$ 372	$ 858	$ 672
Interest Rate	5.30%	5.30%	7.20%	7.20%
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 411	$ 325	$ 415	$ 325
Interest Rate	4.30%	4.30%	4.30%	4.30%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Debt Instrument [Line Items]
Outstanding	$ 316		$ 191
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 316	$ 250	$ 159	$ 125
Interest Rate	2.80%	2.80%	2.80%	2.80%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Unsecured Loan Facility
Debt Instrument [Line Items]
Outstanding	$ 0	$ 0	$ 32	$ 25
Interest Rate	0.00%	0.00%	1.30%	1.30%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 211	$ 167	$ 253	$ 198
Interest Rate	7.60%	7.60%	7.60%	7.60%
TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding	$ 46	$ 36	$ 29	$ 23
Interest Rate	1.30%	1.30%	2.20%	2.20%
NORTH BAJA PIPELINE, LLC | Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding	$ 0	$ 0	$ 64	$ 50
Interest Rate	0.00%	0.00%	1.20%	1.20%

LONG-TERM DEBT - Issued (Detail

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

Nov. 30, 2021

May 22, 2020

Jun. 30, 2019CAD ($)

Nov. 30, 2021

Oct. 31, 2021USD ($)

Aug. 31, 2021USD ($)

Jun. 30, 2021CAD ($)

Jan. 31, 2021USD ($)

Oct. 31, 2020USD ($)

Jun. 30, 2020USD ($)

May 31, 2020

Apr. 30, 2020USD ($)

Apr. 30, 2020CAD ($)

Sep. 30, 2019CAD ($)

Jul. 31, 2019CAD ($)

Apr. 30, 2019CAD ($)

Dec. 31, 2021USD ($)

Dec. 31, 2021CAD ($)

Dec. 31, 2020

Jun. 30, 2021USD ($)

Jan. 04, 2021USD ($)

Northern Courier | Liquids Pipelines

Debt Instrument [Line Items]

Ownership interest sold

15.00%

Ownership interest percentage

15.00%

Coastal GasLink | Canadian Natural Gas Pipelines

Debt Instrument [Line Items]

Ownership interest percentage

35.00%

35.00%

35.00%

Disposal group, disposed of by sale, not discontinued operations | Northern Courier

Debt Instrument [Line Items]

Ownership interest sold

15.00%

85.00%

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

Debt Instrument [Line Items]

Ownership interest sold

65.00%

65.00%

65.00%

Senior Secured Credit Facilities due April 2027

Debt Instrument [Line Items]

Amount

$ 1,500

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due October 2024

Debt Instrument [Line Items]

Amount

$ 1,250

Interest Rate

1.00%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due October 2031

Debt Instrument [Line Items]

Amount

$ 1,000

Interest Rate

2.50%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due June 2024

Debt Instrument [Line Items]

Amount

$ 750

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due June 2031

Debt Instrument [Line Items]

Amount

500

Interest Rate

2.97%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due September 2047

Debt Instrument [Line Items]

Amount

$ 250

Interest Rate

4.33%

Long-term debt, re-issuance yield

4.186%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due April 2030

Debt Instrument [Line Items]

Amount

$ 1,250

Interest Rate

4.10%

4.10%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due April 2027

Debt Instrument [Line Items]

Amount

$ 2,000

Interest Rate

3.80%

3.80%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due September 2029

Debt Instrument [Line Items]

Amount

$ 700

Interest Rate

3.00%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due July 2048

Debt Instrument [Line Items]

Amount

$ 300

Interest Rate

4.18%

Long-term debt, re-issuance yield

3.991%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due October 2049

Debt Instrument [Line Items]

Amount

$ 1,000

Interest Rate

4.34%

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

Debt Instrument [Line Items]

Amount

$ 125

Interest Rate

2.68%

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

Debt Instrument [Line Items]

Amount

$ 125

Interest Rate

2.84%

TUSCARORA GAS TRANSMISSION COMPANY | Senior Unsecured Notes due August 2024

Debt Instrument [Line Items]

Amount

$ 13

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

Debt Instrument [Line Items]

Amount

$ 849

$ 1,028

Revolving credit facility, borrowing capacity

$ 1,600

$ 4,100

COLUMBIA PIPELINE GROUP, INC.4 | Unsecured Term Loan due June 2022

Debt Instrument [Line Items]

Amount

$ 4,040

GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes due June 2030

Debt Instrument [Line Items]

Amount

$ 175

Interest Rate

3.12%

Coastal GasLink | Senior Secured Credit Facilities due April 2027

Debt Instrument [Line Items]

Amount

$ 1,603

Northern Courier | Senior Secured Notes due June 2042

Debt Instrument [Line Items]

Amount

$ 1,000

$ 1,000

Interest Rate

3.365%

LONG-TERM DEBT - Retired_Repaid

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

1 Months Ended

12 Months Ended

Dec. 31, 2021CAD ($)

Dec. 31, 2021USD ($)

Nov. 30, 2021CAD ($)

Nov. 30, 2021USD ($)

Oct. 31, 2021USD ($)

Jun. 30, 2021USD ($)

Mar. 31, 2021USD ($)

Jan. 31, 2021USD ($)

Nov. 30, 2020CAD ($)

Oct. 31, 2020USD ($)

Jun. 30, 2020USD ($)

Mar. 31, 2020USD ($)

Nov. 30, 2019USD ($)

Jun. 30, 2019USD ($)

May 31, 2019CAD ($)

May 31, 2019USD ($)

Mar. 31, 2019CAD ($)

Jan. 31, 2019USD ($)

Dec. 31, 2021CAD ($)

Dec. 31, 2021USD ($)

Dec. 31, 2020CAD ($)

Mar. 04, 2021CAD ($)

Mar. 04, 2021USD ($)

Dec. 31, 2020USD ($)

TRANSCANADA PIPELINES LIMITED | Medium Term Note due November 2021

Debt Instrument [Line Items]

Amount

$ 500,000,000

Interest Rate

3.65%

3.65%

TRANSCANADA PIPELINES LIMITED | Debentures due January 2021

Debt Instrument [Line Items]

Amount

$ 400

Interest Rate

9.875%

TRANSCANADA PIPELINES LIMITED | Debentures due November 2020

Debt Instrument [Line Items]

Amount

$ 250,000,000

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

$ 8,000,000

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due November 2019

Debt Instrument [Line Items]

Amount

$ 700

Interest Rate

2.125%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due November 2019

Debt Instrument [Line Items]

Amount

$ 550

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due May 2019

Debt Instrument [Line Items]

Amount

$ 13,000,000

Interest Rate

9.35%

9.35%

TRANSCANADA PIPELINES LIMITED | Debentures due March 2019

Debt Instrument [Line Items]

Amount

$ 100,000,000

Interest Rate

10.50%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due January 2019

Debt Instrument [Line Items]

Amount

$ 750

Interest Rate

7.125%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due January 2019

Debt Instrument [Line Items]

Amount

$ 400

Interest Rate

3.125%

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

$ 5,000,000

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 | Unsecured Term Loan due June 2019

Debt Instrument [Line Items]

Amount

$ 50

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%

9.625%

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

Debt Instrument [Line Items]

Amount

$ 10

Interest Rate

9.09%

9.09%

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

Debt Instrument [Line Items]

Amount

$ 93

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

$ 1,028,000,000

$ 849

GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes due June 2020

Debt Instrument [Line Items]

Amount

$ 100

Interest Rate

5.29%

GAS TRANSMISSION NORTHWEST LLC | Unsecured Term Loan due May 2019

Debt Instrument [Line Items]

Amount

$ 35

LONG-TERM DEBT - Interest Expen

LONG-TERM DEBT - Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Interest Expense [Abstract]
Capitalized interest	$ (22)	$ (294)	$ (186)
Amortization and other financial charges	78	43	55
Interest expense	2,360	2,228	2,333
Interest payments, net of interest capitalized	2,299	2,203	2,295
Short-term debt
Interest Expense [Abstract]
Interest on debt	10	46	106
Long-term debt (excluding junior subordinated notes)
Interest Expense [Abstract]
Interest on debt	1,841	1,963	1,931
Junior subordinated notes
Interest Expense [Abstract]
Interest on debt	$ 453	$ 470	$ 427

JUNIOR SUBORDINATED NOTES (Deta

JUNIOR SUBORDINATED NOTES (Details) $ in Millions	1 Months Ended		12 Months Ended
	Mar. 31, 2021CAD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)
Debt Instrument [Line Items]
Outstanding					$ 38,756	$ 36,956
Unamortized debt discount and issue costs					(243)	(238)
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding					33,427	30,228
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					9,024	8,578
Unamortized debt discount and issue costs					(85)	(80)
Long-term Debt					$ 8,939	8,498
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%	6.35%
Outstanding					$ 1,265	$ 1,275
Effective Interest Rate			4.00%		4.00%	4.10%
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					$ 949	$ 957
Effective Interest Rate			5.00%		5.00%	5.00%
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					$ 1,519	$ 1,530
Effective Interest Rate			5.80%		5.80%	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					$ 1,899	$ 1,913
Effective Interest Rate			4.70%		4.70%	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			4.50%		4.50%	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					$ 1,392	$ 1,403
Effective Interest Rate			5.40%		5.40%	5.40%
Stated interest rate, period of time			10 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	$ 0
Effective Interest Rate			4.00%		4.00%	0.00%
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	100.00%
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]
Variable interest rate	3.316%
Stated interest rate, period of time	5 years
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 PIPELINES LIMITED | Trust Notes - Series 2019-A | Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,100,000,000
Stated interest rate		5.75%
Administrative charge percentage		0.25%
Redemption price as a percentage of principal amount plus accrued and unpaid interest		100.00%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2019-A | Period two | Junior subordinated notes | LIBOR
Debt Instrument [Line Items]
Variable interest rate		4.404%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2019-A | Period three | Junior subordinated notes | LIBOR
Debt Instrument [Line Items]
Variable interest rate		5.154%
TransCanada Trust | Trust Notes - Series 2021-A | Notes payable
Debt Instrument [Line Items]
Debt instrument, face amount	$ 500
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
TransCanada Trust | Trust Notes - Series 2019-A | Notes payable
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,100,000,000
Stated interest rate, period of time		10 years
TransCanada Trust | Trust Notes - Series 2019-A | Period one | Notes payable
Debt Instrument [Line Items]
Stated interest rate		5.50%

NON-CONTROLLING INTERESTS - Nar

NON-CONTROLLING INTERESTS - Narrative (Details)	Mar. 03, 2021shares	Dec. 31, 2021	Mar. 04, 2021	Dec. 31, 2020	Dec. 31, 2019
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
Non-controlling interests
Percentage of non-controlling interests		74.50%		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, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Non-controlling interests
Common shares		$ 26,716	$ 24,488
Common Shares
Non-controlling interests
Common shares		$ 26,716	$ 24,488	$ 24,387	$ 23,174
TC PipeLines, LP
Non-controlling interests
Deferred income tax liabilities	$ (443)
Other	(12)
TC PipeLines, LP | Common Shares
Non-controlling interests
Noncontrolling interest, fair value	2,063
TC PipeLines, LP | Additional Paid-In Capital
Non-controlling interests
Noncontrolling interest, fair value	(398)
TC PipeLines, LP | Accumulated Other Comprehensive Loss (Note 24)
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Non-controlling interests
Redeemable non-controlling interest	$ 1	$ (10)	$ 0
Total non-controlling interests	91	297	293
TC PipeLines, LP
Non-controlling interests
Non-controlling interest	60	284	270
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Non-controlling interests
Non-controlling interest	$ 30	$ 23	$ 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)	940,000
Outstanding at the beginning of the period	$ 24,488
Exercise of options (in shares)	2,797
Outstanding at the end of the period (in shares)	981,000	940,000
Outstanding at the end of the period	$ 26,716	$ 24,488
Weighted Average Common Shares Outstanding
Basic (in shares)	973,000	940,000	929,000
Diluted (in shares)	974,000	940,000	931,000
Common Shares
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)	940,064	938,400	918,097
Outstanding at the beginning of the period	$ 24,488	$ 24,387	$ 23,174
Dividend reinvestment and share purchase plan (in shares)			15,165
Dividend reinvestment and share purchase plan			$ 931
Acquisition of TC Pipelines, LP, net of transaction costs (in shares)	37,955
Acquisition of TC PipeLines, LP, net of transaction costs (Note 21)	$ 2,063
Exercise of options (in shares)	2,797	1,664	5,138
Exercise of options	$ 165	$ 101	$ 282
Outstanding at the end of the period (in shares)	980,816	940,064	938,400
Outstanding at the end of the period	$ 26,716	$ 24,488	$ 24,387
Weighted Average Common Shares Outstanding
Basic (in shares)	973,000	940,000	929,000
Diluted (in shares)	974,000	940,000	931,000

COMMON SHARES - Dividend Reinve

COMMON SHARES - Dividend Reinvestment and Share Purchase Plan (Details) - shares	Mar. 03, 2021	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Discount of shares issued from treasury		2.00%
Price of shares issued from treasury		100.00%
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, 2021CAD ($)
Subsidiary, Sale of Stock [Line Items]
Stock issuance program, period in effect (in months)	25 months
Authorized amount	$ 1,000,000,000

COMMON SHARES - Options (Detail

COMMON SHARES - Options (Details)	12 Months Ended
	Dec. 31, 2021$ / sharesshares
Number of Options
Outstanding at the beginning of the period (in shares)	8,996,000
Granted (in shares)	1,679,000
Exercised (in shares)	(2,797,000)
Options forfeited/expired (in shares)	(109,000)
Outstanding at the end of the period (in shares)	7,769,000
Options Exercisable (in shares)	4,410,000
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share) | $ / shares	$ 59.55
Granted (in Canadian dollars per share) | $ / shares	56.86
Exercised (in Canadian dollars per share) | $ / shares	53.10
Options forfeited/expired (in Canadian dollars per share) | $ / shares	59.96
Outstanding at the end of the period (in Canadian dollars per share) | $ / shares	61.29
Options Exercisable at December 31, 2020 (in Canadian dollars per share) | $ / shares	$ 60.13
Weighted Average Remaining Contractual Life
Options Outstanding at December 31, 2021	4 years 2 months 12 days
Options Exercisable at December 31, 2021	3 years 2 months 12 days
Number of shares available for grant (in shares)	4,826,189
Options expiration term	7 years
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Vesting in year one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights percentage	33.33%
Vesting in year two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights percentage	33.33%
Vesting in year three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights percentage	33.34%

COMMON SHARES - Stock Options A

COMMON SHARES - Stock Options Assumptions Used (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Weighted average fair value (in dollars per share)	$ 7.39	$ 7.73	$ 6.37
Expected life	5 years 4 months 24 days	5 years 8 months 12 days	5 years 8 months 12 days
Interest rate	0.50%	1.50%	1.90%
Volatility	25.00%	17.00%	19.00%
Dividend yield	6.00%	4.20%	5.00%
Expense for stock options	$ 12	$ 12	$ 13
Unrecognized compensation costs related to non-vested stock options	$ 13
Expense recognition period	1 year 9 months 18 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Total intrinsic value of options exercised	$ 28	$ 31	$ 75
Total fair value of options that have vested	$ 110	$ 101	$ 143
Total options vested (in shares)	1.9	2	2.1
Options, exercisable, intrinsic value	$ 7
Options, outstanding, intrinsic value	$ 12

COMMON SHARES - Shareholder Rig

COMMON SHARES - Shareholder Rights Plan (Details)	Dec. 31, 2021shares
Shareholder Rights Plan
Number of rights entitled to each common share (in shares)	1

PREFERRED SHARES (Details)

PREFERRED SHARES (Details) $ / shares in Units, $ in Millions	May 31, 2021$ / sharesshares	Feb. 01, 2021shares	Jan. 30, 2021	Jun. 30, 2020shares	Dec. 31, 2019CAD ($)shares	Jan. 29, 2021	Jun. 30, 2021$ / shares	Dec. 31, 2021CAD ($)$ / sharesshares	Dec. 31, 2020CAD ($)
Preferred Shares [Line Items]
Carrying Value December 31 | $					$ 3,980			$ 3,487	$ 3,980
Series 1
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								14,577,000
Current Yield								3.479%
Annual Dividend Rate per Share (in Canadian dollars per share) | $ / shares								$ 0.86975
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25
Carrying Value December 31 | $					$ 360			$ 360	360
Number of preferred shares converted (in shares) | shares					173,954
Shares issued upon conversion per share of preferred stock (in shares) | shares					1
Series 1 | Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								1.92%
Series 2
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								7,423,000
Current Yield								2.049%
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25
Carrying Value December 31 | $					$ 179			$ 179	179
Number of preferred shares converted (in shares) | shares					5,252,715
Shares issued upon conversion per share of preferred stock (in shares) | shares					1
Series 2 | Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								1.92%
Series 3
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								9,997,000
Current Yield								1.694%
Annual Dividend Rate per Share (in Canadian dollars per share) | $ / shares								$ 0.4235
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25
Carrying Value December 31 | $					$ 209			$ 246	246
Shares converted (in shares) | shares				401,590
Conversion ratio				1
Series 3 | Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								1.28%
Series 4
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								4,003,000
Current Yield								1.409%
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25
Carrying Value December 31 | $					134			$ 97	97
Shares converted (in shares) | shares				1,865,362
Conversion ratio				1
Series 4 | Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								1.28%
Series 5
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								12,071,000
Current Yield			1.949%			2.263%		1.949%
Annual Dividend Rate per Share (in Canadian dollars per share) | $ / shares								$ 0.48725
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25
Carrying Value December 31 | $					310			$ 294	310
Shares converted (in shares) | shares		818,876
Conversion ratio		1
Series 5 | Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								1.54%
Series 6
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								1,929,000
Current Yield								1.686%
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25
Carrying Value December 31 | $					32			$ 48	32
Shares converted (in shares) | shares		175,208
Conversion ratio		1
Series 6 | Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								1.54%
Series 7
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								24,000,000
Current Yield								3.903%
Annual Dividend Rate per Share (in Canadian dollars per share) | $ / shares								$ 0.97575
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25
Carrying Value December 31 | $					589			$ 589	589
Series 7 | Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								2.38%
Series 9
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								18,000,000
Current Yield								3.762%
Annual Dividend Rate per Share (in Canadian dollars per share) | $ / shares								$ 0.9405
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25
Carrying Value December 31 | $					442			$ 442	442
Series 9 | Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								2.35%
Series 11
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								10,000,000
Current Yield								3.351%
Annual Dividend Rate per Share (in Canadian dollars per share) | $ / shares								$ 0.83775
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25
Carrying Value December 31 | $					244			$ 244	244
Series 11 | Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								2.96%
Series 13
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								0
Current Yield								0.00%
Annual Dividend Rate per Share (in Canadian dollars per share) | $ / shares							$ 0.34375	$ 0
Redemption Price Per Share (in Canadian dollars per share) | $ / shares	$ 25							$ 0
Carrying Value December 31 | $					493				493
Stock redeemed during period (in shares) | shares	20,000,000
Series 15
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) | shares								40,000,000
Current Yield								4.90%
Annual Dividend Rate per Share (in Canadian dollars per share) | $ / shares								$ 1.225
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25
Carrying Value December 31 | $					$ 988			$ 988	$ 988
Series 15 | Government of Canada, Five-Year Bond Yield
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								3.85%
Preferred stock, fixed percentage added To Bond Or Treasury Bill rate for calculating dividend yield, minimum								4.90%
Even numbered series of preferred shares
Preferred Shares [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
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								2.38%
Series 10 | Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								2.35%
Series 12 | Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								2.96%
Series 16 | Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum								3.85%
Odd numbered series of preferred shares
Preferred Shares [Line Items]
Period of time preferred stock or bond is considered for dividend yield calculation								5 years
Series 2 and Series 4 and Series 6
Preferred Shares [Line Items]
Redemption Price Per Share (in Canadian dollars per share) | $ / shares								$ 25.50

OTHER COMPREHENSIVE INCOME _ _3

OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Components (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Before Tax Amount
Other Comprehensive Income (Loss)	$ 894	$ (1,056)	$ (1,055)
Income Tax Recovery/(Expense)
Other Comprehensive Income (Loss)	(252)	138	3
Net of Tax Amount
Other comprehensive income/(loss) (Note 24)	642	(918)	(1,052)
Foreign currency translation gains and losses on net investment in foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(100)	(647)	(914)
Reclassification from accumulated other comprehensive Income (loss)			(13)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	(8)	38	(30)
Reclassification from AOCI			0
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(108)	(609)	(944)
Reclassification from accumulated other comprehensive income (loss)			(13)
Change in fair value of net investment hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(3)	48	46
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	1	(12)	(11)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(2)	36	35
Change in fair value and reclassification of gains and losses of cash flow hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(13)	(771)	(78)
Reclassification from accumulated other comprehensive Income (loss)	68	649	19
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	3	188	16
Reclassification from AOCI	(13)	(160)	(5)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(10)	(583)	(62)
Reclassification from accumulated other comprehensive income (loss)	55	489	14
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	208	15	(15)
Reclassification from accumulated other comprehensive Income (loss)	20	23	14
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	(50)	(3)	5
Reclassification from AOCI	(6)	(6)	(4)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	158	12	(10)
Reclassification from accumulated other comprehensive income (loss)	14	17	10
Other comprehensive income on equity investments
Before Tax Amount
Other Comprehensive Income (Loss)	714	(373)	(114)
Income Tax Recovery/(Expense)
Other Comprehensive Income (Loss)	(179)	93	32
Net of Tax Amount
Other comprehensive income/(loss) (Note 24)	$ 535	$ (280)	$ (82)

OTHER COMPREHENSIVE INCOME _ _4

OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reconciliation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	$ 33,080	$ 32,397
Other comprehensive income/(loss) (Note 24)	642	(918)	$ (1,052)
Balance at end of year	33,396	33,080	32,397
Cash flow hedge loss to be reclassified within twelve months	(62)
Cash flow hedge loss to be reclassified within twelve months, net of tax	(47)
Currency Translation Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(1,273)	(730)	107
Other comprehensive (loss) / income, before reclassifications	(98)	(543)	(824)
Amounts reclassified from AOCI	0	0	(13)
Other comprehensive income/(loss) (Note 24)	(98)	(543)	(837)
Acquisition of TC Pipelines, LP	362
Balance at end of year	(1,009)	(1,273)	(730)
Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(143)	(58)	(23)
Other comprehensive (loss) / income, before reclassifications	(11)	(567)	(49)
Amounts reclassified from AOCI	55	482	14
Other comprehensive income/(loss) (Note 24)	44	(85)	(35)
Acquisition of TC Pipelines, LP	(13)
Balance at end of year	(112)	(143)	(58)
Pension and Other Post-Retirement Benefit Plan Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(285)	(314)	(314)
Other comprehensive (loss) / income, before reclassifications	158	12	(10)
Amounts reclassified from AOCI	14	17	10
Other comprehensive income/(loss) (Note 24)	172	29	0
Acquisition of TC Pipelines, LP	0
Balance at end of year	(113)	(285)	(314)
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(738)	(457)	(376)
Other comprehensive (loss) / income, before reclassifications	506	(292)	(86)
Amounts reclassified from AOCI	28	11	5
Other comprehensive income/(loss) (Note 24)	534	(281)	(81)
Acquisition of TC Pipelines, LP	4
Balance at end of year	(200)	(738)	(457)
Accumulated Other Comprehensive Loss (Note 24)
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(2,439)	(1,559)	(606)
Other comprehensive (loss) / income, before reclassifications	555	(1,390)	(969)
Amounts reclassified from AOCI	97	510	16
Other comprehensive income/(loss) (Note 24)	652	(880)	(953)
Acquisition of TC Pipelines, LP	353
Balance at end of year	(1,434)	(2,439)	(1,559)
Accumulated foreign currency adjustment attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive (loss) / income, before reclassifications	(12)	(30)	(85)
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	1	(16)	(13)
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	$ 1	$ 1	$ (1)

OTHER COMPREHENSIVE INCOME _ _5

OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reclassifications (Details) - CAD ($) $ in Millions	May 22, 2020	May 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Storage)			$ 13,387	$ 12,999	$ 13,255
Interest expense			(2,360)	(2,228)	(2,333)
Net gain/(loss) on assets sold/held for sale			30	(50)	(121)
Total before tax			2,166	5,107	5,187
Income tax (recovery) expense			(120)	(194)	(754)
Net Income Attributable to Common Shares			1,815	4,457	3,976
Plant operating costs and other			4,098	3,878	3,913
Income from equity investments			898	1,019	920
Reclassification to net income of gains and losses on cash flow hedges			(55)	$ (489)	(14)
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	65.00%	65.00%		65.00%
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			(68)	(642)	(19)
Income tax (recovery) expense			13	160	5
Net Income Attributable to Common Shares			(55)	(482)	(14)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges | Interest rate
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense			(46)	(28)	(12)
Net gain/(loss) on assets sold/held for sale			0	(613)	0
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			(20)	(23)	(14)
Income tax (recovery) expense			6	6	4
Net Income Attributable to Common Shares			(14)	(17)	(10)
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			(22)	(23)	(14)
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	0	0
Amounts Reclassified From Accumulated Other Comprehensive Loss | Equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax (recovery) expense			9	4	3
Net Income Attributable to Common Shares			(28)	(11)	(5)
Income from equity investments			(37)	(15)	(8)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Currency translation adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net gain/(loss) on assets sold/held for sale			0	0	13
Income tax (recovery) expense			0	0	0
Net Income Attributable to Common Shares			0	0	13
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	7	0
Power and Storage | Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges | Commodities
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Storage)			$ (22)	$ (1)	$ (7)

EMPLOYEE POST-RETIREMENT BENE_3

EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments, Changes and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized		11 years	11 years	11 years
Expense for savings plan and DC Plans		$ 58	$ 58	$ 61
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Savings and DC Plans		58	58	61
Total cash contributions		171	191	$ 205
Gain (loss) due to settlement		(81)
Net periodic benefit cost, settlement charge		18
Change in Plan Assets
Plan assets at fair value – beginning of year	$ 4,479	4,479
Plan assets at fair value – end of year		4,576	4,479
Amounts recognized in the Balance Sheet
Other long-term assets (Note 14)		312	207
Other long-term liabilities (Note 17)		$ (174)	$ (503)
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		10 years	9 years	9 years
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans		$ 105	$ 124	$ 122
Total amount outstanding under letters of credit		20	13
Settlement gain (loss), before tax		(2)	0	0
Curtailment gain		5	0	0
Change in Benefit Obligation
Benefit obligation – beginning of year	4,326	4,326	4,058
Service cost		171	155	126
Interest cost		119	133	142
Employee contributions		6	6
Benefits paid		(372)	(249)
Actuarial (gain)/loss		(208)	242
Curtailment		(5)	0
Foreign exchange rate changes		(10)	(19)
Benefit obligation – end of year		4,027	4,326	4,058
Change in Plan Assets
Plan assets at fair value – beginning of year	4,038	4,038	3,693
Actual return on plan assets		376	485
Employer contributions		105	124
Employee contributions		6	6
Benefits paid		(372)	(249)
Foreign exchange rate changes		(8)	(21)
Plan assets at fair value – end of year		4,145	4,038	3,693
Funded Status – Plan Surplus/(Deficit)		$ 118	$ (288)
Discount rate		3.05%	2.70%
Amounts recognized in the Balance Sheet
Other long-term assets (Note 14)		$ 119	$ 29
Accounts payable and other		0	0
Other long-term liabilities (Note 17)		(1)	(317)
Net		118	(288)
Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans		8	9	22
Settlement gain (loss), before tax		0	0	0
Curtailment gain		0	0	0
Change in Benefit Obligation
Benefit obligation – beginning of year	457	457	427
Service cost		6	6	5
Interest cost		12	14	17
Employee contributions		1	0
Benefits paid		(21)	(21)
Actuarial (gain)/loss		(35)	36
Curtailment		3	0
Foreign exchange rate changes		(4)	(5)
Benefit obligation – end of year		419	457	427
Change in Plan Assets
Plan assets at fair value – beginning of year	441	441	406
Actual return on plan assets		5	56
Employer contributions		8	9
Employee contributions		1	0
Benefits paid		(21)	(21)
Foreign exchange rate changes		(3)	(9)
Plan assets at fair value – end of year		431	441	406
Funded Status – Plan Surplus/(Deficit)		$ 12	$ (16)
Discount rate		3.10%	2.75%
Amounts recognized in the Balance Sheet
Other long-term assets (Note 14)		$ 193	$ 178
Accounts payable and other		(8)	(8)
Other long-term liabilities (Note 17)		(173)	(186)
Net		12	(16)
Canadian | Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Letter of credit to the DB Plan		20	$ 13	$ 12
Total amount outstanding under letters of credit		$ 322
U.S. | Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Settlement gain (loss), before tax	2
Curtailment gain	5
U.S. | Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Settlement gain (loss), before tax	3
Curtailment gain	$ 3

EMPLOYEE POST-RETIREMENT BENE_4

EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Benefit obligation and fair value of plan assets for plans that are not fully funded
Plan assets at fair value	$ 4,576	$ 4,479
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Pension Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	$ (4,027)	$ (4,326)	$ (4,058)
Plan assets at fair value	4,145	4,038	3,693
Funded Status – Plan Surplus/(Deficit)	118	(288)
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(3,714)	(3,957)
Plan assets at fair value	4,145	4,038
Funded Status – Plan Surplus	$ 431	$ 81
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Pension Benefit Plans | Debt securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	34.00%	33.00%
Company debt or common shares included in plan assets, amount	$ 7	$ 13
Company debt or common shares included in plan assets, percentage	0.20%	0.30%
Pension Benefit Plans | Debt securities | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	25.00%
Pension Benefit Plans | Debt securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	0.45%
Pension Benefit Plans | Equity securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	53.00%	57.00%
Company debt or common shares included in plan assets, amount	$ 5	$ 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	0.35%
Pension Benefit Plans | Equity securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	0.65%
Pension Benefit Plans | Alternatives
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	13.00%	10.00%
Pension Benefit Plans | Alternatives | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	0.10%
Pension Benefit Plans | Alternatives | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	0.20%
Pension Benefit Plans | Not fully funded
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	$ (2,687)	$ (3,292)
Plan assets at fair value	2,686	2,975
Funded Status – Plan Surplus/(Deficit)	(1)	(317)
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	(419)	(457)	(427)
Plan assets at fair value	431	441	$ 406
Funded Status – Plan Surplus/(Deficit)	12	(16)
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	(183)	(194)
Plan assets at fair value	0	0
Funded Status – Plan Surplus/(Deficit)	$ (183)	$ (194)

EMPLOYEE POST-RETIREMENT BENE_5

EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Employee post-retirement benefits
Fair value of plan assets	$ 4,576	$ 4,479
Percentage of Total Portfolio	100.00%	100.00%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 1,946	$ 1,938
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	2,065	2,124
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	565	417	$ 379
Cash and Cash Equivalents
Employee post-retirement benefits
Fair value of plan assets	$ 70	$ 87
Percentage of Total Portfolio	2.00%	2.00%
Cash and Cash Equivalents | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 68	$ 87
Cash and Cash Equivalents | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	2	0
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	$ 417	$ 453
Percentage of Total Portfolio	9.00%	10.00%
Equity Securities, Canadian | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 269	$ 276
Equity Securities, Canadian | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	148	177
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	$ 813	$ 805
Percentage of Total Portfolio	18.00%	18.00%
Equity Securities, U.S. | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 649	$ 594
Equity Securities, U.S. | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	164	211
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	$ 480	$ 494
Percentage of Total Portfolio	10.00%	11.00%
Equity Securities, International | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 126	$ 114
Equity Securities, International | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	354	380
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	$ 424	$ 484
Percentage of Total Portfolio	9.00%	11.00%
Equity Securities, Global | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 111	$ 116
Equity Securities, Global | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	313	368
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	$ 145	$ 160
Percentage of Total Portfolio	3.00%	4.00%
Equity Securities, Emerging | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 25	$ 35
Equity Securities, Emerging | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	120	125
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	$ 226	$ 207
Percentage of Total Portfolio	5.00%	5.00%
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	226	207
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	$ 331	$ 283
Percentage of Total Portfolio	7.00%	6.00%
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	331	283
Fixed Income Securities, Canadian Bonds, Provincial | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Municipal
Employee post-retirement benefits
Fair value of plan assets	$ 16	$ 13
Percentage of Total Portfolio	0.00%	0.00%
Fixed Income Securities, Canadian Bonds, Municipal | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, Canadian Bonds, Municipal | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	16	13
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	$ 147	$ 151
Percentage of Total Portfolio	4.00%	3.00%
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	147	151
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	$ 448	$ 458
Percentage of Total Portfolio	10.00%	10.00%
Fixed Income Securities, U.S. Bonds, Federal | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 433	$ 444
Fixed Income Securities, U.S. Bonds, Federal | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	15	14
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	$ 2
Percentage of Total Portfolio	0.00%	0.00%
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	2
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	$ 210	$ 215
Percentage of Total Portfolio	5.00%	5.00%
Fixed Income Securities, U.S. Bonds, Corporate | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 67	$ 72
Fixed Income Securities, U.S. Bonds, Corporate | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	143	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	$ 13	$ 14
Percentage of Total Portfolio	0.00%	0.00%
Fixed Income Securities, International, Government | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 6	$ 8
Fixed Income Securities, International, Government | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	7	6
Fixed Income Securities, International, Government | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, International, Corporate
Employee post-retirement benefits
Fair value of plan assets	$ 73	$ 48
Percentage of Total Portfolio	2.00%	1.00%
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	73	48
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	$ 47	$ 51
Percentage of Total Portfolio	1.00%	1.00%
Fixed Income Securities, International, Mortgage-backed | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 42	$ 47
Fixed Income Securities, International, Mortgage-backed | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	5	4
Fixed Income Securities, International, Mortgage-backed | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Real estate
Employee post-retirement benefits
Fair value of plan assets	$ 283	$ 213
Percentage of Total Portfolio	6.00%	5.00%
Real estate | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Real estate | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Real estate | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	283	213
Infrastructure
Employee post-retirement benefits
Fair value of plan assets	$ 281	$ 203
Percentage of Total Portfolio	6.00%	5.00%
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	281	203
Private equity funds
Employee post-retirement benefits
Fair value of plan assets	$ 1	$ 1
Percentage of Total Portfolio	0.00%	0.00%
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	1	1
Derivatives
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ (8)
Percentage of Total Portfolio	0.00%	0.00%
Derivatives | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Derivatives | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	(8)
Derivatives | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Funds held on deposit
Employee post-retirement benefits
Fair value of plan assets	$ 150	$ 145
Percentage of Total Portfolio	3.00%	3.00%
Funds held on deposit | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 150	$ 145
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, 2021	Dec. 31, 2020
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	$ 4,479
Plan assets at fair value – end of year	4,576	$ 4,479
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	417	379
Purchases and sales	100	42
Realized and unrealized losses	48	(4)
Plan assets at fair value – end of year	$ 565	$ 417

EMPLOYEE POST-RETIREMENT BENE_7

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for savings plan and DC Plans	$ 55
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits	5.60%
Percentage level to which average annual rate was assumed to decrease	5.00%
Pension Benefit Plans
DB Plans
Company's expected funding contributions	$ 76
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	20
Estimated future benefit payments, which reflect expected future service
2022	208
2023	211
2024	216
2025	220
2026	224
2027 to 2031	$ 1,171
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	3.05%	2.70%
Rate of compensation increase	2.95%	2.60%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	2.70%	3.20%	3.90%
Expected long-term rate of return on plan assets	6.15%	6.40%	6.60%
Rate of compensation increase	2.60%	3.00%	3.00%
Net benefit cost
Service cost	$ 171	$ 155	$ 126
Other components of net benefit cost
Interest cost	119	133	142
Expected return on plan assets	(234)	(230)	(222)
Amortization of actuarial loss	23	21	12
Amortization of regulatory asset	27	25	14
Curtailment gain	(5)	0	0
Settlement gain – AOCI	(2)	0	0
Other components of net benefit cost	(72)	(51)	(54)
Net Benefit Cost Recognized	99	104	72
Pre-tax amounts recognized in AOCI
Net loss	147	358	398
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to net income	(23)	(21)	(12)
Curtailment	0	0	0
Settlement	2	0	0
Funded status adjustment	(190)	(18)	52
Total pre-tax amounts recognized in OCI	(211)	$ (39)	$ 40
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	7
Estimated future benefit payments, which reflect expected future service
2022	25
2023	25
2024	24
2025	24
2026	24
2027 to 2031	$ 114
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	3.10%	2.75%
Rate of compensation increase	0.00%	0.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	2.80%	3.35%	4.10%
Expected long-term rate of return on plan assets	3.00%	3.50%	4.30%
Rate of compensation increase	0.00%	0.00%	0.00%
Net benefit cost
Service cost	$ 6	$ 6	$ 5
Other components of net benefit cost
Interest cost	12	14	17
Expected return on plan assets	(13)	(14)	(15)
Amortization of actuarial loss	2	2	2
Amortization of regulatory asset	2	2	2
Curtailment gain	0	0	0
Settlement gain – AOCI	0	0	0
Other components of net benefit cost	3	4	6
Net Benefit Cost Recognized	9	10	11
Pre-tax amounts recognized in AOCI
Net loss	5	22	20
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to net income	(2)	(2)	(2)
Curtailment	3	0	0
Settlement	0	0	0
Funded status adjustment	(18)	3	(37)
Total pre-tax amounts recognized in OCI	$ (17)	$ 1	$ (39)

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, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)
Derivative [Line Items]
Fair Value	$ (51)	$ 145
Designated as a net investment hedge
Derivative [Line Items]
Fair Value	19	68
Designated as a net investment hedge | US$ denominated
Derivative [Line Items]
Notional Amount			$ 4,200	$ 2,600
Designated as a net investment hedge | U.S. dollar foreign exchange options (maturing 2022 to 2023)
Derivative [Line Items]
Fair Value	(4)	45
Designated as a net investment hedge | U.S. dollar foreign exchange options (maturing 2022 to 2023) | US$ denominated
Derivative [Line Items]
Notional Amount			3,800	2,200
Designated as a net investment hedge | U.S. dollar cross-currency interest rate swaps (maturing 2022 to 2025)
Derivative [Line Items]
Fair Value	23	23
Designated as a net investment hedge | U.S. dollar cross-currency interest rate swaps (maturing 2022 to 2025) | US$ denominated
Derivative [Line Items]
Notional Amount			$ 400	$ 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, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)
Derivative [Line Items]
Notional amount	$ 30,700		$ 27,700
Fair value	$ 35,500		$ 33,800
US$ denominated
Derivative [Line Items]
Notional amount		$ 24,200		$ 21,800
Fair value		$ 28,100		$ 26,500

RISK MANAGEMENT AND FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	$ (38,756)	$ (36,956)
Junior subordinated notes (Note 20)	(8,939)	(8,498)
Level II | Carrying Amount
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	(38,661)	(36,885)
Junior subordinated notes (Note 20)	(8,939)	(8,498)
Total liabilities	(47,600)	(45,383)
Level II | Fair Value
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	(45,615)	(46,054)
Junior subordinated notes (Note 20)	(9,236)	(8,908)
Total liabilities	$ (54,851)	$ (54,962)

RISK MANAGEMENT AND FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Total Derivatives
Derivative Assets	$ 217	$ 276
Derivative Liabilities	(268)	(131)
Total Derivatives	(51)	145
Loss on settlement of financial instruments (Note 26)	(10)	(130)	$ 0
Total trading activity
Total Derivatives
Derivative Assets	173	207
Derivative Liabilities	(200)	(46)
Total Derivatives	(27)	161
Cash Flow Hedges
Total Derivatives
Derivative Assets	2	0
Derivative Liabilities	(45)	(84)
Total Derivatives	(43)	(84)
Net Investment Hedges
Total Derivatives
Derivative Assets	42	69
Derivative Liabilities	(23)	(1)
Total Derivatives	19	68
Other current assets
Total Derivatives
Derivative Assets	169	235
Other current assets | Total trading activity
Total Derivatives
Derivative Assets	159	188
Other current assets | Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets | Net Investment Hedges
Total Derivatives
Derivative Assets	10	47
Other current assets | Commodities
Total Derivatives
Derivative Assets	122	13
Other current assets | Commodities | Commodities
Total Derivatives
Derivative Assets	122	13
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	47	222
Other current assets | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Assets	37	175
Other current assets | Foreign exchange | Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets | Foreign exchange | Net Investment Hedges
Total Derivatives
Derivative Assets	10	47
Other long-term assets
Total Derivatives
Derivative Assets	48	41
Other long-term assets | Total trading activity
Total Derivatives
Derivative Assets	14	19
Other long-term assets | Cash Flow Hedges
Total Derivatives
Derivative Assets	2	0
Other long-term assets | Net Investment Hedges
Total Derivatives
Derivative Assets	32	22
Other long-term assets | Commodities
Total Derivatives
Derivative Assets	8
Other long-term assets | Commodities | Commodities
Total Derivatives
Derivative Assets	8
Other long-term assets | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Assets	0
Other long-term assets | Commodities | Net Investment Hedges
Total Derivatives
Derivative Assets	0
Other long-term assets | Foreign exchange
Total Derivatives
Derivative Assets	38	41
Other long-term assets | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Assets	6	19
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	32	22
Other long-term assets | Interest rate
Total Derivatives
Derivative Assets	2
Other long-term assets | Interest rate | Interest rate
Total Derivatives
Derivative Assets	0
Other long-term assets | Interest rate | Cash Flow Hedges
Total Derivatives
Derivative Assets	2
Other long-term assets | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Assets	0
Accounts payable and other
Total Derivatives
Derivative Liabilities	(221)	(72)
Accounts payable and other | Total trading activity
Total Derivatives
Derivative Liabilities	(184)	(42)
Accounts payable and other | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(33)	(29)
Accounts payable and other | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(4)	(1)
Accounts payable and other | Commodities
Total Derivatives
Derivative Liabilities	(161)	(40)
Accounts payable and other | Commodities | Commodities
Total Derivatives
Derivative Liabilities	(138)	(32)
Accounts payable and other | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(23)	(8)
Accounts payable and other | Commodities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other | Foreign exchange
Total Derivatives
Derivative Liabilities	(50)	(11)
Accounts payable and other | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Liabilities	(46)	(10)
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	(4)	(1)
Accounts payable and other | Interest rate
Total Derivatives
Derivative Liabilities	(10)	(21)
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	(10)	(21)
Accounts payable and other | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities
Total Derivatives
Derivative Liabilities	(47)	(59)
Other long-term liabilities | Total trading activity
Total Derivatives
Derivative Liabilities	(16)	(4)
Other long-term liabilities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(12)	(55)
Other long-term liabilities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(19)	0
Other long-term liabilities | Commodities
Total Derivatives
Derivative Liabilities	(10)	(10)
Other long-term liabilities | Commodities | Commodities
Total Derivatives
Derivative Liabilities	(6)	(4)
Other long-term liabilities | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(4)	(6)
Other long-term liabilities | Commodities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities | Foreign exchange
Total Derivatives
Derivative Liabilities	(29)
Other long-term liabilities | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Liabilities	(10)
Other long-term liabilities | Foreign exchange | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0
Other long-term liabilities | Foreign exchange | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(19)
Other long-term liabilities | Interest rate
Total Derivatives
Derivative Liabilities	(8)	(49)
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	(8)	(49)
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	817	736
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains/(losses)	45	130	32
Net realized gains	3	20	60
Other Restricted Investments
Fair value
Fair value of equity securities	0	0
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains/(losses)	(2)	1	3
Net realized gains	0	1	$ 0
Fixed income securities | LMCI Restricted Investments
Fair value
Maturing within 1 year	0	0
Maturing within 1-5 years	8	0
Maturing within 5-10 years	1,150	985
Maturing after 10 years	84	85
Fair value of securities	2,059	1,806
Fixed income securities | Other Restricted Investments
Fair value
Maturing within 1 year	26	17
Maturing within 1-5 years	107	66
Maturing within 5-10 years	0	0
Maturing after 10 years	0	0
Fair value of securities	$ 133	$ 83

RISK MANAGEMENT AND FINANCIAL_7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional and Maturity Summary (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)GWhBcfMMBbls	Dec. 31, 2020USD ($)GWhMMBblsBcf	Dec. 31, 2021MXN ($)	Dec. 31, 2020MXN ($)
Commodities | Power | Purchases
Derivative [Line Items]
Notional amount, energy (gwh) | GWh	553	185
Commodities | Power | Sales
Derivative [Line Items]
Notional amount, energy (gwh) | GWh	1,043	1,786
Commodities | Natural Gas | Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | Bcf	104	13
Commodities | Natural Gas | Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | Bcf	52	14
Commodities | Liquids | Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | MMBbls	34	26
Commodities | Liquids | Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | MMBbls	38	30
Foreign exchange
Derivative [Line Items]
Notional amount	$ 6,636	$ 4,432	$ 5,500	$ 1,700
Interest rate
Derivative [Line Items]
Notional amount	$ 650	$ 1,100	$ 0	$ 0

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses) / Gains on Derivative Instruments (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative [Line Items]
Gain (loss) on cash flow hedge	$ 0	$ 0	$ 0
Commodities
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	9,000,000	(23,000,000)	(111,000,000)
Amount of realized gains/(losses) in the year	287,000,000	183,000,000	378,000,000
Commodities | Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	(44,000,000)	6,000,000	(6,000,000)
Foreign exchange
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	(203,000,000)	126,000,000	245,000,000
Amount of realized gains/(losses) in the year	240,000,000	(33,000,000)	(70,000,000)
Interest rate | Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	$ (32,000,000)	$ (16,000,000)	$ 2,000,000

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ (13)	$ (771)	$ (78)
Commodities
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	(35)	(5)	(15)
Interest rate
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ 22	$ (766)	$ (63)

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Effect of Fair Value and Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions	May 22, 2020	May 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disposal group, disposed of by sale, not discontinued operations | Coastal GasLink
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Ownership interest sold	65.00%	65.00%		65.00%
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Change in fair value of derivative instruments recognized in OCI		$ (613)		$ (613)
Interest Expense | Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged items			$ 0	(3)	$ (19)
Derivatives designated as hedging instruments			0	1	1
Reclassification of gains/(losses) on derivative instruments from AOCI to net income			(46)	(648)	(12)
Revenue | Commodity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification of gains/(losses) on derivative instruments from AOCI to net income			$ (22)	$ (1)	$ (7)

RISK MANAGEMENT AND FINANCIA_11

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD ($)	Dec. 31, 2021	Dec. 31, 2020
Derivative instrument assets
Gross Derivative Instruments	$ 217,000,000	$ 276,000,000
Amounts Available for Offset	(146,000,000)	(18,000,000)
Net Amounts	71,000,000	258,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(268,000,000)	(131,000,000)
Amounts Available for Offset	146,000,000	18,000,000
Net Amounts	(122,000,000)	(113,000,000)
Cash collateral provided by the Company	144,000,000	54,000,000
Letters of credit provided by the Company	130,000,000	15,000,000
Cash collateral received by the Company	0	0
Letters of credit received by the Company	6,000,000	0
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	5,000,000	4,000,000
Foreign exchange
Derivative instrument assets
Gross Derivative Instruments	85,000,000	263,000,000
Amounts Available for Offset	(54,000,000)	(11,000,000)
Net Amounts	31,000,000	252,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(79,000,000)	(11,000,000)
Amounts Available for Offset	54,000,000	11,000,000
Net Amounts	(25,000,000)	0
Interest rate
Derivative instrument assets
Gross Derivative Instruments	2,000,000
Amounts Available for Offset	(1,000,000)
Net Amounts	1,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(18,000,000)	(70,000,000)
Amounts Available for Offset	1,000,000	0
Net Amounts	(17,000,000)	(70,000,000)
Power | Commodities
Derivative instrument assets
Gross Derivative Instruments	130,000,000	13,000,000
Amounts Available for Offset	(91,000,000)	(7,000,000)
Net Amounts	39,000,000	6,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(171,000,000)	(50,000,000)
Amounts Available for Offset	91,000,000	7,000,000
Net Amounts	$ (80,000,000)	$ (43,000,000)

RISK MANAGEMENT AND FINANCIA_12

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value Hierarchy
Derivative instrument assets	$ 217	$ 276
Derivative instrument liabilities	(268)	(131)
Recurring basis
Fair Value Hierarchy
Assets and (liabilities), net	(51)	145
Recurring basis | Commodities | Power
Fair Value Hierarchy
Derivative instrument assets	130	13
Derivative instrument liabilities	(171)	(50)
Recurring basis | Foreign exchange
Fair Value Hierarchy
Derivative instrument assets	85	263
Derivative instrument liabilities	(79)	(11)
Recurring basis | Interest rate
Fair Value Hierarchy
Derivative instrument assets	2
Derivative instrument liabilities	(18)	(70)
Recurring basis | Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	(10)	(12)
Recurring basis | Quoted Prices in Active Markets (Level I) | Commodities | Power
Fair Value Hierarchy
Derivative instrument assets	39	3
Derivative instrument liabilities	(49)	(15)
Recurring basis | Quoted Prices in Active Markets (Level I) | Foreign exchange
Fair Value Hierarchy
Derivative instrument assets	0	0
Derivative instrument liabilities	0	0
Recurring basis | Quoted Prices in Active Markets (Level I) | Interest rate
Fair Value Hierarchy
Derivative instrument assets	0
Derivative instrument liabilities	0	0
Recurring basis | Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Assets and (liabilities), net	(35)	161
Recurring basis | Significant Other Observable Inputs (Level II) | Commodities | Power
Fair Value Hierarchy
Derivative instrument assets	91	10
Derivative instrument liabilities	(116)	(31)
Recurring basis | Significant Other Observable Inputs (Level II) | Foreign exchange
Fair Value Hierarchy
Derivative instrument assets	85	263
Derivative instrument liabilities	(79)	(11)
Recurring basis | Significant Other Observable Inputs (Level II) | Interest rate
Fair Value Hierarchy
Derivative instrument assets	2
Derivative instrument liabilities	(18)	(70)
Recurring basis | Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	(6)	(4)
Recurring basis | Significant Unobservable Inputs (Level III) | Commodities | Power
Fair Value Hierarchy
Derivative instrument assets	0	0
Derivative instrument liabilities	(6)	(4)
Recurring basis | Significant Unobservable Inputs (Level III) | Foreign exchange
Fair Value Hierarchy
Derivative instrument assets	0	0
Derivative instrument liabilities	0	0
Recurring basis | Significant Unobservable Inputs (Level III) | Interest rate
Fair Value Hierarchy
Derivative instrument assets	0
Derivative instrument liabilities	$ 0	$ 0

RISK MANAGEMENT AND FINANCIA_13

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, 2021	Dec. 31, 2020
Revenue
Net change in the Level III fair value category
Unrealized gains (losses) attributed to derivatives in the Level III category	$ (3)	$ 3
Commodity contracts | Power
Net change in the Level III fair value category
Balance at beginning of year	(4)	(7)
Total (losses)/gains included in Net income	(3)	3
Settlements	1	0
Balance at end of year	$ (6)	$ (4)

CHANGES IN OPERATING WORKING _3

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
CHANGES IN OPERATING WORKING CAPITAL
(Increase)/decrease in Accounts receivable	$ (925)	$ 129	$ 31
Increase in Inventories	(93)	(55)	(42)
Increase in Other current assets	(141)	(221)	(15)
Increase/(decrease) in Accounts payable and other	890	(162)	352
Decrease in Accrued interest	(18)	(18)	(33)
(Increase)/Decrease in Operating Working Capital	$ (287)	$ (327)	$ 293

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Details) $ / shares in Units, $ in Millions, $ in Millions

Nov. 30, 2021CAD ($)

May 22, 2020

Jun. 30, 2019CAD ($)

Nov. 30, 2021CAD ($)

Nov. 30, 2020USD ($)

May 31, 2020CAD ($)

Apr. 30, 2020CAD ($)

Oct. 31, 2019CAD ($)

Oct. 31, 2019USD ($)$ / shares

Aug. 31, 2019CAD ($)

Aug. 31, 2019USD ($)

Jul. 31, 2019CAD ($)

May 31, 2019CAD ($)

Dec. 31, 2021CAD ($)

Dec. 31, 2020CAD ($)

Dec. 31, 2019CAD ($)

Dec. 31, 2020CAD ($)

Nov. 13, 2020

May 31, 2019USD ($)

Business Acquisition [Line Items]

Net gain/(loss) on assets sold/held for sale

$ 30

$ (50)

$ (121)

Proceeds from sale of assets, net of transaction costs

35

3,407

2,398

Goodwill

12,582

12,679

$ 12,679

Income tax expense

120

194

754

Payments for unredeemed shares

$ 373

$ 284

$ 0

0

$ 373

Columbia Pipeline Partners | Equity Attributable to Non-Controlling Interests

Business Acquisition [Line Items]

Decrease from redemption or purchase of interests (in dollars per share) | $ / shares

$ 25.50

Senior Secured Credit Facilities due April 2027

Business Acquisition [Line Items]

Proceeds from issuance of debt

$ 1,500

TransCanada Turbines | TransCanada Turbines

Business Acquisition [Line Items]

Business acquisition, percentage of voting interests acquired

50.00%

Coastal GasLink | Canadian Natural Gas Pipelines

Business Acquisition [Line Items]

Ownership interest percentage

35.00%

35.00%

Columbia Midstream assets

Business Acquisition [Line Items]

Proceeds from sale of assets, net of transaction costs

$ 1,300

Gain (loss) on disposition of property plant equipment

$ 21

Gain (loss) on disposition of property plant equipment, net of tax

152

Gain (loss) on disposition of property plant and equipment foreign currency translation amount

4

Goodwill

$ 595

Columbia Midstream assets | 2019

Business Acquisition [Line Items]

Income tax expense

$ (18)

Northern Courier | Liquids Pipelines

Business Acquisition [Line Items]

Ownership interest sold

15.00%

Ownership interest percentage

15.00%

TransCanada Turbines | TransCanada Turbines

Business Acquisition [Line Items]

Ownership interest percentage

50.00%

Business combination, consideration transferred

$ 67

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

Business Acquisition [Line Items]

Ownership interest sold

65.00%

65.00%

65.00%

Total consideration

$ 656

Net gain/(loss) on assets sold/held for sale

364

Gain (loss) on sale, net of tax

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

15.00%

85.00%

Total consideration

$ 35

$ 35

$ 144

Net gain/(loss) on assets sold/held for sale

13

69

Gain (loss) on sale, net of tax

$ 19

115

Disposal group, disposed of by sale, not discontinued operations | Portlands Energy Centre

Business Acquisition [Line Items]

Ownership interest sold

50.00%

Disposal group, disposed of by sale, not discontinued operations | Halton Hills, Napanee and Portlands Energy Centre

Business Acquisition [Line Items]

Total consideration

$ 2,800

Net gain/(loss) on assets sold/held for sale

(676)

Gain (loss) on sale, net of tax

$ (470)

Disposal group, disposed of by sale, not discontinued operations | SRP

Business Acquisition [Line Items]

Total consideration

$ 448

Net gain/(loss) on assets sold/held for sale

$ 68

Gain (loss) on sale, net of tax

54

Foreign currency translation gain

$ 9

Coastal GasLink | Senior Secured Credit Facilities due April 2027

Business Acquisition [Line Items]

Proceeds from issuance of debt

$ 1,603

Northern Courier | Senior Secured Notes due June 2042

Business Acquisition [Line Items]

Proceeds from issuance of debt

$ 1,000

$ 1,000

COMMITMENTS, CONTINGENCIES AN_3

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Narrative (Details) $ in Millions, $ in Billions	Nov. 22, 2021USD ($)	Nov. 30, 2021	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)
Other Commitments
Purchase commitment			$ 239	$ 224	$ 236
Purchase commitment percentage			1
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites			$ 30	$ 24
Damages sought	$ 15
Capital expenditures | Minimum
Other Commitments
Purchase commitment, period			8 years
Capital expenditures | Maximum
Other Commitments
Purchase commitment, period			15 years
Canadian Natural Gas Pipelines | Capital expenditures
Other Commitments
Purchase commitment			$ 1,500
U.S. Natural Gas Pipelines | Capital expenditures
Other Commitments
Purchase commitment			100
Mexico Natural Gas Pipelines | Capital expenditures
Other Commitments
Purchase commitment			100
Liquids Pipelines | Northern Courier
Guarantees [Abstract]
Ownership interest sold		15.00%
Liquids Pipelines | Capital expenditures
Other Commitments
Purchase commitment			100
Power and Storage | Capital expenditures
Other Commitments
Purchase commitment			$ 100

COMMITMENTS, CONTINGENCIES AN_4

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - CAD ($) $ in Millions	1 Months Ended
	Nov. 30, 2021	Dec. 31, 2021	Dec. 31, 2020
Northern Courier | Liquids Pipelines
Guarantees
Ownership interest sold	15.00%
Contingent financial obligation
Guarantees
Potential Exposure		$ 261	$ 566
Carrying Value		4	30
Contingent financial obligation | Sur de Texas
Guarantees
Potential Exposure		93	100
Carrying Value		0	0
Contingent financial obligation | Bruce Power
Guarantees
Potential Exposure		88	88
Carrying Value		0	0
Contingent financial obligation | Other jointly-owned entities
Guarantees
Potential Exposure		80	78
Carrying Value		4	4
Contingent financial obligation | Northern Courier
Guarantees
Potential Exposure		0	300
Carrying Value		$ 0	$ 26

VARIABLE INTEREST ENTITIES - Na

VARIABLE INTEREST ENTITIES - Narrative (Details)	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable interest entity ownership percentage	100.00%

VARIABLE INTEREST ENTITIES - As

VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 673	$ 1,530
Accounts receivable	3,092	2,162
Inventories	724	629
Other current assets	1,717	880
Total Current Assets	7,423	5,201
Plant, Property and Equipment	70,182	69,775
Equity Investments	8,441	6,677
Goodwill	12,582	12,679
Other Long-Term Assets	1,403	979
Total Assets	104,218	100,300
Current Liabilities
Accounts payable and other	5,099	3,816
Redeemable non-controlling interest	0	633
Accrued interest	577	595
Current portion of long-term debt	1,320	1,972
Total Current Liabilities	13,041	11,987
Total Regulatory Liabilities	4,300	4,148
Deferred Income Tax Liabilities	6,142	5,806
Total Liabilities	70,822	66,827
VIE, Primary Beneficiary
Current Assets
Cash and cash equivalents	72	254
Accounts receivable	70	61
Inventories	28	26
Other current assets	13	11
Total Current Assets	183	352
Plant, Property and Equipment	3,672	3,325
Equity Investments	890	714
Goodwill	421	424
Other Long-Term Assets	0	8
Total Assets	5,166	4,823
Current Liabilities
Accounts payable and other	232	109
Redeemable non-controlling interest	0	633
Accrued interest	17	21
Current portion of long-term debt	29	579
Total Current Liabilities	278	1,342
Total Regulatory Liabilities	66	60
Other Long-Term Liabilities	1	11
Deferred Income Tax Liabilities	13	12
Long-Term Debt	2,025	2,468
Total Liabilities	$ 2,383	$ 3,893

VARIABLE INTEREST ENTITIES - Ca

VARIABLE INTEREST ENTITIES - Carrying Value of Non-consolidated VIEs and Maximum Exposure (Details) - CAD ($) $ in Thousands	Dec. 31, 2021	Dec. 06, 2021	Dec. 31, 2020
Balance sheet
Loans receivable from affiliates (Note 11)	$ 1,217,000		$ 0
Equity Investments	8,441,000		6,677,000
Long-Term Loans Receivable from Affiliates (Note 11)	238,000		1,338,000
Off-balance sheet
Maximum exposure to loss	10,519,000		7,366,000
Coastal GasLink | Equity method investee
Balance sheet
Long-Term Loans Receivable from Affiliates (Note 11)	238,000
Subordinated Loan Agreement | Coastal GasLink | Subordinated Debt
Off-balance sheet
Debt instrument, face amount		$ 3,275,000
VIE, Not Primary Beneficiary
Balance sheet
Loans receivable from affiliates (Note 11)	1,000
Long-Term Loans Receivable from Affiliates (Note 11)	238,000		0
Bruce Power
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	974,000		1,183,000
Bruce Power | VIE, Not Primary Beneficiary
Balance sheet
Equity Investments	4,493,000		3,306,000
Pipeline Equity Investments And Other | VIE, Not Primary Beneficiary
Balance sheet
Equity Investments	1,605,000		1,371,000
Coastal GasLink
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	3,037,000		1,107,000
Pipeline equity investments
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	$ 171,000		$ 399,000