0001232384-21-000018 | 40-F | XBRL Viewer

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Cover Page	12 Months Ended
Cover Page	Dec. 31, 2020 shares
Entity Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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	940,064,042
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
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
TRANSCANADA PIPELINES LIMITED
Entity Information [Line Items]
Entity Registrant Name	TRANSCANADA PIPELINES LIMITED
Entity File Number	1-8887
Entity Tax Identification Number	52-2179728
Security Reporting Obligation	15(d)
Entity Common Stock, Shares Outstanding	902,108,711
Entity Central Index Key	0000099070
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
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

Consolidated statement of income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues	$ 12,999	$ 13,255	$ 13,679
Income from Equity Investments (Note 9)	1,019	920	714
Operating and Other Expenses
Plant operating costs and other	3,878	3,913	3,593
Commodity purchases resold		365	1,486
Property taxes	727	727	569
Depreciation and amortization	2,590	2,464	2,350
Goodwill and other asset impairment charges (Notes 7 and 12)	0	0	801
Total Operating and Other Expenses	7,195	7,469	8,799
Net (Loss)/ Gain on Assets Sold/Held for Sale (Note 27)	(50)	(121)	170
Financial Charges
Interest expense (Note 18)	2,228	2,333	2,265
Allowance for funds used during construction	(349)	(475)	(526)
Interest income and other	(213)	(460)	76
Total Financial Charges	1,666	1,398	1,815
Income before Income Taxes	5,107	5,187	3,949
Income Tax Expense (Note 17)
Current	252	699	315
Deferred	(58)	55	284
Deferred – U.S. Tax Reform and 2018 FERC Actions	0	0	(167)
Income Tax Expense	194	754	432
Net Income	4,913	4,433	3,517
Net income /(loss) attributable to non-controlling interests (Note 20)	297	293	(185)
Net Income Attributable to Controlling Interests	4,616	4,140	3,702
Preferred share dividends	159	164	163
Net Income Attributable to Common Shares	$ 4,457	$ 3,976	$ 3,539
Net Income per Common Share (Note 21)
Basic (in dollars per share)	$ 4.74	$ 4.28	$ 3.92
Diluted (in dollars per share)	4.74	4.27	3.92
Dividends Declared per Common Share (in dollars per share)	$ 3.24	$ 3.00	$ 2.76
Weighted Average Number of Common Shares (millions) (Note 21)
Basic (in shares)	940	929	902
Diluted (in shares)	940	931	903
Canadian Natural Gas Pipelines
Revenues	$ 4,469	$ 4,010	$ 4,038
U.S. Natural Gas Pipelines
Revenues	5,031	4,978	4,314
Mexico Natural Gas Pipelines
Revenues	716	603	619
Liquids Pipelines
Revenues	2,371	2,879	2,584
Power and Storage
Revenues	$ 412	$ 785	$ 2,124

Consolidated statement of comprehensive income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net Income	$ 4,913	$ 4,433	$ 3,517
Other Comprehensive (Loss)/ Income, Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations	(609)	(944)	1,358
Reclassification to net income of foreign currency translation gains on disposal of foreign operations	0	(13)	0
Change in fair value of net investment hedges	36	35	(42)
Change in fair value of cash flow hedges	(583)	(62)	(10)
Reclassification to net income of gains and losses on cash flow hedges	489	14	21
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	12	(10)	(114)
Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans	17	10	15
Other comprehensive (loss)/ income on equity investments	(280)	(82)	86
Other comprehensive (loss)/ income (Note 23)	(918)	(1,052)	1,314
Comprehensive Income	3,995	3,381	4,831
Comprehensive income /(loss) attributable to non-controlling interests	259	194	(13)
Comprehensive Income Attributable to Controlling Interests	3,736	3,187	4,844
Preferred share dividends	159	164	163
Comprehensive Income Attributable to Common Shares	$ 3,577	$ 3,023	$ 4,681

Consolidated statement of cash flows $ in Millions, $ in Millions	12 Months Ended			24 Months Ended
	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2020 CAD ($)
Cash Generated from Operations
Net income	$ 4,913	$ 4,433	$ 3,517
Depreciation and amortization	2,590	2,464	2,350
Goodwill and other asset impairment charges (Notes 7 and 12)	0	0	801
Deferred income taxes (Note 17)	(58)	55	284
Deferred income taxes – U.S. Tax Reform and 2018 FERC Actions (Note 17)	0	0	(167)
Income from equity investments (Note 9)	(1,019)	(920)	(714)
Distributions received from operating activities of equity investments (Note 9)	1,123	1,213	985
Employee post-retirement benefits funding, net of expense (Note 24)	(19)	(45)	(35)
Net loss/(gain) on assets sold/held for sale (Note 27)	50	121	(170)
Equity allowance for funds used during construction	(235)	(299)	(374)
Unrealized (gains)/ losses on financial instruments	(103)	(134)	220
Foreign exchange losses /(gains) on Loan receivable from affiliate (Note 10)	86	(53)	5
Other	57	(46)	(45)
(Increase)/ decrease in operating working capital (Note 26)	(327)	293	(102)
Net cash provided by operations	7,058	7,082	6,555
Investing Activities
Capital expenditures (Note 4)	(8,013)	(7,475)	(9,418)
Capital projects in development (Note 4)	(122)	(707)	(496)
Contributions to equity investments (Notes 4 and 9)	(765)	(602)	(1,015)
Proceeds from sales of assets, net of transaction costs	3,407	2,398	614
Acquisition	(88)	0	0
Reimbursement of costs related to capital projects in development (Note 13)	0	0	470
Other distributions from equity investments (Note 9)	0	186	121
Payment for unredeemed shares of Columbia Pipeline Group, Inc. (Note 27)	0	(373)	0
Deferred amounts and other	(471)	(299)	(295)
Net cash used in investing activities	(6,052)	(6,872)	(10,019)
Financing Activities
Notes payable (repaid)/ issued, net	(220)	1,656	817
Long-term debt issued, net of issue costs	5,770	3,024	6,238
Long-term debt repaid	(3,977)	(3,502)	(3,550)
Junior subordinated notes issued, net of issue costs	0	1,436	0
Loss on settlement of financial instruments (Note 25)	(130)	0	0
Dividends on common shares	(2,987)	(1,798)	(1,571)
Dividends on preferred shares	(159)	(160)	(158)
Distributions to non-controlling interests	(221)	(216)	(225)
Contributions from redeemable non-controlling interest (Note 20)	1,033	0	0
Common shares issued, net of issue costs	91	253	1,148
Partnership units of TC PipeLines, LP issued, net of issue costs	0	0	49
Net cash (used in)/ provided by financing activities	(800)	693	2,748
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(19)	(6)	73
Increase /(Decrease) in Cash and Cash Equivalents	187	897	(643)
Cash and Cash Equivalents, Beginning of year	1,343	446	1,089	$ 446
Cash and Cash Equivalents, End of year	$ 1,530	$ 1,343	$ 446	$ 1,530

Consolidated balance sheet - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current Assets
Cash and cash equivalents	$ 1,530	$ 1,343
Accounts receivable	2,162	2,422
Inventories	629	452
Assets held for sale (Note 27)	0	2,807
Other current assets (Note 6)	880	627
Total Current Assets	5,201	7,651
Plant, Property and Equipment (Note 7)	69,775	65,489
Loan Receivable from Affiliate (Note 10)	1,338	1,434
Equity Investments (Note 9)	6,677	6,506
Restricted Investments	1,898	1,557
Regulatory Assets (Note 11)	1,753	1,587
Goodwill (Note 12)	12,679	12,887
Other Long-Term Assets (Note 13)	979	2,168
Total Assets	100,300	99,279
Current Liabilities
Notes payable (Note 14)	4,176	4,300
Accounts payable and other (Note 15)	3,816	4,544
Redeemable non-controlling interest	633	0
Dividends payable	795	737
Accrued interest	595	613
Current portion of long-term debt (Note 18)	1,972	2,705
Total Current Liabilities	11,987	12,899
Regulatory Liabilities (Note 11)	4,148	3,772
Other Long-Term Liabilities (Note 16)	1,475	1,614
Deferred Income Tax Liabilities (Note 17)	5,806	5,703
Long-Term Debt (Note 18)	34,913	34,280
Junior Subordinated Notes (Note 19)	8,498	8,614
Total Liabilities	66,827	66,882
Redeemable Non-Controlling Interest (Note 20)	393	0
EQUITY
Common shares, no par value (Note 21)	24,488	24,387
Preferred shares (Note 22)	3,980	3,980
Additional paid-in capital	2	0
Retained earnings	5,367	3,955
Accumulated other comprehensive loss (Note 23)	(2,439)	(1,559)
Controlling Interests	31,398	30,763
Non-controlling interests (Note 20)	1,682	1,634
Total Equity	33,080	32,397
Total Liabilities and Equity	$ 100,300	$ 99,279

Consolidated balance sheet (Parenthetical) - shares shares in Millions	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Common shares issued (in shares)	940	938
Common shares outstanding (in shares)	940	938

Consolidated statement of equity - CAD ($) $ in Millions	Total	Equity Attributable to Controlling Interests	Common Shares	Preferred Shares	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Equity Attributable to Non-Controlling Interests
Balance at beginning of year at Dec. 31, 2017			$ 21,167			$ 1,623	$ (1,731)	$ 1,852
Shares issued:
On exercise of stock options			34
Under dividend reinvestment and share purchase plan			855
Under at-the-market equity issuance program, net of issue costs			1,118
Issuance of stock options, net of exercises					$ 10
Dilution from TC PipeLines, LP units issued					7			49
Net income attributable to controlling interests	$ 3,702					3,702
Common share dividends						(2,501)
Preferred share dividends						(163)
Adjustment related to income tax effects of asset drop-downs to TC PipeLines, LP						95
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform						17	(17)
Other comprehensive (loss)/ income attributable to controlling interests (Note 23)	1,314						1,142
Net income /(loss) attributable to non-controlling interests	185							(185)
Other comprehensive (loss)/ income attributable to non-controlling interests								172
Distributions declared to non-controlling interests								(224)
Issuance of TC PipeLines, LP units
Dilution from TC PipeLines, LP units issued					7			49
Decrease in TC Energy's ownership of TC PipeLines, LP								(9)
Balance at end of year at Dec. 31, 2018	30,993	$ 29,338	23,174	$ 3,980	17	2,773	(606)	1,655
Shares issued:
On exercise of stock options			282
Under 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 (loss)/ income attributable to controlling interests (Note 23)	(1,052)						(953)
Net income /(loss) attributable to non-controlling interests	(293)							293
Other comprehensive (loss)/ income 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:
On 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 (loss)/ income attributable to controlling interests (Note 23)	(918)						(880)
Net income /(loss) attributable to non-controlling interests	(297)							307
Other comprehensive (loss)/ income 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

DESCRIPTION OF TC ENERGY'S BUSINESS	12 Months Ended
DESCRIPTION OF TC ENERGY'S BUSINESS	Dec. 31, 2020
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 40,707 km (25,294 miles) of regulated natural gas pipelines. 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, owned directly and through the Company's investment in TC PipeLines, LP. 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. Liquids Pipelines The Liquids Pipelines segment primarily consists of the Company's investments in 4,946 km (3,075 miles) of crude oil pipeline systems 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	12 Months Ended
ACCOUNTING POLICIES	Dec. 31, 2020
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. TC Energy records its proportionate share of undivided interests in certain assets. 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: •recoverability of plant, property and equipment (Notes 7 and 30) and development costs (Notes 13 and 30) •fair value of reporting units that contain goodwill (Notes 12 and 27) and •fair value of assets and liabilities acquired in a business combination (Note 27). 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: •depreciation rates of plant, property and equipment (Note 7) •determining whether a contract contains a lease (Note 8) •fair value of equity investments (Note 9) •carrying value of regulatory assets and liabilities (Note 11) •carrying value of asset retirement obligations (Note 16) •provisions for income taxes, including valuation allowances and releases (Note 17) •assumptions used to measure retirement and other post-retirement benefit obligations (Note 24) •fair value of financial instruments (Note 25) and •provisions for commitments, contingencies and guarantees (Note 28). 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 Canadian, U.S. and Mexico natural gas pipelines, 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. 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 regards 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 27, Acquisitions and dispositions, for additional information regarding the sale of the Columbia Midstream assets. Net revenues earned from the sale of proprietary natural gas are recognized in the month of delivery. 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. Net revenues earned from the sale of proprietary natural gas are recognized in the month of delivery. 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. Other Net revenues earned from the sale of proprietary crude oil are recognized in the month of delivery. Power and Storage Power Generation 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 earned from the sale of proprietary natural gas are recognized in the month of delivery. 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 27, 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 On January 1, 2019, the Company adopted the FASB's new lease guidance using optional transition relief. Results reported for 2020 and 2019 reflect the application of the new guidance while the 2018 comparative results were prepared and reported under previous lease guidance. 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 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 facility 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. 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. Power Purchase Arrangements A power purchase arrangement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis. TC Energy has PPAs for the sale of power that are accounted for as operating leases where TC Energy is the lessor. 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. Canadian income taxes are not provided 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, and •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 expensed 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. 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 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 (loss)/ income (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 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. Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI until the operations are sold, at which time the gains and losses are reclassified to net income. Asset and liability accounts are translated at the period-end exchange rates while revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction. The Company's U.S. dollar-denominated debt and certain derivative hedging instruments have been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar-denominated debt and derivatives are also reflected in OCI. Derivative Instruments and Hedging Activities All derivative instruments are recorded on the Consolidated balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions. The Company applies hedge accounting to arrangements that qualify for and are designated for hedge accounting treatment. This includes fair value and cash flow hedges and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the change in the fair value of the hedging derivative is recognized in OCI. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. Termination payments on interest rate derivatives are classified as a financing activity on the Consolidated statement of cash flows. In hedging the foreign currency exposure of a net investment in a foreign operation, the foreign exchange gains and losses on the hedging instruments are recognized in OCI. The amounts recognized previously in AOCI are reclassified to net income in the event the Company reduces its net investment in a foreign operation. In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory assets or liabilities and are refunded to or collected from ratepayers in subsequent periods when the derivative settles. Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in net income. Long-Term Debt Transaction Costs and Issuance Costs 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 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	12 Months Ended
ACCOUNTING CHANGES	Dec. 31, 2020
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES Changes in Accounting Policies for 2020 Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments, basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write-down of the amortized cost basis. The new guidance was effective January 1, 2020 and was applied using a modified retrospective approach. The adoption of this new guidance did not have a material impact on the Company's consolidated financial statements. Implementation costs of cloud computing arrangements In August 2018, the FASB issued new guidance requiring an entity in a hosting arrangement that is a service contract to follow the guidance for internal-use software to determine which implementation costs should be capitalized as an asset and which costs should be expensed. The guidance also requires the entity to amortize the capitalized implementation costs of a hosting arrangement over the term of the arrangement. This guidance was effective January 1, 2020 and was applied prospectively. The adoption of this new guidance did not have a material impact on the Company's consolidated financial statements. Consolidation In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance was effective January 1, 2020 and was applied on a retrospective basis. The adoption of this new guidance did not have an impact on the Company's consolidated financial statements. Defined benefit plans In August 2018, the FASB issued new guidance which amends and clarifies disclosure requirements related to defined benefit pension and other post-retirement benefit plans. This new guidance was effective for annual disclosure requirements at December 31, 2020 and applied on a retrospective basis. The adoption of this new guidance, which is limited to disclosures only, did not have a material impact on the Company's consolidated financial statements. Reference rate reform In response to the expected cessation of the London Interbank Offered Rate (LIBOR), of which certain rate settings may cease to be published at the end of 2021 with full cessation expected 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 is continuing to identify and analyze existing agreements to determine the effect of reference rate reform on its consolidated financial statements. The Company will continue to evaluate the timing and potential impact of adoption for other optional expedients when deemed necessary. Future Accounting Changes Income taxes In December 2019, the FASB issued new guidance that simplified the accounting for income taxes and clarified existing guidance. This new guidance is effective January 1, 2021, and is not expected to have a material impact on the Company's consolidated financial statements.

- Definition

The entire disclosure for change in accounting principle. Includes, but is not limited to, nature, reason, and method of adopting amendment to accounting standards or other change in accounting principle.

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+ Details

SEGMENTED INFORMATION

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

SEGMENTED INFORMATION


year ended December 31, 2020	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines	Power and Storage	Corporate1		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 other3								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

1Includes intersegment eliminations.

2The 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.

3Income 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 10, Loans receivable from affiliates, for additional information.


year ended December 31, 2019	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines	Power and Storage	Corporate1		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 other3								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

1Includes intersegment eliminations.

3Income /(loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange losses and gains on the peso-denominated loans from affiliates which are fully offset in Interest income and other by the corresponding foreign exchange gains and losses on the affiliate receivable balance. Refer to Note 10, Loans receivable from affiliates, for additional information.


year ended December 31, 2018	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines	Power and Storage	Corporate1		Total
(millions of Canadian $)

Revenues	4,038	4,314	619	2,584	2,124	—		13,679
Intersegment revenues	—	162	—	—	56	(218)	2	—
	4,038	4,476	619	2,584	2,180	(218)		13,679
Income from equity investments	12	256	22	64	355	5	3	714
Plant operating costs and other	(1,405)	(1,368)	(34)	(630)	(315)	159	2	(3,593)
Commodity purchases resold	—	—	—	—	(1,486)	—		(1,486)
Property taxes	(266)	(199)	—	(98)	(6)	—		(569)
Depreciation and amortization	(1,129)	(664)	(97)	(341)	(119)	—		(2,350)
Goodwill and other asset impairment charges	—	(801)	—	—	—	—		(801)
Net gain on sale of assets	—	—	—	—	170	—		170
Segmented earnings /(losses)	1,250	1,700	510	1,579	779	(54)		5,764
Interest expense								(2,265)
Allowance for funds used during construction								526
Interest income and other3								(76)
Income before income taxes								3,949
Income tax expense								(432)
Net income								3,517
Net loss attributable to non-controlling interests								185
Net income attributable to controlling interests								3,702
Preferred share dividends								(163)
Net income attributable to common shares								3,539

Capital spending
Capital expenditures	2,442	5,591	463	110	767	45		9,418
Capital projects in development	36	1	—	459	—	—		496
Contributions to equity investments	—	179	334	12	490	—		1,015
	2,478	5,771	797	581	1,257	45		10,929

1Includes intersegment eliminations.


at December 31	2020	2019
(millions of Canadian $)

Total Assets by segment
Canadian Natural Gas Pipelines	22,852	21,983
U.S. Natural Gas Pipelines	43,217	41,627
Mexico Natural Gas Pipelines	7,215	7,207
Liquids Pipelines	16,744	15,931
Power and Storage	5,062	7,788
Corporate	5,210	4,743
	100,300	99,279

Geographic Information


year ended December 31	2020	2019	2018
(millions of Canadian $)

Revenues
Canada – domestic	4,392	4,059	4,187
Canada – export	1,059	1,035	1,075
United States	6,832	7,558	7,798
Mexico	716	603	619
	12,999	13,255	13,679


at December 31	2020	2019
(millions of Canadian $)

Plant, Property and Equipment
Canada	24,092	23,362
United States	39,698	36,184
Mexico	5,985	5,943
	69,775	65,489

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

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-Publisher FASB
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+ Details

REVENUES

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

REVENUES

Disaggregation of Revenues


year ended December 31, 2020	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	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 other1	61	654	109	3	106	933
	4,469	4,955	716	2,209	298	12,647
Other revenues2,3	—	76	—	162	114	352
	4,469	5,031	716	2,371	412	12,999

1Includes $138 million of fee revenues from affiliates, of which $77 million is related to the construction of the Sur de Texas pipeline which is 60 per cent owned by TC Energy and $61 million is 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 27, Acquisitions and dispositions, for additional information.

2Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 8, Leases, and Note 25, Risk management and financial instruments, for additional information on income from lease arrangements and financial instruments, respectively.

3Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income taxes, for additional information.


year ended December 31, 2019	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	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 revenues1,2	—	83	—	452	50	585
	4,010	4,978	603	2,879	785	13,255

1Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 8, Leases, and Note 25, Risk management and financial instruments, for additional information on income from lease arrangements and financial instruments, respectively.

2Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income taxes, for additional information.


year ended December 31, 2018	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines	Power and Storage	Total
(millions of Canadian $)

Revenues from contracts with customers
Capacity arrangements and transportation	4,038	3,549	614	2,079	—	10,280
Power generation	—	—	—	—	1,771	1,771
Natural gas storage and other	—	654	5	3	81	743
	4,038	4,203	619	2,082	1,852	12,794
Other revenues1,2	—	111	—	502	272	885
	4,038	4,314	619	2,584	2,124	13,679

2Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income taxes, for additional information.

Contract Balances


at December 31	2020	2019	Affected line item on Consolidated balance sheet
(millions of Canadian $)

Receivables from contracts with customers	1,330	1,458	Accounts receivable
Contract assets (Note 6)	132	153	Other current assets
Long-term contract assets (Note 13)	192	102	Other long-term assets
Contract liabilities1 (Note 15)	129	61	Accounts payable and other
Long-term contract liabilities (Note 16)	203	226	Other long-term liabilities

1During the year ended December 31, 2020, $18 million (2019 – $6 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, 2020, future revenues from long-term pipeline capacity arrangements and transportation as well as natural gas storage and other contracts extending through 2047 are approximately $25.5 billion, of which approximately $3.7 billion is expected to be recognized in 2021.

A significant portion of the Company's revenues are considered constrained and therefore not included in the future revenue amounts above as the Company uses the following practical expedients:

•right to invoice practical expedient – applied to all U.S. and certain Mexico rate-regulated natural gas pipeline capacity arrangements and flow-through revenues

•variable consideration practical expedient – applied to the following variable revenues:

◦interruptible transportation service revenues as volumes cannot be estimated

◦liquids pipelines capacity revenues based on volumes transported

◦power generation revenues related to market prices that are subject to factors outside the Company's influence

•contracts for a duration of one year or less.

In addition, future revenues from the Company's Canadian natural gas pipelines' regulated firm capacity contracts include fixed revenues only for the time periods that approved tolls under current rate settlements are in effect and certain, which is currently one year.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/topic&trid=49130388

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+ Details

OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2020

Other Assets [Abstract]

OTHER CURRENT ASSETS


at December 31	2020	2019
(millions of Canadian $)

Fair value of derivative contracts (Note 25)	235	190
Cash provided as collateral	142	52
Contract assets (Note 5)	132	153
Regulatory assets (Note 11)	131	43
Prepaid expenses	126	60
Other	114	129
	880	627

PLANT, PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

PLANT, PROPERTY AND EQUIPMENT


	2020			2019
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)

Canadian Natural Gas Pipelines
NGTL System
Pipeline	14,190	5,278	8,912	11,556	4,846	6,710
Compression	5,421	1,906	3,515	4,205	1,771	2,434
Metering and other	1,393	648	745	1,296	609	687
	21,004	7,832	13,172	17,057	7,226	9,831
Under construction	1,402	—	1,402	3,181	—	3,181
	22,406	7,832	14,574	20,238	7,226	13,012
Canadian Mainline
Pipeline	10,297	7,443	2,854	10,145	7,109	3,036
Compression	3,930	3,000	930	3,867	2,823	1,044
Metering and other	637	239	398	643	219	424
	14,864	10,682	4,182	14,655	10,151	4,504
Under construction	150	—	150	60	—	60
	15,014	10,682	4,332	14,715	10,151	4,564
Other Canadian Natural Gas Pipelines1
Other	1,885	1,508	377	1,861	1,455	406
Under construction2	42	—	42	1,276	—	1,276
	1,927	1,508	419	3,137	1,455	1,682
	39,347	20,022	19,325	38,090	18,832	19,258
U.S. Natural Gas Pipelines
Columbia Gas
Pipeline	10,198	557	9,641	9,708	389	9,319
Compression	4,287	276	4,011	4,094	206	3,888
Metering and other	3,388	185	3,203	3,244	125	3,119
	17,873	1,018	16,855	17,046	720	16,326
Under construction	1,070	—	1,070	425	—	425
	18,943	1,018	17,925	17,471	720	16,751
ANR
Pipeline	1,685	512	1,173	1,594	472	1,122
Compression	2,146	489	1,657	2,050	436	1,614
Metering and other	1,289	388	901	1,245	355	890
	5,120	1,389	3,731	4,889	1,263	3,626
Under construction	431	—	431	252	—	252
	5,551	1,389	4,162	5,141	1,263	3,878


	2020			2019
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)

Other U.S. Natural Gas Pipelines
Columbia Gulf	2,638	151	2,487	2,597	114	2,483
GTN	2,330	1,008	1,322	2,257	969	1,288
Great Lakes	2,117	1,223	894	2,090	1,208	882

Other3	1,568	578	990	1,530	616	914
	8,653	2,960	5,693	8,474	2,907	5,567
Under construction	389	—	389	164	—	164
	9,042	2,960	6,082	8,638	2,907	5,731
	33,536	5,367	28,169	31,250	4,890	26,360
Mexico Natural Gas Pipelines
Pipeline	2,952	411	2,541	2,988	340	2,648
Compression	480	69	411	486	54	432
Metering and other	624	133	491	643	124	519
	4,056	613	3,443	4,117	518	3,599
Under construction	2,525	—	2,525	2,321	—	2,321
	6,581	613	5,968	6,438	518	5,920
Liquids Pipelines
Keystone Pipeline System
Pipeline	9,254	1,579	7,675	9,378	1,403	7,975
Pumping equipment	1,025	228	797	1,035	204	831
Tanks and other	3,522	644	2,878	3,488	556	2,932
	13,801	2,451	11,350	13,901	2,163	11,738
Under construction4	2,870	—	2,870	47	—	47
	16,671	2,451	14,220	13,948	2,163	11,785
Intra-Alberta Pipelines
Pipeline	142	6	136	138	2	136

Tanks and other	56	3	53	56	2	54
	198	9	189	194	4	190




	16,869	2,460	14,409	14,142	2,167	11,975
Power and Storage

Natural Gas	1,255	569	686	1,256	522	734

Natural Gas Storage and Other	780	194	586	742	181	561
	2,035	763	1,272	1,998	703	1,295
Under construction	11	—	11	6	—	6
	2,046	763	1,283	2,004	703	1,301
Corporate	993	372	621	883	208	675
	99,372	29,597	69,775	92,807	27,318	65,489

1Includes Foothills, Ventures LP and Great Lakes Canada.

2Includes the Coastal GasLink pipeline project at December 31, 2019. On May 22, 2020, the Company completed the sale of a 65 per cent equity interest in Coastal GasLink Pipeline Limited Partnership and subsequently commenced accounting for its remaining investment using the equity method. Refer to Note 27, Acquisitions and dispositions, for additional information.

3Includes Portland, North Baja, Tuscarora, Crossroads and mineral rights.

4On March 31, 2020, TC Energy announced that it would proceed with construction of the Keystone XL pipeline. As a result, related capitalized development costs of $1.7 billion were transferred to Plant, property and equipment from Capital projects in development within Other long-term assets on the Consolidated balance sheet. On January 20, 2021, the Presidential Permit for the Keystone XL pipeline was revoked. Refer to Note 30, Subsequent events, for additional information.

Bison Impairment

At December 31, 2018, the Company evaluated its investment in its Bison natural gas pipeline for impairment in connection with the termination of certain customer transportation agreements which released the Company from providing any future services. With the loss of these future cash flows and the persistence of unfavourable market conditions which have inhibited system flows on the pipeline, the Company determined that the asset’s remaining carrying value was no longer recoverable and recognized a non-cash impairment charge of $722 million pre tax in its U.S. Natural Gas Pipelines segment. The non-cash charge was recorded in Goodwill and other asset impairment charges in the Consolidated statement of income. As Bison is a TC PipeLines, LP asset, in which the Company had a 25.5 per cent interest, the Company's share of the impairment charge, after tax and net of non-controlling interests, was $140 million.

The termination of the transportation agreements resulted in the receipt of $130 million in termination payments which were recorded in Revenues in 2018. The Company's share of this amount, after tax and net of non-controlling interests, was $25 million.

LEASES

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

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 to 25 years, and some may include options to terminate the lease within one year. Payments due under lease contracts include fixed payments plus, for many of the Company's leases, variable payments such as a proportionate share of the buildings' property taxes, insurance and common area maintenance. The Company subleases some of the leased premises.

Operating lease cost was as follows:


year ended December 31
(millions of Canadian $)	2020	2019

Operating lease cost1	124	117
Sublease income	(13)	(11)
Net operating lease cost	111	106

1 Includes short-term leases and variable lease costs.

Net rental expense on operating leases in 2018 was $84 million.

Other information related to operating leases is noted in the following tables:


year ended December 31
(millions of Canadian $)	2020	2019

Cash paid for amounts included in the measurement of operating lease liabilities	77	76
ROU assets obtained in exchange for new operating lease liabilities	14	9


at December 31	2020		2019

Weighted average remaining lease term	10 years		10 years
Weighted average discount rate	3.5	%	3.5	%

Maturities of operating lease liabilities are as follows:


(millions of Canadian $)	2020	2019

Less than one year	72	73
One to two years	61	69
Two to three years	59	59
Three to four years	58	58
Four to five years	54	57
More than five years	269	323
Total operating lease payments	573	639
Imputed interest	(90)	(107)
Operating lease liabilities	483	532

The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows:


at December 31
(millions of Canadian $)	2020	2019

Accounts payable and other	56	56
Other long-term liabilities (Note 16)	427	476
	483	532

As at December 31, 2020, the carrying value of the ROU assets recorded under operating leases was $473 million (2019 – $530 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. In addition, the Company has long-term PPAs for the sale of power for the Power and Storage lease assets which expire between 2024 and 2026.

The Northern Courier pipeline in the Liquids Pipelines segment was accounted for as an operating lease prior to the July 2019 sale of an 85 per cent equity interest in Northern Courier. The Company uses the equity method to account for its remaining 15 per cent interest in the Company's consolidated financial statements. Refer to Note 27, Acquisitions and dispositions, for additional information.

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, 2020 was $130 million (2019 – $180 million). Operating lease income in 2018 was $373 million.

Future lease payments to be received under operating leases are as follows:


(millions of Canadian $)	2020	2019

Less than one year	119	123
One to two years	111	116
Two to three years	109	111
Three to four years	109	109
Four to five years	94	109
More than five years	70	164
	612	732

The cost and accumulated depreciation for facilities accounted for as operating leases was $858 million and $327 million, respectively, at December 31, 2020 (2019 – $834 million and $301 million, respectively).

LEASES

As a Lessee

Operating lease cost was as follows:


year ended December 31
(millions of Canadian $)	2020	2019

Operating lease cost1	124	117
Sublease income	(13)	(11)
Net operating lease cost	111	106

1 Includes short-term leases and variable lease costs.

Net rental expense on operating leases in 2018 was $84 million.

Other information related to operating leases is noted in the following tables:


year ended December 31
(millions of Canadian $)	2020	2019

Cash paid for amounts included in the measurement of operating lease liabilities	77	76
ROU assets obtained in exchange for new operating lease liabilities	14	9


at December 31	2020		2019

Weighted average remaining lease term	10 years		10 years
Weighted average discount rate	3.5	%	3.5	%

Maturities of operating lease liabilities are as follows:


(millions of Canadian $)	2020	2019

Less than one year	72	73
One to two years	61	69
Two to three years	59	59
Three to four years	58	58
Four to five years	54	57
More than five years	269	323
Total operating lease payments	573	639
Imputed interest	(90)	(107)
Operating lease liabilities	483	532

The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows:


at December 31
(millions of Canadian $)	2020	2019

Accounts payable and other	56	56
Other long-term liabilities (Note 16)	427	476
	483	532

As a Lessor

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, 2020 was $130 million (2019 – $180 million). Operating lease income in 2018 was $373 million.

Future lease payments to be received under operating leases are as follows:


(millions of Canadian $)	2020	2019

Less than one year	119	123
One to two years	111	116
Two to three years	109	111
Three to four years	109	109
Four to five years	94	109
More than five years	70	164
	612	732

EQUITY INVESTMENTS

12 Months Ended

Dec. 31, 2020

Equity Method Investments and Joint Ventures [Abstract]

EQUITY INVESTMENTS


(millions of Canadian $)	Ownership Interest at December 31, 2020		Income /(Loss) from Equity Investments			Equity Investments
			year ended December 31			at December 31
			2020	2019	2018	2020	2019

Canadian Natural Gas Pipelines
TQM1	50.0	%	12	12	12	90	79
Coastal GasLink1,2	35.0	%	—	—	—	211	—
U.S. Natural Gas Pipelines
Northern Border3	50.0	%	100	91	87	521	549
Millennium	47.5	%	96	92	75	482	496
Iroquois4	50.0	%	52	54	60	197	241
Pennant Midstream5	nil		—	12	17	—	—
Other	Various		16	15	17	120	112
Mexico Natural Gas Pipelines
Sur de Texas6	60.0	%	213	3	27	680	600
Liquids Pipelines
Grand Rapids1,7	50.0	%	53	56	65	998	1,028
Northern Courier1,8	15.0	%	22	14	—	53	62
HoustonLink Pipeline1	50.0	%	—	—	(1)	19	19
Power and Storage
Bruce Power1,9	48.4	%	439	527	311	3,306	3,256
Portlands Energy Centre1,10	nil		12	35	36	—	—
TransCanada Turbines11	100.0	%	4	9	8	—	64
			1,019	920	714	6,677	6,506

1Classified as a non-consolidated VIE. Refer to Note 29, Variable interest entities, for additional information.

2On May 22, 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 27, 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 Coastal GasLink Pipeline Limited Partnership was $188 million due mainly to the fair value assessment of assets at the time of partial monetization.

3At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border was US$116 million (2019 – US$116 million) due mainly to the fair value assessment of assets at the time of acquisition.

4At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$39 million (2019 – US$40 million) due mainly to the fair value assessment of the assets at the times of acquisition.

5In August 2019, TC Energy completed the sale of certain Columbia Midstream assets, including the Company's investment in Pennant Midstream. Refer to Note 27, Acquisitions and dispositions, for additional information.

6Sur 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, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Sur de Texas was US$79 million (2019 – nil) due mainly to fees earned from the successful construction of the pipeline.

7At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $98 million (2019 – $101 million) due mainly to interest capitalized during construction.

8In July 2019, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier, and subsequently applied the equity method to account for its 15 per cent retained equity interest in the jointly controlled entity. Refer to Note 27, 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 (2019 – $62 million) due mainly to the fair value of guarantees and the fair value assessment of assets at the time of partial monetization.

9At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $796 million (2019 – $829 million) due mainly to capitalized interest and the fair value assessment of assets at the time of acquisition.

10Investment in Portlands Energy Centre was reclassed to Assets held for sale in July 2019 and sold on April 29, 2020. At December 31, 2019, the difference between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy Centre was $76 million due mainly to capitalized interest. Refer to Note 27, Acquisitions and dispositions, for additional information.

11On November 13, 2020, TC Energy purchased the remaining 50 per cent ownership in TransCanada Turbines which was subsequently consolidated. Refer to Note 27, Acquisitions and dispositions, for additional information.

Distributions and Contributions

Distributions received from equity investments for the year ended December 31, 2020 were $1,123 million (2019 – $1,399 million; 2018 – $1,106 million). For 2020, all distributions received were included in Cash generated from operations in the Consolidated statement of cash flows. Of the total distributions received in 2019 and 2018, $186 million and $121 million, respectively, were included in Investing activities in the Consolidated statement of cash flows with regard to distributions received from Bruce Power and Northern Border from their respective financing programs.

Contributions made to equity investments for the year ended December 31, 2020 were $765 million (2019 – $602 million; 2018 – $1,015 million) and were included in Investing activities in the Consolidated statement of cash flows. For 2019 and 2018, contributions of $32 million and $179 million, respectively, 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	2020	2019	2018
(millions of Canadian $)

Income
Revenues	5,838	5,693	4,836
Operating and other expenses	(3,341)	(3,408)	(3,545)
Net income	2,047	1,990	1,515
Net income attributable to TC Energy	1,019	920	714


at December 31	2020	2019
(millions of Canadian $)

Balance Sheet
Current assets	2,911	2,305
Non-current assets	26,957	21,865
Current liabilities	(3,727)	(2,060)
Non-current liabilities	(15,309)	(11,461)

LOANS RECEIVABLE FROM AFFILIATES

12 Months Ended

Dec. 31, 2020

Receivables [Abstract]

LOANS RECEIVABLE FROM AFFILIATE

LOANS RECEIVABLE FROM AFFILIATES

Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

Coastal GasLink Pipeline Limited Partnership

In conjunction with the equity sale on May 22, 2020, the Company entered into a subordinated demand revolving credit facility with Coastal GasLink Pipeline Limited Partnership (Coastal GasLink LP), which had a capacity of $200 million at December 31, 2020. This facility provides additional short-term liquidity and funding flexibility to the project and bears interest at a floating market-based rate. At December 31, 2020, there were no amounts outstanding on this facility. Refer to Note 27, Acquisitions and dispositions, for additional information.

Sur de Texas

TC Energy holds a 60 per cent equity interest in a joint venture with IEnova to own the Sur de Texas pipeline, for which TC Energy is the operator. In 2017, TC Energy entered into a MXN$21.3 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. At December 31, 2020, Loan receivable from affiliate on the Company's Consolidated balance sheet reflected a MXN$20.9 billion or $1.3 billion (2019 – MXN$20.9 billion or $1.4 billion) loan receivable from the Sur de Texas joint venture which represents TC Energy's proportionate share of long-term debt financing to the joint venture.

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 $)	2020	2019	2018

Interest income1	110	147	120	Interest income and other
Interest expense2	(110)	(147)	(120)	Income from equity investments
Foreign exchange (losses)/ gains1	(86)	53	(5)	Interest income and other
Foreign exchange gains /(losses)1	86	(53)	5	Income from equity investments

1Included in the Corporate segment.

2Included in the Mexico Natural Gas Pipelines segment.

RATE-REGULATED BUSINESSES

12 Months Ended

Dec. 31, 2020

Regulated Operations [Abstract]

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 (NEB 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. TC Energy projects submitted to the NEB for review prior to August 28, 2019 will continue to be assessed under the previous NEB Act in accordance with the transitional rules under the CER Act.

The CER regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems under federal jurisdiction.

TC Energy's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and return 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 approved by the CER on August 17, 2020. The settlement, effective January 1, 2020, includes an ROE of 10.1 per cent on 40 per cent deemed common equity, provides the NGTL System with the opportunity to increase depreciation rates if tolls fall below projected levels and includes an incentive mechanism for certain operating costs where variances from projected amounts are shared between the NGTL System and its customers. It also includes a mechanism to review the settlement should tolls exceed a pre-determined level, without affecting the equity return.

NGTL System's 2019 and 2018 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 deemed common equity of 40 per cent, 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 (NEB 2018 Decision) 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.

On April 17, 2020, the CER approved the six-year unanimous negotiated settlement (2021-2026 Mainline Settlement) filed in December 2019. 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. Going forward, 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.

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), and income taxes for rate-making purposes in a master limited partnership (MLP) that impact future earnings and cash flows of FERC-regulated pipelines. As part of the 2018 FERC Actions, FERC issued a Revised Policy Statement which created a presumption that entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in their cost-of-service rates. In addition, FERC established that, to the extent an entity's income tax allowance should be eliminated from rates, it must also eliminate existing accumulated deferred income tax (ADIT) asset and liability balances from its rate base.

These 2018 FERC Actions also established a process and schedule by which all FERC-regulated interstate pipelines and natural gas storage facilities had to either (i) file a new uncontested rate settlement or (ii) file a FERC Form 501-G that quantified the isolated impact of U.S. Tax Reform and provided four options to address the impact for rate-making purposes.

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$1.5 billion from 2013-2017 to modernize the Columbia Gas system thereby improving system integrity and enhancing service reliability and flexibility. An extension of this settlement was approved by FERC in 2016 which allows for the cost recovery and return on additional expanded scope investment of US$1.1 billion over a three-year period through 2020.

Columbia Gas filed a general NGA Section 4 Rate Case with FERC on July 31, 2020 requesting an increase to Columbia Gas's maximum transportation rates expected to become effective February 1, 2021, subject to refund. The rate case continues to progress as expected, and the Company intends to pursue a collaborative process to reach a mutually beneficial outcome with its customers through settlement negotiations.

ANR Pipeline

ANR Pipeline operates under rates established through a FERC-approved rate settlement in 2016. Under terms of the 2016 settlement, ANR Pipeline is no longer under a rate moratorium and is required to file for new rates to be effective no later than August 1, 2022.

On August 10, 2020, FERC terminated ANR Pipeline's 501-G proceeding and ruled that ANR Pipeline has complied with the one-time reporting requirement. Additionally, FERC stated it will not exercise its right to initiate a NGA Section 5 investigation into ANR’s effective rates at this time but may in the future, if warranted.

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.

TC PipeLines, LP

TC Energy owns a 25.5 per cent interest in TC PipeLines, LP, which has ownership interests in eight wholly-owned or partially-owned natural gas pipelines serving major markets in the U.S. As TC PipeLines, LP is an MLP, all pipelines it owns wholly or in part were impacted by the 2018 FERC Actions which required these pipelines to eliminate their existing ADIT balance from rate base. Refer to Note 17, Income taxes, for additional information regarding the impact of these changes to TC Energy.

Great Lakes

Great Lakes reached a rate settlement with its customers, which was approved by FERC in February 2018, decreasing Great Lakes' maximum transportation rates by 27 per cent effective October 2017. This settlement does not contain a moratorium and 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. In 2018, as a result of the 2018 FERC Actions noted above, Great Lakes made a limited NGA Section 4 filing which had the effect of reducing rates by two per cent from what was in place previously. The reduction in rates became effective on February 1, 2019 after the limited Section 4 filing was accepted by FERC.

On May 11, 2020, FERC terminated Great Lakes’ 501-G proceeding and ruled that Great Lakes has complied with the one-time reporting requirement. Additionally, FERC also stated that rate reductions provided for in its 2017 settlement and the two per cent rate reduction from the limited Section 4 rate reduction proceeding have provided substantial rate relief for Great Lakes’ shippers and, as a result, it will not exercise its right to institute a NGA Section 5 investigation to determine if Great Lakes is over-recovering on its current tariff rates.

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	2020	2019	Remaining Recovery/ Settlement Period (years)
(millions of Canadian $)

Regulatory Assets
Deferred income taxes1	1,287	1,088	n/a
Operating and debt-service regulatory assets2	54	2	1
Pensions and other post-retirement benefits1,3	401	417	n/a
Foreign exchange on long-term debt1,4	7	16	1-9
Other	135	107	n/a
	1,884	1,630
Less: Current portion included in Other current assets (Note 6)	131	43
	1,753	1,587
Regulatory Liabilities

Operating and debt-service regulatory liabilities2	48	139	1
Pensions and other post-retirement benefits3	18	35	n/a
ANR-related post-employment and retirement benefits other than pension5	40	41	n/a
Long-term adjustment account6,7	227	660	6
Bridging amortization account6	537	428	10
Pipeline abandonment trust balances8	1,842	1,462	n/a
Cost of removal9	246	253	n/a
Deferred income taxes1	115	151	n/a
Deferred income taxes – U.S. Tax Reform10	1,170	1,239	n/a
Other	58	60	n/a
	4,301	4,468
Less: Current portion included in Accounts payable and other (Note 15)	153	696
	4,148	3,772

1These 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.

2Operating 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.

3These 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.

4Foreign 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.

5This balance represents the amount ANR estimates would be required to refund to its customers for post-retirement and post-employment benefit amounts collected through its FERC-approved rates that have not been used to pay benefits to its employees. Pursuant to a FERC-approved rate settlement, the $40 million (US$32 million) balance at December 31, 2020 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period cannot be determined at this time.

6These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll-stabilization adjustments during the 2015-2030 settlement term.

7Under the terms of the 2021-2026 Mainline Settlement, $223 million will be amortized over the six-year settlement term and the residual of $4 million will be transferred to the STAA.

8This 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.

9This 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.

10These balances represent the impact of U.S. Tax Reform. 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 under the Reverse South Georgia Methodology.

GOODWILL

12 Months Ended

Dec. 31, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL

The Company has recorded the following Goodwill on its acquisitions:


(millions of Canadian $)			U.S. Natural Gas Pipelines

Balance at January 1, 2019			14,178
Sale of Columbia Midstream assets			(595)
Foreign exchange rate changes			(696)
Balance at December 31, 2019			12,887

Foreign exchange rate changes			(208)
Balance at December 31, 2020			12,679

As part of the annual goodwill impairment assessment at December 31, 2020, the Company evaluated qualitative factors impacting the fair value of the underlying reporting units. It was determined that it was more likely than not that the fair value of the reporting units exceeded their carrying amounts, including goodwill.

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 27, Acquisitions and dispositions, for additional details.

Tuscarora

In 2018, the Company recorded a goodwill impairment charge of $79 million pre-tax within the U.S. Natural Gas Pipelines segment. The fair value of the reporting unit was determined using a discounted cash flow analysis. This non-cash charge was recorded in Goodwill and other asset impairment charges in the Consolidated statement of income. As Tuscarora is a TC PipeLines, LP asset, the Company's share of this amount, after tax and net of non-controlling interests, was $15 million. The gross goodwill and accumulated impairment losses related to Tuscarora were US$82 million and US$59 million, respectively, on the Consolidated balance sheet at December 31, 2020 and 2019.

OTHER LONG-TERM ASSETS

12 Months Ended

Dec. 31, 2020

Intangible Assets, Net (Excluding Goodwill) [Abstract]

OTHER LONG-TERM ASSETS


at December 31	2020	2019
(millions of Canadian $)

Capital projects in development	231	1,715
Employee post-retirement benefits (Note 24)	207	162
Long-term contract assets (Note 5)	192	102
Deferred income tax assets (Note 17)	177	37
Fair value of derivative contracts (Note 25)	41	7
Other	131	145
	979	2,168

Capital Projects in Development

Keystone XL

On March 31, 2020, TC Energy announced that it would proceed with construction of the Keystone XL pipeline and, as a result, $1.7 billion of related capitalized development costs were transferred to Plant, property and equipment. At December 31, 2019, the amount included in Capital projects in development for this project was $1.5 billion.

Reimbursement of Coastal GasLink pipeline project costs

In November 2018, in accordance with provisions in the agreements with the LNG Canada joint venture participants, all five parties elected to collectively reimburse TC Energy $470 million representing costs incurred prior to receiving the Final Investment Decision (FID) on the Coastal GasLink pipeline project (Coastal GasLink). These payments were recorded as a reduction of the carrying value of Coastal GasLink costs which, subsequent to the FID, were reported in Plant, property and equipment until the sale of a 65 per cent equity interest in Coastal GasLink LP on May 22, 2020, at which point TC Energy's remaining investment was recorded in Equity investments. Refer to Note 27, Acquisitions and dispositions, for additional information.

NOTES PAYABLE

12 Months Ended

Dec. 31, 2020

Short-term Debt [Abstract]

NOTES PAYABLE


	2020			2019
(millions of Canadian $, unless otherwise noted)	Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31		Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31

Canada1	2,836	0.4	%	4,034	2.1	%
U.S. (2020 – US$900; 2019 – nil)	1,149	0.4	%	—	—
Mexico (2020 – US$150; 2019 – US$205)2	191	1.7	%	266	2.7	%
	4,176			4,300

1At December 31, 2020, Notes payable consisted of Canadian dollar-denominated notes of $656 million (2019 – $1,353 million) and U.S. dollar-denominated notes of US$1,709 million (2019 – US$2,068 million).

2The 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, 2020 and 2019, Notes payable reflects short-term borrowings in Canada by TransCanada PipeLines Limited (TCPL) and in Mexico by a wholly-owned Mexican subsidiary. At December 31, 2020, Notes payable also includes short-term borrowings in the U.S. by TransCanada PipeLine USA Ltd. (TCPL USA).

At December 31, 2020, total committed revolving and demand credit facilities were $12.4 billion (2019 – $12.6 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)

2020

2019

Borrower

Description

Matures

Total Facilities

Unused Capacity 1

Total Facilities

Committed, syndicated, revolving, extendible, senior unsecured credit facilities2:

TCPL

Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes

December 2024

3.0

2.3

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 2021

US 4.5

US 1.9

US 4.5

TCPL/TCPL USA/Columbia/TransCanada American Investments Ltd.

For general corporate purposes of the borrowers, guaranteed by TCPL

December 2022

US 1.0

Demand senior unsecured revolving credit facilities2:

TCPL/TCPL USA

Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL

Demand

2.1

1.1

2.1

Mexico subsidiary

For Mexico general corporate purposes, guaranteed by TCPL

Demand

MXN5.0

MXN2.0

MXN5.0

1Net of commercial paper outstanding and facility draws.

2Provisions 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, 2020, the Company was in compliance with all debt covenants.

3Or the U.S. dollar equivalent.

In second quarter 2020, an additional US$2.0 billion of 364-day committed bilateral credit facilities were established. These credit facilities were extinguished in fourth quarter 2020 as they were no longer required.

For the year ended December 31, 2020, the cost to maintain the above facilities was $21 million (2019 – $11 million; 2018 – $12 million).

At December 31, 2020, certain of the Company's other subsidiaries had an additional $0.8 billion (2019 – $0.8 billion) of undrawn capacity on third-party committed credit facilities.

ACCOUNTS PAYABLE AND OTHER

12 Months Ended

Dec. 31, 2020

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE AND OTHER


at December 31	2020	2019
(millions of Canadian $)

Trade payables	3,057	3,314
Regulatory liabilities (Note 11)	153	696
Contract liabilities (Note 5)	129	61
Fair value of derivative contracts (Note 25)	72	115


Other	405	358
	3,816	4,544

OTHER LONG-TERM LIABILITIES

12 Months Ended

Dec. 31, 2020

Deferred Costs, Noncurrent [Abstract]

OTHER LONG-TERM LIABILITIES


at December 31	2020	2019
(millions of Canadian $)

Employee post-retirement benefits (Note 24)	503	540
Operating lease obligations (Note 8)	427	476
Long-term contract liabilities (Note 5)	203	226
Fair value of derivative contracts (Note 25)	59	81
Asset retirement obligations	54	62
Guarantees	30	32
Other	199	197
	1,475	1,614

INCOME TAXES

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

INCOME TAXES

Provision for Income Taxes


year ended December 31	2020	2019	2018
(millions of Canadian $)

Current
Canada	(54)	84	65
Foreign1	306	615	250
	252	699	315
Deferred
Canada	(224)	(29)	49
Foreign	166	84	235
Foreign – U.S. Tax Reform and 2018 FERC Actions	—	—	(167)
	(58)	55	117
Income Tax Expense	194	754	432

1The 2019 current foreign income tax expense mainly relates to the sale of certain Columbia Midstream assets in August 2019. Refer to Note 27, Acquisitions and dispositions, for additional information.

Geographic Components of Income before Income Taxes


year ended December 31	2020	2019	2018
(millions of Canadian $)

Canada	691	1,144	433
Foreign	4,416	4,043	3,516
Income before Income Taxes	5,107	5,187	3,949

Reconciliation of Income Tax Expense


year ended December 31	2020		2019		2018
(millions of Canadian $)

Income before income taxes	5,107		5,187		3,949
Federal and provincial statutory tax rate	24.0	%	26.5	%	27.0	%
Expected income tax expense	1,226		1,375		1,066
Valuation allowance releases	(400)		(259)		—
Foreign income tax rate differentials	(258)		(180)		(432)
Income tax differential related to regulated operations	(228)		(159)		(54)
(Income)/ loss from non-controlling interests and equity investments	(141)		(78)		50
Alberta tax rate reduction	—		(32)		—
Non-taxable portion of capital gains	(62)		(28)		(11)
Non-deductible goodwill on the Columbia Midstream asset disposition	—		154		—
U.S. Tax Reform and 2018 FERC Actions	—		—		(167)


Other	57		(39)		(20)
Income Tax Expense	194		754		432

Deferred Income Tax Assets and Liabilities


at December 31	2020	2019
(millions of Canadian $)

Deferred Income Tax Assets
Tax loss and credit carryforwards	1,389	1,046
Regulatory and other deferred amounts	532	692
Difference in accounting and tax bases of impaired assets and assets held for sale	537	538
Unrealized foreign exchange losses on long-term debt	154	260
Financial instruments	48	23
Other	70	70
	2,730	2,629
Less: Valuation allowance	243	673
	2,487	1,956
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment	6,661	6,197
Equity investments	1,087	1,087
Taxes on future revenue requirement	287	232
Other	81	106
	8,116	7,622
Net Deferred Income Tax Liabilities	5,629	5,666

The above deferred tax amounts have been classified on the Consolidated balance sheet as follows:


at December 31	2020	2019
(millions of Canadian $)

Deferred Income Tax Assets
Other long-term assets (Note 13)	177	37
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,806	5,703
Net Deferred Income Tax Liabilities	5,629	5,666

At December 31, 2020, the Company has recognized the benefit of non-capital loss carryforwards of $3,671 million (2019 – $1,929 million) for federal and provincial purposes in Canada, which expire from 2030 to 2040. The Company has not yet recognized the benefit of capital loss carryforwards of $253 million (2019 – $598 million) for federal and provincial purposes in Canada, with no expiry date. The Company also has Ontario minimum tax credits of $106 million (2019 – $102 million), which expire from 2026 to 2040.

At December 31, 2020, the Company has fully recognized the benefit of net operating loss carryforwards of US$849 million (2019 – US$1,098 million) for federal purposes in the U.S., which expire from 2029 to 2037.

At December 31, 2020, the Company has recognized the benefit of net operating loss carryforwards of US$13 million (2019 – US$4 million) in Mexico, which expire from 2024 to 2030.

TC Energy recorded an income tax valuation allowance of $243 million and $673 million against the deferred income tax asset balances at December 31, 2020 and 2019, respectively. The decrease in the valuation allowance in 2020 is primarily a result of the foreign exchange movement on unrecognized capital losses, realized capital gains and valuation allowance releases. 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, 2020, 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.

The Company recorded $400 million in valuation allowance releases in 2020 primarily a result of the final investment decision to proceed with the construction of the Keystone XL pipeline, the sale of the Ontario natural gas-fired power plants and the sale of a 65 per cent equity interest in Coastal GasLink LP. Refer to Note 27, Acquisitions and dispositions, for additional information on the sale of the Ontario natural gas-fired power plants and Coastal GasLink LP equity sale, and refer to Note 30, Subsequent events, for additional information on the Keystone XL pipeline.

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, 2020 by approximately $684 million (2019 – $648 million) if there had been a provision for these taxes.

Income Tax Payments

Income tax payments of $252 million, net of refunds, were made in 2020 (2019 – payments, net of refunds, of $713 million; 2018 – payments, net of refunds, of $338 million).

Reconciliation of Unrecognized Tax Benefit

Below is the reconciliation of the annual changes in the total unrecognized tax benefit:


at December 31	2020	2019	2018
(millions of Canadian $)

Unrecognized tax benefit at beginning of year	29	19	15
Gross increases – tax positions in prior years	26	13	13
Gross decreases – tax positions in prior years	(2)	(1)	(5)
Gross increases – tax positions in current year	1	—	—

Lapse of statutes of limitations	(2)	(2)	(4)
Unrecognized Tax Benefit at End of Year	52	29	19

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 2012. 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.

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, 2020 reflects $4 million of interest expense (2019 – $4 million of interest expense; 2018 – $1 million of interest recovery). At December 31, 2020, the Company had accrued $11 million in interest expense (December 31, 2019 – $7 million). The Company incurred no penalties associated with income tax uncertainties related to Income tax expense for the years ended December 31, 2020, 2019 and 2018 and no penalties were accrued as at December 31, 2020 and 2019.

U.S. Tax Reform and FERC Actions

In 2017, U.S. Tax Reform was signed into law and the enacted U.S. federal corporate income tax rate was reduced from 35 per cent to 21 per cent effective January 1, 2018. This resulted in a remeasurement of existing deferred income tax assets and deferred income tax liabilities related to the Company's U.S. businesses to reflect the new lower income tax rate as at December 31, 2017. Given the significance of the legislation, SEC registrants were allowed to record provisional amounts at December 31, 2017 which could be adjusted as additional information became available, prepared or analyzed for a period not to exceed one year. The Company recognized further adjustments to the provisional amount in 2018.

In accordance with FERC Form 501-G and uncontested rate settlement filings, the ADIT balances for all pipelines held wholly or in part by TC PipeLines, LP were eliminated from their respective rate bases. As a result, net regulatory liabilities recorded for these assets pursuant to U.S. Tax Reform were written off, resulting in a further deferred income tax recovery of $115 million in 2018.

Under U.S. Tax Reform, the U.S. Treasury and the U.S. Internal Revenue Service issued final base erosion and anti-abuse tax regulations in 2019 and final anti-hybrid rules on April 7, 2020. The finalization of these regulations did not have a material impact on the Company's consolidated financial statements at December 31, 2020.

Mexico Tax Reform

In 2019, Mexico passed tax reform legislation related to, among other things, interest deductibility and tax reporting. These changes did not have a material impact on the Company's consolidated financial statements at December 31, 2020.

Alberta Rate Reduction

On December 9, 2020, the Government of Alberta enacted the reduction of the corporate income tax rate to eight per cent effective July 1, 2020. This change did not have a material impact on the Company's consolidated financial statements at December 31, 2020.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References + Details

LONG-TERM DEBT

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

LONG-TERM DEBT


		2020			2019
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate1		Outstanding at December 31	Interest Rate1
(millions of Canadian $, unless otherwise noted)

TRANSCANADA PIPELINES LIMITED
Debentures
Canadian		—	—		250	11.8	%
U.S. (2020 and 2019 – US$400)	2021	510	9.9	%	518	9.9	%
Medium Term Notes
Canadian	2021 to 2049	11,491	4.5	%	9,491	4.6	%
Senior Unsecured Notes
U.S. (2020 – US$14,292; 2019 – US$14,792)	2022 to 2049	18,227	5.3	%	19,174	5.2	%
		30,228			29,433
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian	2024	100	9.9	%	100	9.9	%
U.S. (2020 and 2019 – US$200)	2023	255	7.9	%	259	7.9	%
Medium Term Notes
Canadian	2025 to 2030	504	7.4	%	504	7.4	%
U.S. (2020 and 2019 – US$33)	2026	42	7.5	%	42	7.5	%
		901			905
COLUMBIA PIPELINE GROUP, INC.
Senior Unsecured Notes
U.S. (2020 – US$1,500; 2019 – US$2,250)2	2025 to 2045	1,913	4.9	%	2,916	4.4	%
TC PIPELINES, LP


Unsecured Term Loan
U.S. (2020 and 2019 – US$450)	2022	574	1.4	%	583	2.9	%
Senior Unsecured Notes
U.S. (2020 and 2019 – US$1,200)	2021 to 2027	1,530	4.4	%	1,556	4.4	%
		2,104			2,139
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2020 and 2019 – US$672)	2021 to 2026	858	7.2	%	872	7.2	%
GAS TRANSMISSION NORTHWEST LLC


Senior Unsecured Notes
U.S. (2020 - US$325; 2019 – US$250)	2030 to 2035	415	4.3	%	324	5.6	%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2020 – US$198; 2019 – US$219)	2021 to 2030	253	7.6	%	284	7.7	%


		2020			2019
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate1		Outstanding at December 31	Interest Rate1
(millions of Canadian $, unless otherwise noted)
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Unsecured Loan Facility
U.S. (2020 – US$25; 2019 – US$39)	2023	32	1.3	%	51	3.0	%
Senior Unsecured Notes
U.S. (2020 – US$125 ; 2019 – nil)	2030	159	2.8	%	—	—
		191			51
TUSCARORA GAS TRANSMISSION COMPANY
Unsecured Term Loan
U.S. (2020 and 2019 – US$23)	2021	29	2.2	%	30	2.8	%
NORTH BAJA PIPELINE, LLC
Unsecured Term Loan
U.S. (2020 and 2019 – US$50)	2021	64	1.2	%	65	2.8	%
		36,956			37,019
Current portion of long-term debt		(1,972)			(2,705)
Unamortized debt discount and issue costs		(238)			(228)
Fair value adjustments3		167			194
		34,913			34,280

1Interest 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.

2Certain 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.

3The fair value adjustments include $167 million (2019 – $193 million) related to the acquisition of Columbia. In 2019, these adjustments also included an increase of $1 million related to hedged interest rate risk. Refer to Note 25, Risk management and financial instruments, for additional information.

Principal Repayments

At December 31, 2020, principal repayments for the next five years on the Company's long-term debt are approximately as follows:


(millions of Canadian $)	2021	2022	2023	2024	2025

Principal repayments on long-term debt	1,972	1,901	1,861	286	2,712

Long-Term Debt Issued

The Company issued long-term debt over the three years ended December 31, 2020 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Issue Date

Type

Maturity Date

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

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

April 2019

Medium Term Notes

October 2049

1,000

4.34

October 2018

Senior Unsecured Notes

March 2049

US 1,000

5.10

October 2018

Senior Unsecured Notes

May 2028

US 400

4.25

July 2018

Medium Term Notes

July 2048

800

4.18

July 2018

Medium Term Notes

March 2028

200

3.39

May 2018

Senior Unsecured Notes

May 2028

US 1,000

4.25

May 2018

Senior Unsecured Notes

May 2048

US 1,000

4.875

May 2018

Senior Unsecured Notes

May 2038

US 500

4.75

PORTLAND NATURAL GAS TRANSMISSION SYSTEM

October 2020

Senior Unsecured Notes

October 2030

US 125

2.84

April 2018

Unsecured Loan Facility

April 2023

US 19

Floating

GAS TRANSMISSION NORTHWEST LLC

June 2020

Senior Unsecured Notes

June 2030

US 175

3.12

COASTAL GASLINK PIPELINE LIMITED PARTNERSHIP4

April 2020

Senior Secured Credit Facilities

April 2027

1,603

Floating

NORTHERN COURIER PIPELINE LIMITED PARTNERSHIP5

July 2019

Senior Secured Notes

June 2042

1,000

3.365

NORTH BAJA PIPELINE, LLC

December 2018

Unsecured Term Loan

December 2021

US 50

Floating

1Reflects 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 3.991 per cent.

2Reflects coupon rate on re-opening of a pre-existing senior unsecured notes issue. The notes were issued at a discount to par, resulting in a re-issuance yield of 4.439 per cent.

3Reflects coupon rate on re-opening of a pre-existing MTN issue. The MTNs were issued at a discount to par, resulting in a re-issuance yield of 3.41 per cent.

4On April 28, 2020, Coastal GasLink LP entered into secured long-term project financing credit facilities. On May 22, 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 27, Acquisitions and dispositions, for additional information.

5In 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 accounts for its remaining 15 per cent interest using the equity method. Refer to Note 27, 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, 2020 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Retirement/Repayment Date

Type

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

November 2020

Debentures

250

11.80

October 2020

Senior Unsecured Notes

US 1,000

3.80

March 20201

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

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

August 2018

Senior Unsecured Notes

US 850

6.50

March 2018

Debentures

150

9.45

January 2018

Senior Unsecured Notes

US 500

1.875

January 2018

Senior Unsecured Notes

US 250

Floating

PORTLAND NATURAL GAS TRANSMISSION SYSTEM

October 2020

Unsecured Loan Facility

US 99

Floating

May 2018

Senior Secured Notes

US 18

5.90

COLUMBIA PIPELINE GROUP, INC.

June 2020

Senior Unsecured Notes

US 750

3.30

June 2018

Senior Unsecured Notes

US 500

2.45

GAS TRANSMISSION NORTHWEST LLC

June 2020

Senior Unsecured Notes

US 100

5.29

May 2019

Unsecured Term Loan

US 35

Floating

TC PIPELINES, LP

June 2019

Unsecured Term Loan

US 50

Floating

December 2018

Unsecured Term Loan

US 170

Floating

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

March 2018

Senior Unsecured Notes

US 9

6.73

1Related 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.

Interest Expense


year ended December 31	2020	2019	2018
(millions of Canadian $)

Interest on long-term debt	1,963	1,931	1,877
Interest on junior subordinated notes	470	427	391
Interest on short-term debt	46	106	73
Capitalized interest	(294)	(186)	(124)
Amortization and other financial charges1	43	55	48
	2,228	2,333	2,265

1Amortization 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 $2,203 million in 2020 (2019 – $2,295 million; 2018 – $2,156 million) on long-term debt, junior subordinated notes and short-term debt, net of interest capitalized.

JUNIOR SUBORDINATED NOTES

12 Months Ended

Dec. 31, 2020

Junior Subordinated Notes [Abstract]

JUNIOR SUBORDINATED NOTES


		2020			2019
Outstanding loan amount	Maturity Date	Outstanding at December 31	Effective Interest Rate1		Outstanding at December 31	Effective Interest Rate1
(millions of Canadian $, unless otherwise noted)

TRANSCANADA PIPELINES LIMITED
US$1,000 notes issued 2007 at 6.35%2	2067	1,275	4.1	%	1,296	5.1	%
US$750 notes issued 2015 at 5.875%3,4	2075	957	5.0	%	972	6.0	%
US$1,200 notes issued 2016 at 6.125%3,4	2076	1,530	5.8	%	1,556	6.7	%
US$1,500 notes issued 2017 at 5.55%3,4	2077	1,913	4.7	%	1,944	5.7	%
$1,500 notes issued 2017 at 4.90%3,4	2077	1,500	4.5	%	1,500	5.4	%
US$1,100 notes issued 2019 at 5.75%3,4	2079	1,403	5.4	%	1,426	6.3	%
		8,578			8,694
Unamortized debt discount and issue costs		(80)			(80)
		8,498			8,614

1The 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.

2Junior 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.

3The 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.

4The 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 September 2019, TransCanada Trust (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 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 25, Risk management and financial instruments, for additional information regarding the expected impact to the Company with certain rate settings of LIBOR which may cease to be published at the end of 2021 with full cessation expected 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.

REDEEMABLE NON-CONTROLLING INTERESTS AND NON-CONTROLLING INTERESTS

12 Months Ended

Dec. 31, 2020

Noncontrolling Interest [Abstract]

REDEEMABLE NON-CONTROLLING INTERESTS AND NON-CONTROLLING INTERESTS

REDEEMABLE NON-CONTROLLING INTEREST AND NON-CONTROLLING INTERESTS

Redeemable Non-Controlling Interest

On March 31, 2020, TC Energy announced that it would proceed with construction of the Keystone XL pipeline. As part of the funding plan, the Government of Alberta agreed to invest up to US$1.1 billion as equity in certain Keystone XL subsidiaries of TC Energy. In the year ended December 31, 2020, the Government of Alberta invested $1,033 million in the form of Class A Interests which rank above TC Energy's equity investment in Keystone XL and have certain voting rights.

TC Energy has a call right exercisable at any time to repurchase the Class A Interests from the Government of Alberta. In turn, the Government of Alberta has a put right to sell its Class A Interests to the Company exercisable upon and following the in-service date of the Keystone XL pipeline if certain conditions are met. As a result of these redemption features, the Company classified the Class A Interests as Redeemable non-controlling interest in mezzanine equity on the Consolidated balance sheet. These Class A Interests are entitled to a return in accordance with contractual terms. This return accrues on a quarterly basis and adjusts the carrying value of the Class A Interests accordingly. Refer to Note 30, Subsequent events, for additional information.

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. 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 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 is fully guaranteed by the Government of Alberta and non-recourse to the Company. The Company drew US$579 million on the credit facility on January 8, 2021, of which US$497 million was used to repurchase a majority of the Government of Alberta’s Class A Interests. The facility bears interest at a floating rate and matures in January 2024.

The changes in Redeemable non-controlling interest classified in mezzanine equity were as follows:


year ended December 31			2020
(millions of Canadian $)

Balance at beginning of year			—
Class A Interests issued			1,033
Net loss attributable to redeemable non-controlling interest1			(10)
Class A Interests transferred to Current liabilities			(630)
Balance at end of year			393

1Includes a return accrual and a foreign currency translation loss on Class A Interests, both of which were presented within Net income /(loss) attributable to non-controlling interests in the Consolidated statement of income.

Non-Controlling Interests

TC PipeLines, LP

During 2020 and 2019, the non-controlling interests in TC PipeLines, LP remained at 74.5 per cent and in 2018 ranged between 74.3 per cent and 74.5 per cent due to periodic issuances of common units in TC PipeLines, LP to third parties under an at-the-market issuance program. Refer to Note 28, Commitments, contingencies and guarantees, for additional information on the acquisition of common units of TC PipeLines, LP.

The Company's Non-controlling interests included on the Consolidated balance sheet were as follows:


at December 31	2020	2019
(millions of Canadian $)

Non-controlling interests in TC PipeLines, LP	1,682	1,634

The Company's Net income /(loss) attributable to non-controlling interests included in the Consolidated statement of income were as follows:


year ended December 31	2020	2019	2018
(millions of Canadian $)

Non-controlling interests in TC PipeLines, LP	307	293	(185)
Redeemable non-controlling interest	(10)	—	—


	297	293	(185)

COMMON SHARES

12 Months Ended

Dec. 31, 2020

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

COMMON SHARES


	Number of Shares	Amount
	(thousands)	(millions of Canadian $)

Outstanding at January 1, 2018	881,376	21,167
At-the-market equity issuance program1	20,050	1,118
Dividend reinvestment and share purchase plan	15,937	855
Exercise of options	734	34
Outstanding at December 31, 2018	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

1Net of issue costs and deferred income taxes.

Common Shares Issued and Outstanding

The Company is authorized to issue an unlimited number of common shares without par value.

TC Energy Corporation At-the-Market Equity Issuance Program

In June 2017, the Company established an At-the-Market Equity Issuance Program (ATM program) that allowed, from time to time, for the issuance of common shares from treasury at the prevailing market price when sold through the Toronto Stock Exchange, the New York Stock Exchange or any other existing trading market for TC Energy common shares in Canada or the United States. This ATM program was effective for a 25-month period and was utilized as appropriate to assist in managing the Company's capital structure. Under the initial ATM program, the Company could issue up to $1.0 billion in common shares or the U.S. dollar equivalent. In June 2018, the Company replenished the capacity available under the program which allowed for the issuance of additional common shares from treasury up to $1.0 billion for a revised aggregate total of $2.0 billion or the U.S. dollar equivalent.

In 2018, 20 million common shares were issued under the above ATM program at an average price of $56.13 per share for proceeds of $1.1 billion, net of approximately $10 million of related commissions and fees. In July 2019, this ATM program expired with no common shares issued under it in 2019.

On December 7, 2020, the Company established a new ATM program that allows for the issuance of up to $1.0 billion in common shares or the U.S. dollar equivalent under substantially similar terms and trading platforms. 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. No common shares were issued under this program in 2020.

Dividend Reinvestment and Share Purchase Plan

Under the Company's Dividend Reinvestment and Share Purchase Plan (DRP), eligible holders of common and preferred shares of TC Energy can reinvest their dividends and make optional cash payments to obtain additional TC Energy common shares. From July 1, 2016 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.

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.

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)	2020	2019	2018

Basic	940	929	902
Diluted	940	931	903

Stock Options


	Number of Options (thousands)	Weighted Average Exercise Prices	Weighted Average Remaining Contractual Life (years)

Options outstanding at January 1, 2020	9,094	$55.77
Options granted	1,714	$75.06
Options exercised	(1,664)	$54.47
Options forfeited/expired	(148)	$63.95
Options Outstanding at December 31, 2020	8,996	$59.55	3.8
Options Exercisable at December 31, 2020	5,395	$55.74	2.8

At December 31, 2020, an additional 6,396,168 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	2020		2019		2018

Weighted average fair value	$7.73		$6.37		$5.80
Expected life (years)1	5.7		5.7		5.7
Interest rate	1.5	%	1.9	%	2.1	%
Volatility2	17	%	19	%	16	%
Dividend yield	4.2	%	5.0	%	4.2	%

1Expected life is based on historical exercise activity.

2Volatility 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 2020 (2019 – $13 million; 2018 – $13 million). At December 31, 2020, unrecognized compensation costs related to non-vested stock options were $14 million. The cost is expected to be fully recognized over a weighted average period of 1.7 years.

The following table summarizes additional stock option information:


year ended December 31	2020	2019	2018
(millions of Canadian $, unless otherwise noted)

Total intrinsic value of options exercised	31	75	10
Total fair value of options that have vested	101	143	101
Total options vested	2.0 million	2.1 million	2.1 million

As at December 31, 2020, the aggregate intrinsic value of the total options exercisable was $5 million and the aggregate intrinsic value of options outstanding was $5 million.

Shareholder Rights Plan

TC Energy's Shareholder Rights Plan is designed to provide the Board of Directors with sufficient time to explore and develop alternatives for maximizing shareholder value in the event of a takeover offer for the Company and to encourage the fair treatment of shareholders in connection with any such offer. Attached to each common share is one right that, under certain circumstances, entitles certain holders to purchase an additional common share of the Company.

PREFERRED SHARES

12 Months Ended

Dec. 31, 2020

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

PREFERRED SHARES


at December 31, 2020	Number of Shares Outstanding	Current Yield			Annual Dividend Per Share1,2	Redemption Price Per Share	Redemption and Conversion Option Date	Right to Convert Into	Carrying Value December 313
									2020	2019	2018
	(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	233
Series 2	7,423	Floating		4	Floating	$25.00	December 31, 2024	Series 1	179	179	306
Series 3	9,997	1.694	%	5	$0.4235	$25.00	June 30, 2025	Series 4	246	209	209
Series 4	4,003	Floating		4	Floating	$25.00	June 30, 2025	Series 3	97	134	134
Series 5	12,714	2.263	%		$0.56575	$25.00	January 30, 2021	Series 6	310	310	310
Series 6	1,286	Floating		4	Floating	$25.00	January 30, 2021	Series 5	32	32	32
Series 7	24,000	3.903	%	6	$0.97575	$25.00	April 30, 2024	Series 8	589	589	589
Series 9	18,000	3.762	%	6	$0.9405	$25.00	October 30, 2024	Series 10	442	442	442
Series 11	10,000	3.351	%	7	$0.83775	$25.00	November 28, 2025	Series 12	244	244	244
Series 13	20,000	5.50	%		$1.375	$25.00	May 31, 2021	Series 14	493	493	493
Series 15	40,000	4.90	%		$1.225	$25.00	May 31, 2022	Series 16	988	988	988
									3,980	3,980	3,980

1Each 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), 4.69 per cent (Series 14) or 3.85 per cent (Series 16). These rates reset quarterly with the then current T-Bill rate.

2The 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), 4.69 per cent, subject to a minimum of 5.50 per cent (Series 13) or 3.85 per cent, subject to a minimum of 4.90 per cent (Series 15).

3Net of underwriting commissions and deferred income taxes.

4The floating quarterly dividend rate for the Series 2 preferred shares is 2.029 per cent for the period starting December 31, 2020 to, but excluding, March 31, 2021. The floating quarterly dividend rate for the Series 4 preferred shares is 1.389 per cent for the period starting December 31, 2020 to, but excluding, March 31, 2021. The floating quarterly dividend rate for the Series 6 preferred shares is 1.676 per cent for the period starting October 30, 2020 to, but excluding, January 30, 2021. These rates will reset each quarter going forward.

5The fixed rate dividend for Series 3 preferred shares decreased from 2.152 per cent to 1.694 per cent on June 30, 2020 and is due to reset on every fifth anniversary thereafter.

6No Series 7 or 9 preferred shares were converted on the April 30, 2019 or October 30, 2019 conversion option dates, respectively. The fixed rate dividend decreased for Series 7 from 4.00 per cent to 3.903 per cent on April 30, 2019 and for Series 9 from 4.250 per cent to 3.762 per cent on October 30, 2019, and are due to reset on every fifth anniversary thereafter.

7No Series 11 were converted on the November 30, 2020 conversion option date. The fixed rate dividend for Series 11 preferred shares decreased from 3.8 per cent to 3.351 per cent on November 30, 2020 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 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 (LOSS) / INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCI)

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

OTHER COMPREHENSIVE INCOME / (LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCI)

OTHER COMPREHENSIVE (LOSS)/ INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCI)

Components of other comprehensive (loss)/ income, including the portion attributable to non-controlling interests and related tax effects, were as follows:


year ended December 31, 2020	Before Tax Amount	Income Tax Recovery/(Expense)	Net of Tax Amount
(millions of Canadian $)

Foreign currency translation 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 losses on net investment in foreign operations	(914)	(30)	(944)
Reclassification to net income 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)


year ended December 31, 2018	Before Tax Amount	Income Tax Recovery/(Expense)	Net of Tax Amount
(millions of Canadian $)

Foreign currency translation gains on net investment in foreign operations	1,323	35	1,358

Change in fair value of net investment hedges	(57)	15	(42)
Change in fair value of cash flow hedges	(14)	4	(10)
Reclassification to net income of gains and losses on cash flow hedges	27	(6)	21
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(153)	39	(114)
Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans	20	(5)	15
Other comprehensive income on equity investments	113	(27)	86
Other Comprehensive Income	1,259	55	1,314

The changes in AOCI by component were as follows:


	Currency Translation Adjustments	Cash Flow Hedges	Pension and Other Post-Retirement Benefit Plan Adjustments	Equity Investments	Total1

AOCI balance at January 1, 2018	(1,043)	(31)	(203)	(454)	(1,731)
Other comprehensive income /(loss) before reclassifications2	1,150	(9)	(114)	72	1,099
Amounts reclassified from AOCI	—	16	15	12	43
Net current period other comprehensive income /(loss)	1,150	7	(99)	84	1,142
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform	—	1	(12)	(6)	(17)
AOCI balance at December 31, 2018	107	(23)	(314)	(376)	(606)
Other comprehensive loss before reclassifications2	(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 reclassifications2	(543)	(567)	12	(292)	(1,390)
Amounts reclassified from AOCI3	—	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)

1All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

2In 2020, other comprehensive (loss)/ income before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling interest losses of $30 million (2019 – $85 million losses; 2018 – $166 million gains), losses of $16 million (2019 – $13 million losses; 2018 – $1 million losses) and gains of $1 million (2019 – $1 million losses; 2018 – nil), respectively.

3Losses 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 $37 million ($28 million, net of tax) at December 31, 2020. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

Details about reclassifications out of AOCI into the Consolidated statement of income were as follows:


	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statement of Income1
year ended December 31	2020	2019	2018
(millions of Canadian $)

Cash flow hedges
Commodities	(1)	(7)	(4)	Revenues (Power and Storage)
Interest rate	(28)	(12)	(18)	Interest expense
Interest rate	(613)	—	—	Net (loss)/ gain on assets sold/held for sale2
	(642)	(19)	(22)	Total before tax
	160	5	6	Income tax expense
	(482)	(14)	(16)	Net of tax3
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial losses	(23)	(14)	(16)	Plant operating costs and other4
Settlement charge	—	—	(4)	Plant operating costs and other4
	(23)	(14)	(20)	Total before tax
	6	4	5	Income tax expense
	(17)	(10)	(15)	Net of tax
Equity investments
Equity income	(15)	(8)	(16)	Income from equity investments
	4	3	4	Income tax expense
	(11)	(5)	(12)	Net of tax3
Currency translation adjustments
Foreign currency translation gains on disposal of foreign operations	—	13	—	Net (loss)/ gain on assets sold/held for sale
	—	—	—	Income tax expense
	—	13	—	Net of tax

1Amounts in parentheses indicate expenses to the Consolidated statement of income.

2Represents 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 27, Acquisitions and dispositions, for additional information.

3Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest losses of $7 million (2019 – nil; 2018 – $5 million gains) and nil (2019 – nil; 2018 – $2 million gains), respectively.

4These AOCI components are included in the computation of net benefit cost. Refer to Note 24, Employee post-retirement benefits, for additional information.

EMPLOYEE POST-RETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2020

Retirement Benefits [Abstract]

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 consecutive years of employment. Effective January 1, 2019, there were certain amendments made to the Canadian DB Plan for new members whereby, subsequent to that date, benefits provided for these new members are based on years of service and highest average earnings over five consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index. The Company's U.S. DB Plan is closed to non-union new entrants and all non-union hires participate in the DC Plan. Net actuarial gains or losses are amortized out of AOCI over the EARSL of plan participants, which is approximately nine years at December 31, 2020 (2019 and 2018 – nine years).

The Company also provides its employees with savings plans in Canada and Mexico, DC Plans consisting of a 401(k) Plan in the U.S. and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Net actuarial gains or losses for the plans are amortized out of AOCI over the EARSL of employees, which was approximately 11 years at December 31, 2020 (2019 – 11 years; 2018 – 12 years). In 2020, the Company expensed $58 million (2019 – $61 million; 2018 – $59 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	2020	2019	2018
(millions of Canadian $)

DB Plans	124	122	103
Other post-retirement benefit plans	9	22	23
Savings and DC Plans	58	61	59
	191	205	185

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 $13 million letter of credit to the Canadian DB Plan in 2020 (2019 – $12 million; 2018 – $17 million), resulting in a total of $302 million provided to the Canadian DB Plan under letters of credit at December 31, 2020.

The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2020 and the next required valuation will be as at January 1, 2021.

In December 2018, the Company recorded a settlement resulting from lump sum payments made in 2018 to certain terminated non-union vested participants in the Company's U.S. DB Plan related to voluntary cash settlement options available to these participants. The impact of the settlement was determined using assumptions consistent with those employed at December 31, 2017. The settlement reduced the Company's U.S. DB Plan's unrealized actuarial losses by $4 million, which was included in OCI, and resulted in a settlement charge of $4 million which was recorded in net benefit costs in 2018. Effective December 1, 2018, the plan was amended to include this unlimited lump sum payment option for certain union employees who were not previously eligible.

The Company's funded status at December 31 was comprised of the following:


at December 31	Pension Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2020	2019	2020	2019

Change in Benefit Obligation1
Benefit obligation – beginning of year	4,058	3,653	427	430
Service cost	155	126	6	5
Interest cost	133	142	14	17
Employee contributions	6	5	—	—
Benefits paid	(249)	(213)	(21)	(24)
Actuarial loss	242	394	36	13


Foreign exchange rate changes	(19)	(49)	(5)	(14)
Benefit obligation – end of year	4,326	4,058	457	427
Change in Plan Assets
Plan assets at fair value – beginning of year	3,693	3,321	406	376
Actual return on plan assets	485	505	56	52
Employer contributions2	124	122	9	22
Employee contributions	6	5	—	—
Benefits paid	(249)	(212)	(21)	(24)

Foreign exchange rate changes	(21)	(48)	(9)	(20)
Plan assets at fair value – end of year	4,038	3,693	441	406
Funded Status – Plan Deficit	(288)	(365)	(16)	(21)

1The 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.

2Excludes a $13 million letter of credit provided to the Canadian DB Plan for funding purposes (2019 – $12 million).

The actuarial loss realized on the defined benefit plan obligation is primarily attributable to a decrease in the weighted average discount rate from 3.20 per cent in 2019 to 2.70 per cent in 2020.

The actuarial loss realized on the other post-retirement benefit plan obligation is primarily due to the decrease in the weighted average discount rate from 3.35 per cent in 2019 to 2.75 per cent in 2020.

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 Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2020	2019	2020	2019

Other long-term assets (Note 13)	29	—	178	162
Accounts payable and other	—	—	(8)	(8)
Other long-term liabilities (Note 16)	(317)	(365)	(186)	(175)
	(288)	(365)	(16)	(21)

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 Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2020	2019	2020	2019

Projected benefit obligation1	(3,292)	(4,058)	(194)	(182)
Plan assets at fair value	2,975	3,693	—	—
Funded Status – Plan Deficit	(317)	(365)	(194)	(182)

1The 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	2020	2019
(millions of Canadian $)

Accumulated benefit obligation	(3,957)	(3,719)
Plan assets at fair value	4,038	3,693
Funded Status – Plan Surplus /(Deficit)	81	(26)

Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of DB Plans that were not fully funded:


at December 31
(millions of Canadian $)	20201	2019

Accumulated benefit obligation	—	(2,397)
Plan assets at fair value	—	2,351
Funded Status – Plan Deficit	—	(46)

1The Company's DB Plans with respect to the accumulated benefit obligation and fair value of plan assets were fully funded at December 31, 2020.

The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:


	Percentage of Plan Assets				Target Allocations
at December 31	2020		2019		2020

Debt securities	33	%	32	%	25% to 45%
Equity securities	57	%	58	%	35% to 65%
Alternatives	10	%	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 Plan Assets
(millions of Canadian $)	2020	2019	2020		2019

Debt securities	13	9	0.3	%	0.2	%
Equity securities	5	15	0.1	%	0.4	%

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 25, Risk management and financial instruments.


at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $)	2020	2019	2020	2019	2020	2019	2020	2019	2020	2019

Asset Category
Cash and Cash Equivalents	87	58	—	—	—	—	87	58	2	1
Equity Securities:
Canadian	276	402	177	189	—	—	453	591	10	14
U.S.	594	523	211	156	—	—	805	679	18	17
International	114	46	380	320	—	—	494	366	11	9
Global	116	136	368	297	—	—	484	433	11	11
Emerging	35	8	125	126	—	—	160	134	4	3
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	207	198	—	—	207	198	5	5
Provincial	—	—	283	246	—	—	283	246	6	6
Municipal	—	—	13	12	—	—	13	12	—	—
Corporate	—	—	151	125	—	—	151	125	3	3
U.S. Bonds:
Federal	444	421	14	7	—	—	458	428	10	11

Municipal	—	—	2	1	—	—	2	1	—	—
Corporate	72	67	143	120	—	—	215	187	5	5
International:
Government	8	7	6	4	—	—	14	11	—	—
Corporate	—	—	48	52	—	—	48	52	1	1
Mortgage backed	47	46	4	7	—	—	51	53	1	1
Other Investments:
Real estate	—	—	—	—	213	196	213	196	5	5
Infrastructure	—	—	—	—	203	181	203	181	5	4
Private equity funds	—	—	—	—	1	2	1	2	—	—
Derivatives	—	—	(8)	—	—	—	(8)	—	—	—
Funds held on deposit	145	146	—	—	—	—	145	146	3	4
	1,938	1,860	2,124	1,860	417	379	4,479	4,099	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, 2018			362
Purchases and sales			35
Realized and unrealized losses			(18)
Balance at December 31, 2019			379
Purchases and sales			42
Realized and unrealized losses			(4)
Balance at December 31, 2020			417

The Company's expected funding contributions in 2021 are approximately $128 million for the DB Plans, approximately $6 million for the other post-retirement benefit plans and approximately $59 million for the savings plans and DC Plans. The Company expects to provide an additional estimated $13 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

2021	208	25
2022	210	25
2023	213	25
2024	215	25
2025	217	25
2026 to 2030	1,115	120

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, 2020. 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:


	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31	2020		2019		2020		2019

Discount rate	2.70	%	3.20	%	2.75	%	3.35	%
Rate of compensation increase	2.60	%	3.00	%	—		—

The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows:


	Pension Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2020		2019		2018		2020		2019		2018

Discount rate	3.20	%	3.90	%	3.60	%	3.35	%	4.10	%	3.70	%
Expected long-term rate of return on plan assets	6.40	%	6.60	%	6.70	%	3.50	%	4.30	%	4.00	%
Rate of compensation increase	3.00	%	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 6.30 per cent weighted-average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2021 measurement purposes. The rate was assumed to decrease gradually to 4.80 per cent by 2028 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:


at December 31	Pension Benefit Plans			Other Post-Retirement Benefit Plans
(millions of Canadian $)	2020	2019	2018	2020	2019	2018

Service cost1	155	126	121	6	5	4
Other components of net benefit cost1
Interest cost	133	142	134	14	17	14
Expected return on plan assets	(230)	(222)	(221)	(14)	(15)	(16)
Amortization of actuarial loss	21	12	15	2	2	1

Amortization of regulatory asset	25	14	18	2	2	—



Settlement charge – AOCI	—	—	4	—	—	—
	(51)	(54)	(50)	4	6	(1)
Net Benefit Cost Recognized	104	72	71	10	11	3

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:


	2020		2019		2018
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)




Net loss	358	22	398	20	364	53

Pre-tax amounts recognized in OCI were as follows:


	2020		2019		2018
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)

Amortization of net loss from AOCI to net income	(21)	(2)	(12)	(2)	(15)	(1)


Settlement	—	—	—	—	(4)	—
Funded status adjustment	(18)	3	52	(37)	110	43
	(39)	1	40	(39)	91	42

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 55
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=118257860&loc=d3e4179-114921

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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2020

Risk Management and Financial Instruments [Abstract]

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 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 and internal audit 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-term 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 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 exposure to commodity price risk 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 generation business, TC Energy manages the exposure to fluctuating commodity prices through long-term contracts and hedging activities including selling and purchasing power 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.

In May 2019, TC Energy sold its remaining U.S. Power marketing contracts completing the divestiture of its U.S. Northeast power business which began in 2017, greatly reducing its exposure to electricity price risk.

Interest rate risk

TC Energy utilizes short-term 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 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 LIBOR, of which certain rate settings may cease to be published at the end of 2021 with full cessation expected by mid-2023. The Company continues to monitor developments and is preparing to address any necessary system and contractual changes while assessing the adoption of the standard market proposed reference rates.

Foreign exchange risk

TC Energy generates revenues and incurs expenses and capital expenditures that are denominated in currencies other than Canadian dollars. As a result, the Company's earnings and cash flows are exposed to currency fluctuations.

A significant portion of TC Energy's businesses generate earnings in U.S. dollars, but 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 two-year basis 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 hedges

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 swaps and foreign exchange options.

The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

2020

2019

at December 31

Fair
Value1,2

Notional Amount

Fair
Value1,2

Notional Amount

(millions of Canadian $, unless otherwise noted)

U.S. dollar foreign exchange options (maturing 2021)

US 2,200

US 3,000

U.S. dollar cross-currency interest rate swaps (maturing 2022 to 2025)3

US 400

US 100

US 2,600

US 3,100

1Fair value equals carrying value.

2No amounts have been excluded from the assessment of hedge effectiveness.

3In 2020, Net income includes net realized gains of $1 million (2019 – nil) 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

2020

2019

(millions of Canadian $, unless otherwise noted)

Notional amount

27,700 (US 21,800)

29,300 (US 22,600)

Fair value

33,800 (US 26,500)

33,400 (US 25,700)

Counterparty Credit Risk

TC Energy's exposure to counterparty credit risk consists of its cash and cash equivalents, accounts receivable, 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 of and communication with those counterparties experiencing greater financial pressures due to recent market events.

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, 2020 and 2019, 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, Other current assets, Loan receivable from affiliate, Restricted investments, Other long-term assets, Notes payable, Accounts payable and other, Redeemable non-controlling interest, 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:


	2020		2019
at December 31	Carrying Amount	Fair Value	Carrying Amount	Fair Value
(millions of Canadian $)

Long-term debt, including current portion1,2 (Note 18)	(36,885)	(46,054)	(36,985)	(43,187)
Junior subordinated notes (Note 19)	(8,498)	(8,908)	(8,614)	(8,777)
	(45,383)	(54,962)	(45,599)	(51,964)

1Long-term debt is recorded at amortized cost, except for US$200 million at December 31, 2019 that was attributed to hedged risk and recorded at fair value.

2Net income in 2020 included unrealized losses of nil (2019 – losses of $3 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$200 million of long-term debt that matured in March 2020 (2019 – US$200 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

Available-for-Sale Assets Summary

The following tables summarize additional information about the Company's restricted investments that were classified as available-for-sale assets:


	2020		2019
at December 31	LMCI Restricted Investments	Other Restricted Investments1	LMCI Restricted Investments	Other Restricted Investments1
(millions of Canadian $)

Fair value of fixed income securities2,3
Maturing within 1 year	—	17	—	6
Maturing within 1-5 years	—	66	26	100
Maturing within 5-10 years	985	—	801	—
Maturing after 10 years	85	—	61	—
Fair value of equity securities2,4	736	—	556	—
	1,806	83	1,444	106

1Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.

2Available-for-sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet.

3Classified in Level II of the fair value hierarchy.

4Classified in Level I of the fair value hierarchy.


	2020		2019		2018
year ended December 31 (millions of Canadian $)	LMCI restricted investments1	Other restricted investments2	LMCI restricted investments1	Other restricted investments2	LMCI restricted investments1	Other restricted investments2

Net unrealized gains	130	1	32	3	11	—
Net realized gains /(losses)3	20	1	60	—	(4)	—

1Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities.

2Gains and losses on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income.

3Realized 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 as at December 31, 2020 was as follows:


at December 31, 2020	Cash Flow Hedges	Net Investment Hedges	Held for Trading	Total Fair Value of Derivative Instruments1
(millions of Canadian $)

Other current assets (Note 6)
Commodities2	—	—	13	13
Foreign exchange	—	47	175	222

	—	47	188	235
Other long-term assets (Note 13)

Foreign exchange	—	22	19	41

	—	22	19	41
Total Derivative Assets	—	69	207	276

Accounts payable and other (Note 15)
Commodities2	(8)	—	(32)	(40)
Foreign exchange	—	(1)	(10)	(11)
Interest rate3	(21)	—	—	(21)
	(29)	(1)	(42)	(72)
Other long-term liabilities (Note 16)
Commodities2	(6)	—	(4)	(10)

Interest rate3	(49)	—	—	(49)
	(55)	—	(4)	(59)
Total Derivative Liabilities	(84)	(1)	(46)	(131)
Total Derivatives	(84)	68	161	145

1Fair value equals carrying value.

2Includes purchases and sales of power, natural gas and liquids.

3For 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 balance sheet classification of the fair value of derivative instruments as at December 31, 2019 was as follows:


at December 31, 2019	Cash Flow Hedges	Fair Value Hedges	Net Investment Hedges	Held for Trading	Total Fair Value of Derivative Instruments1
(millions of Canadian $)

Other current assets (Note 6)
Commodities2	—	—	—	118	118
Foreign exchange	—	—	10	61	71
Interest rate	—	1	—	—	1
	—	1	10	179	190
Other long-term assets (Note 13)

Foreign exchange	—	—	5	—	5
Interest rate	2	—	—	—	2
	2	—	5	—	7
Total Derivative Assets	2	1	15	179	197

Accounts payable and other (Note 15)
Commodities2	(4)	—	—	(104)	(108)
Foreign exchange	—	—	(1)	(3)	(4)
Interest rate	(3)	—	—	—	(3)
	(7)	—	(1)	(107)	(115)
Other long-term liabilities (Note 16)
Commodities2	(6)	—	—	(11)	(17)
Foreign exchange	—	—	(1)	—	(1)
Interest rate	(63)	—	—	—	(63)
	(69)	—	(1)	(11)	(81)
Total Derivative Liabilities	(76)	—	(2)	(118)	(196)
Total Derivatives	(74)	1	13	61	1

1Fair value equals carrying value.

2Includes purchases and sales of power, natural gas and liquids.

The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk.

Derivatives in fair value hedging relationships

The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities:


at December 31		Carrying amount				Fair value hedging adjustments1
(millions of Canadian $)	2020		2019		2020		2019


Long-term debt		—		(260)		—		(1)

1At December 31, 2020 and 2019, adjustments for discontinued hedging relationships included in these balances were nil.

Notional and Maturity Summary

The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations was as follows:


at December 31, 2020	Power	Natural Gas	Liquids	Foreign Exchange	Interest Rate

Purchases1	185	13	26	—	—
Sales1	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

1Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.


at December 31, 2019	Power	Natural Gas	Liquids	Foreign Exchange	Interest Rate

Purchases1	492	14	39	—	—
Sales1	2,089	22	53	—	—
Millions of U.S. dollars	—	—	—	3,153	1,600
Millions of Mexican pesos	—	—	—	800	—
Maturity dates	2020-2024	2020-2027	2020	2020	2020-2030

1Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.

Unrealized and Realized (Losses)/ Gains on Derivative Instruments

The following summary does not include hedges of the net investment in foreign operations:


year ended December 31	2020	2019	2018
(millions of Canadian $)

Derivative instruments held for trading1
Amount of unrealized (losses)/ gains in the year
Commodities	(23)	(111)	28
Foreign exchange	126	245	(248)
Amount of realized gains /(losses) in the year
Commodities	183	378	351
Foreign exchange	(33)	(70)	(24)
Derivative instruments in hedging relationships2
Amount of realized gains /(losses) in the year
Commodities	6	(6)	(1)
Interest rate	(16)	2	(1)

1Realized 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.

2In 2020, 2019 and 2018, 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 23) 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	2020	2019	2018
(millions of Canadian $, pre-tax)

Change in fair value of derivative instruments recognized in OCI1
Commodities	(5)	(15)	(1)

Interest rate	(766)	(63)	(13)
	(771)	(78)	(14)

1No 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	2020	2019	2018
(millions of Canadian $)




Fair Value Hedges
Interest rate contracts1
Hedged items	(3)	(19)	(71)
Derivatives designated as hedging instruments	1	1	(4)
Cash Flow Hedges
Reclassification of losses on derivative instruments from AOCI to net income2,3
Interest rate contracts1	(648)	(12)	(22)
Commodity contracts4	(1)	(7)	(5)

1Presented within Interest expense in the Consolidated statement of income, except for a loss of $613 million 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 is included in Net (loss)/ gain on assets sold/held for sale. Refer to Note 27, Acquisitions and dispositions, for additional information.

2Refer to Note 23, Other comprehensive (loss)/ income 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.

3There are no amounts recognized in earnings that were excluded from effectiveness testing.

4Presented 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, 2020	Gross Derivative Instruments	Amounts Available for Offset1	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)

1Amounts available for offset do not include cash collateral pledged or received.


at December 31, 2019	Gross Derivative Instruments	Amounts Available for Offset1	Net Amounts
(millions of Canadian $)

Derivative instrument assets
Commodities	118	(76)	42
Foreign exchange	76	(5)	71
Interest rate	3	(1)	2
	197	(82)	115
Derivative instrument liabilities
Commodities	(125)	76	(49)
Foreign exchange	(5)	5	—
Interest rate	(66)	1	(65)
	(196)	82	(114)

1Amounts 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 $54 million and letters of credit of $15 million at December 31, 2020 (2019 – $58 million and $25 million, respectively) to its counterparties. At December 31, 2020, the Company held no cash collateral and no letters of credit (2019 – 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, 2020, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $4 million (2019 – $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, 2020, 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, 2020	Quoted Prices in Active Markets (Level I)	Significant Other Observable Inputs (Level II)1	Significant Unobservable Inputs (Level III)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

1There were no transfers from Level II to Level III for the year ended December 31, 2020.


at December 31, 2019	Quoted Prices in Active Markets (Level I)	Significant Other Observable Inputs (Level II)1	Significant Unobservable Inputs (Level III)1	Total
(millions of Canadian $)

Derivative instrument assets
Commodities	81	37	—	118
Foreign exchange	—	76	—	76
Interest rate	—	3	—	3
Derivative instrument liabilities
Commodities	(77)	(41)	(7)	(125)
Foreign exchange	—	(5)	—	(5)
Interest rate	—	(66)	—	(66)
	4	4	(7)	1

1There were no transfers from Level II to Level III for the year ended December 31, 2019.

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)	2020	2019

Balance at beginning of year	(7)	(4)
Transfers out of Level III	—	4
Total gains /(losses) included in Net income	3	(3)
Total losses included in OCI	—	(4)



Balance at end of year1	(4)	(7)

1Revenues include unrealized gains of $3 million attributed to derivatives in the Level III category that were still held at December 31, 2020 (2019 – unrealized losses of $3 million).

CHANGES IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2020

CHANGES IN OPERATING WORKING CAPITAL

CHANGES IN OPERATING WORKING CAPITAL


year ended December 31	2020	2019	2018
(millions of Canadian $)

Decrease /(increase) in Accounts receivable	129	31	(69)
Increase in Inventories	(55)	(42)	(49)

(Increase)/ decrease in Other current assets	(221)	(15)	45
(Decrease)/ increase in Accounts payable and other	(162)	352	(70)
(Decrease)/ increase in Accrued interest	(18)	(33)	41

(Increase)/ Decrease in Operating Working Capital	(327)	293	(102)

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
ACQUISITIONS AND DISPOSITIONS	Dec. 31, 2020
Business Combinations [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS Canadian Natural Gas Pipelines Coastal GasLink LP On May 22, 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 includes $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 incorporates 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 reflects the utilization of previously unrecognized tax loss benefits. The pre-tax gain is included in Net (loss)/ gain on assets sold/held for sale in the Consolidated statement of income. As part of this transaction, TC Energy has been 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. In conjunction with the equity sale, Coastal GasLink LP entered into secured long-term project financing credit facilities with a current total capacity of $6.8 billion to fund the majority of the construction costs of Coastal GasLink. Immediately preceding the equity sale, Coastal GasLink LP drew down $1.6 billion on the facilities, of which approximately $1.5 billion was paid to TC Energy. Along with this sale, TC Energy has provided an opportunity to the 20 First Nations that have executed agreements with Coastal GasLink LP to invest in the project through an option to acquire a 10 per cent equity interest. 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 is not deductible for income tax purposes. The pre-tax gain is included in Net (loss)/ gain 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 is included in Net (loss)/ gain on assets sold/held for sale in the Consolidated statement of income. On an after-tax basis, the gain of $115 million reflects 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. TC Energy remains the operator of the Northern Courier pipeline and uses the equity method to account for its remaining 15 per cent interest in the Company’s consolidated financial statements. Power and Storage TransCanada Turbines Ltd. On November 13, 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 On April 29, 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. Pre-tax losses of $414 million ($283 million after tax) were recognized on the sale in 2020 and reflect the finalization of post-closing obligations. The total pre-tax loss of $693 million ($477 million after tax) on this transaction includes losses accrued during 2019 while classified as an asset held for sale and the after-tax loss also reflects utilization of previously unrecognized tax loss benefits. The pre-tax loss is included in Net (loss)/ gain on assets sold/held 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 December 2018, the Company entered into an agreement to sell its Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC (SWG). Salt River Project Agriculture Improvement and Power District (SRP), the PPA counterparty, subsequently exercised its contractual right of first refusal (ROFR) on a sale to a third party and the Company terminated the agreement with SWG. In May 2019, the Company completed the sale to SRP, as per the terms of their ROFR, 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 is included in Net (loss)/ gain on assets sold/held for sale in the Consolidated statement of income. Cartier Wind In October 2018, the Company completed the sale of its 62 per cent interest in the Cartier Wind power facilities to Innergex Renewable Energy Inc. for proceeds of $630 million before post-closing adjustments. As a result, the Company recorded a gain on sale of $170 million ($143 million after tax) which is included in Net (loss)/ gain on assets sold/held for sale in the Consolidated statement of income.

COMMITMENTS, CONTINGENCIES AND GUARANTEES

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

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 2020 were $224 million (2019 – $236 million; 2018 – $207 million).

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, 2020, TC Energy had the following capital expenditure commitments:

•approximately $0.9 billion for its Canadian natural gas pipelines, primarily related to construction costs associated with NGTL System expansion projects

•approximately $0.3 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with ANR and Columbia Gulf pipeline projects

•approximately $0.2 billion for its Mexico natural gas pipelines, primarily related to construction of the Tula and Villa de Reyes pipeline projects

•approximately $0.9 billion for its Liquids pipelines, primarily related to the construction of Keystone XL

•approximately $0.3 billion for its Power and Storage business, primarily related to the Company's proportionate share of commitments for Bruce Power's life extension program.

Acquisition of common units of TC PipeLines, LP

On December 14, 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. Pursuant to the agreement, TC PipeLines, LP common unitholders will receive 0.70 common shares of TC Energy for each issued and outstanding publicly-held TC PipeLines, LP common unit. The exchange ratio reflects an equivalent of approximately 38 million TC Energy common shares for all publicly-held common units of TC PipeLines, LP. A vote on the plan of merger by the unitholders of the publicly-held common units is scheduled for February 26, 2021. The transaction is expected to close in late first quarter 2021 subject to approval by the holders of a majority of outstanding common units of TC PipeLines, LP and customary regulatory approvals.

If the transaction closes, the expected changes in the Company's ownership interest in TC PipeLines, LP will be accounted for as an equity transaction as the Company will continue to control TC PipeLines, LP and no gain or loss will be recognized in the Consolidated statement of income resulting from the transaction.

Contingencies

TC Energy is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2020, the Company had accrued approximately $24 million (2019 – $30 million) related to operating facilities, which represents the present value of the estimated future amount it expects to spend to remediate the sites. However, additional liabilities may be incurred as assessments take place and remediation efforts continue.

TC Energy and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. The amounts involved in such proceedings are not reasonably estimable as the final outcome of such legal proceedings cannot be predicted with certainty. It is the opinion of management that the ultimate resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.

Guarantees

As part of its role as operator of the Northern Courier pipeline, TC Energy has 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 and contractor and supplier services.

The Company and its partners in certain other jointly-owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to construction services and the payment of liabilities. For certain of these entities, any payments made by TC Energy under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

The carrying value of these guarantees has been recorded in Accounts payable and other and Other long-term liabilities on the Consolidated balance sheet. Information regarding the Company’s guarantees were as follows:


		2020		2019
at December 31	Term	Potential Exposure1	Carrying Value	Potential Exposure1	Carrying Value
(millions of Canadian $)

Northern Courier pipeline	to 2055	300	26	300	27
Sur de Texas	to 2021	100	—	109	—
Bruce Power	to 2023	88	—	88	—
Other jointly-owned entities	to 2043	78	4	100	10
		566	30	597	37

1TC Energy's share of the potential estimated current or contingent exposure.

VARIABLE INTEREST ENTITIES

12 Months Ended

Dec. 31, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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 $)	2020	2019

ASSETS
Current Assets
Cash and cash equivalents	254	106
Accounts receivable	61	88
Inventories	26	27
Other	11	8
	352	229
Plant, Property and Equipment	3,325	3,050
Equity Investments	714	785
Goodwill	424	431
Other Long-Term Assets	8	—
	4,823	4,495
LIABILITIES
Current Liabilities
Accounts payable and other	109	70
Redeemable non-controlling interest	633	—
Accrued interest	21	21
Current portion of long-term debt	579	187
	1,342	278
Regulatory Liabilities	60	45
Other Long-Term Liabilities	11	9
Deferred Income Tax Liabilities	12	9
Long-Term Debt	2,468	2,694
	3,893	3,035

Certain consolidated VIEs have a redeemable non-controlling interest that ranks above the Company's equity interest. Refer to Note 20, Redeemable non-controlling interest and non-controlling interests and Note 30, Subsequent events, 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 $)	2020	2019

Balance sheet
Equity investments
Bruce Power	3,306	3,256
Pipeline equity investments and other1	1,371	1,464
Off-balance sheet2
Bruce Power	1,183	1,521
Pipeline equity investments	1,506	425
Maximum exposure to loss	7,366	6,666

1 Includes equity investment in Portlands Energy Centre classified as Assets held for sale as at December 31, 2019 and sold on April 29, 2020. Refer to Note 27, Acquisitions and dispositions, for additional information.

2 Includes maximum potential exposure to guarantees plus future expected and contingent funding commitments.

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Dec. 31, 2020
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Columbia Pipeline Group, Inc. Debt Issuance On December 9, 2020, the Company's subsidiary, Columbia, entered into a US$4.2 billion Delayed Draw Term Loan due in June 2022, bearing interest at a floating rate. In January 2021, US$4.0 billion was drawn on the Delayed Draw Term Loan and the total availability under the loan agreement was reduced accordingly. Keystone XL Presidential Permit Revocation On January 20, 2021, U.S. President Biden revoked the Presidential Permit for the Keystone XL pipeline. As a result and as of this date, the Company suspended the advancement of the Keystone XL pipeline project while it assesses the implications of the revocation and considers its options along with its partner, the Government of Alberta, and other stakeholders. The Company ceased capitalizing costs, including interest during construction, and also ceased accruing a return on the Government of Alberta Class A Interests, effective January 20, 2021. The decision to suspend advancement of the Keystone XL pipeline also represents a triggering event under GAAP requiring the Company to evaluate the Keystone XL capitalized project costs for impairment. Given the uncertainty related to the Keystone XL project, the Company expects to record a predominantly non-cash impairment charge in first quarter 2021. The carrying value of plant, property and equipment for Keystone XL, including capitalized interest, was $2.8 billion at December 31, 2020. Accounting implications, in the first quarter of 2021 and beyond, will depend on the assessment and consideration of options as noted above, including the impacts that this has on contractual arrangements. As a result, the magnitude of the impairment charge and related recoveries cannot be quantified at this time. The following factors will be considered in determining the amount and timing of the impairment charge and related recoveries, although these will be dependent on future decisions and developments: •the viability of projects currently associated with the Keystone XL pipeline, including Heartland Pipeline, TC Terminals and Keystone Hardisty Terminal, is also being reviewed. The carrying value of these projects in Other long-term assets on the Consolidated balance sheet at December 31, 2020 was $0.2 billion •incremental liabilities incurred for contractual commitments •specified contractual recoveries •recoverable value of the project's tangible assets •income tax impact of the above items, including the assessment of any income tax valuation allowances and deferred income tax assets recorded at December 31, 2020. Any principal outstanding under the project-level credit facility is fully guaranteed by the Government of Alberta without recourse to the Company. The suspension of the advancement of the project does not require immediate repayment of the debt as repayment is dependent upon certain other events or decisions specified in the credit facility agreement. While the credit facility remains outstanding, the Company continues to be responsible for ongoing interest charges. For further discussion of subsequent events related to the project-level credit facility, refer to Note 20, Redeemable non-controlling interest and non-controlling interests.

ACCOUNTING POLICIES (Policies)	12 Months Ended
ACCOUNTING POLICIES (Policies)	Dec. 31, 2020
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. TC Energy records its proportionate share of undivided interests in certain assets. 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: •recoverability of plant, property and equipment (Notes 7 and 30) and development costs (Notes 13 and 30) •fair value of reporting units that contain goodwill (Notes 12 and 27) and •fair value of assets and liabilities acquired in a business combination (Note 27). 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: •depreciation rates of plant, property and equipment (Note 7) •determining whether a contract contains a lease (Note 8) •fair value of equity investments (Note 9) •carrying value of regulatory assets and liabilities (Note 11) •carrying value of asset retirement obligations (Note 16) •provisions for income taxes, including valuation allowances and releases (Note 17) •assumptions used to measure retirement and other post-retirement benefit obligations (Note 24) •fair value of financial instruments (Note 25) and •provisions for commitments, contingencies and guarantees (Note 28). 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. TC Energy's businesses that apply RRA currently include Canadian, U.S. and Mexico natural gas pipelines, 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	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. 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 regards 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 27, Acquisitions and dispositions, for additional information regarding the sale of the Columbia Midstream assets. Net revenues earned from the sale of proprietary natural gas are recognized in the month of delivery. 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. Net revenues earned from the sale of proprietary natural gas are recognized in the month of delivery. 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. Other Net revenues earned from the sale of proprietary crude oil are recognized in the month of delivery. Power and Storage Power Generation 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 earned from the sale of proprietary natural gas are recognized in the month of delivery. 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	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.
Assets Held for Sale	Assets Held for Sale The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a disposal group and expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, the asset is recorded at the lower of its carrying amount or its estimated fair value, net of selling costs, and any losses are recognized in net income. Gains related to the expected sale of these assets are not recognized until the transaction closes. Once an asset is classified as held for sale, depreciation expense is no longer recorded.
Plant, Property and Equipment 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 27, 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 On January 1, 2019, the Company adopted the FASB's new lease guidance using optional transition relief. Results reported for 2020 and 2019 reflect the application of the new guidance while the 2018 comparative results were prepared and reported under previous lease guidance. 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 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 facility and liquids tank terminals for which the Company is the lessor. Power Purchase ArrangementsA power purchase arrangement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis. TC Energy has PPAs for the sale of power that are accounted for as operating leases where TC Energy is the lessor.
Impairment of Long-Lived Assets and Financial Assets	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.
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. 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. Canadian income taxes are not provided 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, and •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. Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and expensed 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.
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 (loss)/ income (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. Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI until the operations are sold, at which time the gains and losses are reclassified to net income. Asset and liability accounts are translated at the period-end exchange rates while revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction. The Company's U.S. dollar-denominated debt and certain derivative hedging instruments have been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar-denominated debt and derivatives are also reflected in OCI.
Derivative Instruments and Hedging Activities	Derivative Instruments and Hedging Activities All derivative instruments are recorded on the Consolidated balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions. The Company applies hedge accounting to arrangements that qualify for and are designated for hedge accounting treatment. This includes fair value and cash flow hedges and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in net income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in net income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the change in the fair value of the hedging derivative is recognized in OCI. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. Termination payments on interest rate derivatives are classified as a financing activity on the Consolidated statement of cash flows. In hedging the foreign currency exposure of a net investment in a foreign operation, the foreign exchange gains and losses on the hedging instruments are recognized in OCI. The amounts recognized previously in AOCI are reclassified to net income in the event the Company reduces its net investment in a foreign operation. In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as regulatory assets or liabilities and are refunded to or collected from ratepayers in subsequent periods when the derivative settles. Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in net income.
Long-Term Debt Transaction Costs and Issuance Costs	Long-Term Debt Transaction Costs and Issuance Costs The Company records long-term debt transaction costs and issuance costs as a deduction from the carrying amount of the related debt liability and amortizes these costs using the effective interest method except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms.
Guarantees	Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of a partially-owned entity or by partially-owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments or Plant, property and equipment and a corresponding liability is recorded in Other long-term liabilities. The release from the obligation is recognized either over the term of the guarantee or upon expiration or settlement of the guarantee.
Accounting Changes	ACCOUNTING CHANGES Changes in Accounting Policies for 2020 Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment model of financial instruments, basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write-down of the amortized cost basis. The new guidance was effective January 1, 2020 and was applied using a modified retrospective approach. The adoption of this new guidance did not have a material impact on the Company's consolidated financial statements. Implementation costs of cloud computing arrangements In August 2018, the FASB issued new guidance requiring an entity in a hosting arrangement that is a service contract to follow the guidance for internal-use software to determine which implementation costs should be capitalized as an asset and which costs should be expensed. The guidance also requires the entity to amortize the capitalized implementation costs of a hosting arrangement over the term of the arrangement. This guidance was effective January 1, 2020 and was applied prospectively. The adoption of this new guidance did not have a material impact on the Company's consolidated financial statements. Consolidation In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance was effective January 1, 2020 and was applied on a retrospective basis. The adoption of this new guidance did not have an impact on the Company's consolidated financial statements. Defined benefit plans In August 2018, the FASB issued new guidance which amends and clarifies disclosure requirements related to defined benefit pension and other post-retirement benefit plans. This new guidance was effective for annual disclosure requirements at December 31, 2020 and applied on a retrospective basis. The adoption of this new guidance, which is limited to disclosures only, did not have a material impact on the Company's consolidated financial statements. Reference rate reform In response to the expected cessation of the London Interbank Offered Rate (LIBOR), of which certain rate settings may cease to be published at the end of 2021 with full cessation expected 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 is continuing to identify and analyze existing agreements to determine the effect of reference rate reform on its consolidated financial statements. The Company will continue to evaluate the timing and potential impact of adoption for other optional expedients when deemed necessary. Future Accounting Changes Income taxes In December 2019, the FASB issued new guidance that simplified the accounting for income taxes and clarified existing guidance. This new guidance is effective January 1, 2021, and is not expected to have a material impact on the Company's consolidated financial statements.

SEGMENTED INFORMATION (Tables)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment


year ended December 31, 2020	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines	Power and Storage	Corporate1		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 other3								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

1Includes intersegment eliminations.


year ended December 31, 2019	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines	Power and Storage	Corporate1		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 other3								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

1Includes intersegment eliminations.


year ended December 31, 2018	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines	Power and Storage	Corporate1		Total
(millions of Canadian $)

Revenues	4,038	4,314	619	2,584	2,124	—		13,679
Intersegment revenues	—	162	—	—	56	(218)	2	—
	4,038	4,476	619	2,584	2,180	(218)		13,679
Income from equity investments	12	256	22	64	355	5	3	714
Plant operating costs and other	(1,405)	(1,368)	(34)	(630)	(315)	159	2	(3,593)
Commodity purchases resold	—	—	—	—	(1,486)	—		(1,486)
Property taxes	(266)	(199)	—	(98)	(6)	—		(569)
Depreciation and amortization	(1,129)	(664)	(97)	(341)	(119)	—		(2,350)
Goodwill and other asset impairment charges	—	(801)	—	—	—	—		(801)
Net gain on sale of assets	—	—	—	—	170	—		170
Segmented earnings /(losses)	1,250	1,700	510	1,579	779	(54)		5,764
Interest expense								(2,265)
Allowance for funds used during construction								526
Interest income and other3								(76)
Income before income taxes								3,949
Income tax expense								(432)
Net income								3,517
Net loss attributable to non-controlling interests								185
Net income attributable to controlling interests								3,702
Preferred share dividends								(163)
Net income attributable to common shares								3,539

Capital spending
Capital expenditures	2,442	5,591	463	110	767	45		9,418
Capital projects in development	36	1	—	459	—	—		496
Contributions to equity investments	—	179	334	12	490	—		1,015
	2,478	5,771	797	581	1,257	45		10,929

1Includes intersegment eliminations.


at December 31	2020	2019
(millions of Canadian $)

Total Assets by segment
Canadian Natural Gas Pipelines	22,852	21,983
U.S. Natural Gas Pipelines	43,217	41,627
Mexico Natural Gas Pipelines	7,215	7,207
Liquids Pipelines	16,744	15,931
Power and Storage	5,062	7,788
Corporate	5,210	4,743
	100,300	99,279

Revenue from External Customers by Geographic Areas


year ended December 31	2020	2019	2018
(millions of Canadian $)

Revenues
Canada – domestic	4,392	4,059	4,187
Canada – export	1,059	1,035	1,075
United States	6,832	7,558	7,798
Mexico	716	603	619
	12,999	13,255	13,679

Schedule of Long-Lived Assets by Country


at December 31	2020	2019
(millions of Canadian $)

Plant, Property and Equipment
Canada	24,092	23,362
United States	39,698	36,184
Mexico	5,985	5,943
	69,775	65,489

REVENUES (Tables)

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenues


year ended December 31, 2020	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	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 other1	61	654	109	3	106	933
	4,469	4,955	716	2,209	298	12,647
Other revenues2,3	—	76	—	162	114	352
	4,469	5,031	716	2,371	412	12,999

3Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income taxes, for additional information.


year ended December 31, 2019	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	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 revenues1,2	—	83	—	452	50	585
	4,010	4,978	603	2,879	785	13,255

2Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income taxes, for additional information.


year ended December 31, 2018	Canadian Natural Gas Pipelines	U.S. Natural Gas Pipelines	Mexico Natural Gas Pipelines	Liquids Pipelines	Power and Storage	Total
(millions of Canadian $)

Revenues from contracts with customers
Capacity arrangements and transportation	4,038	3,549	614	2,079	—	10,280
Power generation	—	—	—	—	1,771	1,771
Natural gas storage and other	—	654	5	3	81	743
	4,038	4,203	619	2,082	1,852	12,794
Other revenues1,2	—	111	—	502	272	885
	4,038	4,314	619	2,584	2,124	13,679

2Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income taxes, for additional information.

Contract Balances


at December 31	2020	2019	Affected line item on Consolidated balance sheet
(millions of Canadian $)

Receivables from contracts with customers	1,330	1,458	Accounts receivable
Contract assets (Note 6)	132	153	Other current assets
Long-term contract assets (Note 13)	192	102	Other long-term assets
Contract liabilities1 (Note 15)	129	61	Accounts payable and other
Long-term contract liabilities (Note 16)	203	226	Other long-term liabilities

1During the year ended December 31, 2020, $18 million (2019 – $6 million) of revenues were recognized that were included in contract liabilities at the beginning of the year.

OTHER CURRENT ASSETS (Tables)

12 Months Ended

Dec. 31, 2020

Other Assets [Abstract]

Schedule of Other Current Assets


at December 31	2020	2019
(millions of Canadian $)

Fair value of derivative contracts (Note 25)	235	190
Cash provided as collateral	142	52
Contract assets (Note 5)	132	153
Regulatory assets (Note 11)	131	43
Prepaid expenses	126	60
Other	114	129
	880	627

PLANT, PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Schedule of Plant, Property and Equipment


	2020			2019
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)

Canadian Natural Gas Pipelines
NGTL System
Pipeline	14,190	5,278	8,912	11,556	4,846	6,710
Compression	5,421	1,906	3,515	4,205	1,771	2,434
Metering and other	1,393	648	745	1,296	609	687
	21,004	7,832	13,172	17,057	7,226	9,831
Under construction	1,402	—	1,402	3,181	—	3,181
	22,406	7,832	14,574	20,238	7,226	13,012
Canadian Mainline
Pipeline	10,297	7,443	2,854	10,145	7,109	3,036
Compression	3,930	3,000	930	3,867	2,823	1,044
Metering and other	637	239	398	643	219	424
	14,864	10,682	4,182	14,655	10,151	4,504
Under construction	150	—	150	60	—	60
	15,014	10,682	4,332	14,715	10,151	4,564
Other Canadian Natural Gas Pipelines1
Other	1,885	1,508	377	1,861	1,455	406
Under construction2	42	—	42	1,276	—	1,276
	1,927	1,508	419	3,137	1,455	1,682
	39,347	20,022	19,325	38,090	18,832	19,258
U.S. Natural Gas Pipelines
Columbia Gas
Pipeline	10,198	557	9,641	9,708	389	9,319
Compression	4,287	276	4,011	4,094	206	3,888
Metering and other	3,388	185	3,203	3,244	125	3,119
	17,873	1,018	16,855	17,046	720	16,326
Under construction	1,070	—	1,070	425	—	425
	18,943	1,018	17,925	17,471	720	16,751
ANR
Pipeline	1,685	512	1,173	1,594	472	1,122
Compression	2,146	489	1,657	2,050	436	1,614
Metering and other	1,289	388	901	1,245	355	890
	5,120	1,389	3,731	4,889	1,263	3,626
Under construction	431	—	431	252	—	252
	5,551	1,389	4,162	5,141	1,263	3,878


	2020			2019
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)

Other U.S. Natural Gas Pipelines
Columbia Gulf	2,638	151	2,487	2,597	114	2,483
GTN	2,330	1,008	1,322	2,257	969	1,288
Great Lakes	2,117	1,223	894	2,090	1,208	882

Other3	1,568	578	990	1,530	616	914
	8,653	2,960	5,693	8,474	2,907	5,567
Under construction	389	—	389	164	—	164
	9,042	2,960	6,082	8,638	2,907	5,731
	33,536	5,367	28,169	31,250	4,890	26,360
Mexico Natural Gas Pipelines
Pipeline	2,952	411	2,541	2,988	340	2,648
Compression	480	69	411	486	54	432
Metering and other	624	133	491	643	124	519
	4,056	613	3,443	4,117	518	3,599
Under construction	2,525	—	2,525	2,321	—	2,321
	6,581	613	5,968	6,438	518	5,920
Liquids Pipelines
Keystone Pipeline System
Pipeline	9,254	1,579	7,675	9,378	1,403	7,975
Pumping equipment	1,025	228	797	1,035	204	831
Tanks and other	3,522	644	2,878	3,488	556	2,932
	13,801	2,451	11,350	13,901	2,163	11,738
Under construction4	2,870	—	2,870	47	—	47
	16,671	2,451	14,220	13,948	2,163	11,785
Intra-Alberta Pipelines
Pipeline	142	6	136	138	2	136

Tanks and other	56	3	53	56	2	54
	198	9	189	194	4	190




	16,869	2,460	14,409	14,142	2,167	11,975
Power and Storage

Natural Gas	1,255	569	686	1,256	522	734

Natural Gas Storage and Other	780	194	586	742	181	561
	2,035	763	1,272	1,998	703	1,295
Under construction	11	—	11	6	—	6
	2,046	763	1,283	2,004	703	1,301
Corporate	993	372	621	883	208	675
	99,372	29,597	69,775	92,807	27,318	65,489

1Includes Foothills, Ventures LP and Great Lakes Canada.

3Includes Portland, North Baja, Tuscarora, Crossroads and mineral rights.

LEASES (Tables)

12 Months Ended

Dec. 31, 2020

Leases [Abstract]

Operating Lease Cost and Other Information

Operating lease cost was as follows:


year ended December 31
(millions of Canadian $)	2020	2019

Operating lease cost1	124	117
Sublease income	(13)	(11)
Net operating lease cost	111	106

1 Includes short-term leases and variable lease costs.

Net rental expense on operating leases in 2018 was $84 million.

Other information related to operating leases is noted in the following tables:


year ended December 31
(millions of Canadian $)	2020	2019

Cash paid for amounts included in the measurement of operating lease liabilities	77	76
ROU assets obtained in exchange for new operating lease liabilities	14	9


at December 31	2020		2019

Weighted average remaining lease term	10 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 $)	2020	2019

Accounts payable and other	56	56
Other long-term liabilities (Note 16)	427	476
	483	532

Maturities of Operating Lease Liabilities

Maturities of operating lease liabilities are as follows:


(millions of Canadian $)	2020	2019

Less than one year	72	73
One to two years	61	69
Two to three years	59	59
Three to four years	58	58
Four to five years	54	57
More than five years	269	323
Total operating lease payments	573	639
Imputed interest	(90)	(107)
Operating lease liabilities	483	532

Future Lease Payments to be Received Under Operating Leases

Future lease payments to be received under operating leases are as follows:


(millions of Canadian $)	2020	2019

Less than one year	119	123
One to two years	111	116
Two to three years	109	111
Three to four years	109	109
Four to five years	94	109
More than five years	70	164
	612	732

EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2020

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Investments


(millions of Canadian $)	Ownership Interest at December 31, 2020		Income /(Loss) from Equity Investments			Equity Investments
			year ended December 31			at December 31
			2020	2019	2018	2020	2019

Canadian Natural Gas Pipelines
TQM1	50.0	%	12	12	12	90	79
Coastal GasLink1,2	35.0	%	—	—	—	211	—
U.S. Natural Gas Pipelines
Northern Border3	50.0	%	100	91	87	521	549
Millennium	47.5	%	96	92	75	482	496
Iroquois4	50.0	%	52	54	60	197	241
Pennant Midstream5	nil		—	12	17	—	—
Other	Various		16	15	17	120	112
Mexico Natural Gas Pipelines
Sur de Texas6	60.0	%	213	3	27	680	600
Liquids Pipelines
Grand Rapids1,7	50.0	%	53	56	65	998	1,028
Northern Courier1,8	15.0	%	22	14	—	53	62
HoustonLink Pipeline1	50.0	%	—	—	(1)	19	19
Power and Storage
Bruce Power1,9	48.4	%	439	527	311	3,306	3,256
Portlands Energy Centre1,10	nil		12	35	36	—	—
TransCanada Turbines11	100.0	%	4	9	8	—	64
			1,019	920	714	6,677	6,506

1Classified as a non-consolidated VIE. Refer to Note 29, Variable interest entities, for additional information.

Summarized Financial Information of Equity Investments


year ended December 31	2020	2019	2018
(millions of Canadian $)

Income
Revenues	5,838	5,693	4,836
Operating and other expenses	(3,341)	(3,408)	(3,545)
Net income	2,047	1,990	1,515
Net income attributable to TC Energy	1,019	920	714


at December 31	2020	2019
(millions of Canadian $)

Balance Sheet
Current assets	2,911	2,305
Non-current assets	26,957	21,865
Current liabilities	(3,727)	(2,060)
Non-current liabilities	(15,309)	(11,461)

LOANS RECEIVABLE FROM AFFILIATES (Tables)

12 Months Ended

Dec. 31, 2020

Receivables [Abstract]

Schedule of Loan Receivable Interest Income and Foreign Exchange Impact


year ended December 31				Affected line item in the Consolidated statement of income
(millions of Canadian $)	2020	2019	2018

Interest income1	110	147	120	Interest income and other
Interest expense2	(110)	(147)	(120)	Income from equity investments
Foreign exchange (losses)/ gains1	(86)	53	(5)	Interest income and other
Foreign exchange gains /(losses)1	86	(53)	5	Income from equity investments

1Included in the Corporate segment.

2Included in the Mexico Natural Gas Pipelines segment.

RATE-REGULATED BUSINESSES (Tables)

12 Months Ended

Dec. 31, 2020

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities


at December 31	2020	2019	Remaining Recovery/ Settlement Period (years)
(millions of Canadian $)

Regulatory Assets
Deferred income taxes1	1,287	1,088	n/a
Operating and debt-service regulatory assets2	54	2	1
Pensions and other post-retirement benefits1,3	401	417	n/a
Foreign exchange on long-term debt1,4	7	16	1-9
Other	135	107	n/a
	1,884	1,630
Less: Current portion included in Other current assets (Note 6)	131	43
	1,753	1,587
Regulatory Liabilities

Operating and debt-service regulatory liabilities2	48	139	1
Pensions and other post-retirement benefits3	18	35	n/a
ANR-related post-employment and retirement benefits other than pension5	40	41	n/a
Long-term adjustment account6,7	227	660	6
Bridging amortization account6	537	428	10
Pipeline abandonment trust balances8	1,842	1,462	n/a
Cost of removal9	246	253	n/a
Deferred income taxes1	115	151	n/a
Deferred income taxes – U.S. Tax Reform10	1,170	1,239	n/a
Other	58	60	n/a
	4,301	4,468
Less: Current portion included in Accounts payable and other (Note 15)	153	696
	4,148	3,772

2Operating 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.

6These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll-stabilization adjustments during the 2015-2030 settlement term.

7Under the terms of the 2021-2026 Mainline Settlement, $223 million will be amortized over the six-year settlement term and the residual of $4 million will be transferred to the STAA.

8This 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.

GOODWILL (Tables)

12 Months Ended

Dec. 31, 2020

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 Gas Pipelines

Balance at January 1, 2019			14,178
Sale of Columbia Midstream assets			(595)
Foreign exchange rate changes			(696)
Balance at December 31, 2019			12,887

Foreign exchange rate changes			(208)
Balance at December 31, 2020			12,679

OTHER LONG-TERM ASSETS (Tables)

12 Months Ended

Dec. 31, 2020

Intangible Assets, Net (Excluding Goodwill) [Abstract]

Schedule of Other Long-Term Assets


at December 31	2020	2019
(millions of Canadian $)

Capital projects in development	231	1,715
Employee post-retirement benefits (Note 24)	207	162
Long-term contract assets (Note 5)	192	102
Deferred income tax assets (Note 17)	177	37
Fair value of derivative contracts (Note 25)	41	7
Other	131	145
	979	2,168

NOTES PAYABLE (Tables)

12 Months Ended

Dec. 31, 2020

Short-term Debt [Abstract]

Schedule of Notes Payable


	2020			2019
(millions of Canadian $, unless otherwise noted)	Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31		Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31

Canada1	2,836	0.4	%	4,034	2.1	%
U.S. (2020 – US$900; 2019 – nil)	1,149	0.4	%	—	—
Mexico (2020 – US$150; 2019 – US$205)2	191	1.7	%	266	2.7	%
	4,176			4,300

Schedule of Credit Facilities

These unsecured credit facilities included the following:

at December 31

(billions of Canadian $, unless otherwise noted)

2020

2019

Borrower

Description

Matures

Total Facilities

Unused Capacity 1

Total Facilities

Committed, syndicated, revolving, extendible, senior unsecured credit facilities2:

TCPL

Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes

December 2024

3.0

2.3

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 2021

US 4.5

US 1.9

US 4.5

TCPL/TCPL USA/Columbia/TransCanada American Investments Ltd.

For general corporate purposes of the borrowers, guaranteed by TCPL

December 2022

US 1.0

Demand senior unsecured revolving credit facilities2:

TCPL/TCPL USA

Supports the issuance of letters of credit and provides additional liquidity; TCPL USA facility guaranteed by TCPL

Demand

2.1

1.1

2.1

Mexico subsidiary

For Mexico general corporate purposes, guaranteed by TCPL

Demand

MXN5.0

MXN2.0

MXN5.0

1Net of commercial paper outstanding and facility draws.

3Or the U.S. dollar equivalent.

ACCOUNTS PAYABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2020

Payables and Accruals [Abstract]

Schedule of Accounts Payable and Other


at December 31	2020	2019
(millions of Canadian $)

Trade payables	3,057	3,314
Regulatory liabilities (Note 11)	153	696
Contract liabilities (Note 5)	129	61
Fair value of derivative contracts (Note 25)	72	115


Other	405	358
	3,816	4,544

OTHER LONG-TERM LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2020

Deferred Costs, Noncurrent [Abstract]

Schedule of Other Long-Term Liabilities


at December 31	2020	2019
(millions of Canadian $)

Employee post-retirement benefits (Note 24)	503	540
Operating lease obligations (Note 8)	427	476
Long-term contract liabilities (Note 5)	203	226
Fair value of derivative contracts (Note 25)	59	81
Asset retirement obligations	54	62
Guarantees	30	32
Other	199	197
	1,475	1,614

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Schedule of Provision for Income Taxes


year ended December 31	2020	2019	2018
(millions of Canadian $)

Current
Canada	(54)	84	65
Foreign1	306	615	250
	252	699	315
Deferred
Canada	(224)	(29)	49
Foreign	166	84	235
Foreign – U.S. Tax Reform and 2018 FERC Actions	—	—	(167)
	(58)	55	117
Income Tax Expense	194	754	432

Schedule of Geographic Components of Income


year ended December 31	2020	2019	2018
(millions of Canadian $)

Canada	691	1,144	433
Foreign	4,416	4,043	3,516
Income before Income Taxes	5,107	5,187	3,949

Reconciliation of Income Tax Expense


year ended December 31	2020		2019		2018
(millions of Canadian $)

Income before income taxes	5,107		5,187		3,949
Federal and provincial statutory tax rate	24.0	%	26.5	%	27.0	%
Expected income tax expense	1,226		1,375		1,066
Valuation allowance releases	(400)		(259)		—
Foreign income tax rate differentials	(258)		(180)		(432)
Income tax differential related to regulated operations	(228)		(159)		(54)
(Income)/ loss from non-controlling interests and equity investments	(141)		(78)		50
Alberta tax rate reduction	—		(32)		—
Non-taxable portion of capital gains	(62)		(28)		(11)
Non-deductible goodwill on the Columbia Midstream asset disposition	—		154		—
U.S. Tax Reform and 2018 FERC Actions	—		—		(167)


Other	57		(39)		(20)
Income Tax Expense	194		754		432

Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet


at December 31	2020	2019
(millions of Canadian $)

Deferred Income Tax Assets
Tax loss and credit carryforwards	1,389	1,046
Regulatory and other deferred amounts	532	692
Difference in accounting and tax bases of impaired assets and assets held for sale	537	538
Unrealized foreign exchange losses on long-term debt	154	260
Financial instruments	48	23
Other	70	70
	2,730	2,629
Less: Valuation allowance	243	673
	2,487	1,956
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment	6,661	6,197
Equity investments	1,087	1,087
Taxes on future revenue requirement	287	232
Other	81	106
	8,116	7,622
Net Deferred Income Tax Liabilities	5,629	5,666

The above deferred tax amounts have been classified on the Consolidated balance sheet as follows:


at December 31	2020	2019
(millions of Canadian $)

Deferred Income Tax Assets
Other long-term assets (Note 13)	177	37
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,806	5,703
Net Deferred Income Tax Liabilities	5,629	5,666

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	2020	2019	2018
(millions of Canadian $)

Unrecognized tax benefit at beginning of year	29	19	15
Gross increases – tax positions in prior years	26	13	13
Gross decreases – tax positions in prior years	(2)	(1)	(5)
Gross increases – tax positions in current year	1	—	—

Lapse of statutes of limitations	(2)	(2)	(4)
Unrecognized Tax Benefit at End of Year	52	29	19

LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Schedule of Long-Term Debt


		2020			2019
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate1		Outstanding at December 31	Interest Rate1
(millions of Canadian $, unless otherwise noted)

TRANSCANADA PIPELINES LIMITED
Debentures
Canadian		—	—		250	11.8	%
U.S. (2020 and 2019 – US$400)	2021	510	9.9	%	518	9.9	%
Medium Term Notes
Canadian	2021 to 2049	11,491	4.5	%	9,491	4.6	%
Senior Unsecured Notes
U.S. (2020 – US$14,292; 2019 – US$14,792)	2022 to 2049	18,227	5.3	%	19,174	5.2	%
		30,228			29,433
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian	2024	100	9.9	%	100	9.9	%
U.S. (2020 and 2019 – US$200)	2023	255	7.9	%	259	7.9	%
Medium Term Notes
Canadian	2025 to 2030	504	7.4	%	504	7.4	%
U.S. (2020 and 2019 – US$33)	2026	42	7.5	%	42	7.5	%
		901			905
COLUMBIA PIPELINE GROUP, INC.
Senior Unsecured Notes
U.S. (2020 – US$1,500; 2019 – US$2,250)2	2025 to 2045	1,913	4.9	%	2,916	4.4	%
TC PIPELINES, LP


Unsecured Term Loan
U.S. (2020 and 2019 – US$450)	2022	574	1.4	%	583	2.9	%
Senior Unsecured Notes
U.S. (2020 and 2019 – US$1,200)	2021 to 2027	1,530	4.4	%	1,556	4.4	%
		2,104			2,139
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2020 and 2019 – US$672)	2021 to 2026	858	7.2	%	872	7.2	%
GAS TRANSMISSION NORTHWEST LLC


Senior Unsecured Notes
U.S. (2020 - US$325; 2019 – US$250)	2030 to 2035	415	4.3	%	324	5.6	%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2020 – US$198; 2019 – US$219)	2021 to 2030	253	7.6	%	284	7.7	%


		2020			2019
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate1		Outstanding at December 31	Interest Rate1
(millions of Canadian $, unless otherwise noted)
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Unsecured Loan Facility
U.S. (2020 – US$25; 2019 – US$39)	2023	32	1.3	%	51	3.0	%
Senior Unsecured Notes
U.S. (2020 – US$125 ; 2019 – nil)	2030	159	2.8	%	—	—
		191			51
TUSCARORA GAS TRANSMISSION COMPANY
Unsecured Term Loan
U.S. (2020 and 2019 – US$23)	2021	29	2.2	%	30	2.8	%
NORTH BAJA PIPELINE, LLC
Unsecured Term Loan
U.S. (2020 and 2019 – US$50)	2021	64	1.2	%	65	2.8	%
		36,956			37,019
Current portion of long-term debt		(1,972)			(2,705)
Unamortized debt discount and issue costs		(238)			(228)
Fair value adjustments3		167			194
		34,913			34,280

The Company issued long-term debt over the three years ended December 31, 2020 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Issue Date

Type

Maturity Date

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

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

April 2019

Medium Term Notes

October 2049

1,000

4.34

October 2018

Senior Unsecured Notes

March 2049

US 1,000

5.10

October 2018

Senior Unsecured Notes

May 2028

US 400

4.25

July 2018

Medium Term Notes

July 2048

800

4.18

July 2018

Medium Term Notes

March 2028

200

3.39

May 2018

Senior Unsecured Notes

May 2028

US 1,000

4.25

May 2018

Senior Unsecured Notes

May 2048

US 1,000

4.875

May 2018

Senior Unsecured Notes

May 2038

US 500

4.75

PORTLAND NATURAL GAS TRANSMISSION SYSTEM

October 2020

Senior Unsecured Notes

October 2030

US 125

2.84

April 2018

Unsecured Loan Facility

April 2023

US 19

Floating

GAS TRANSMISSION NORTHWEST LLC

June 2020

Senior Unsecured Notes

June 2030

US 175

3.12

COASTAL GASLINK PIPELINE LIMITED PARTNERSHIP4

April 2020

Senior Secured Credit Facilities

April 2027

1,603

Floating

NORTHERN COURIER PIPELINE LIMITED PARTNERSHIP5

July 2019

Senior Secured Notes

June 2042

1,000

3.365

NORTH BAJA PIPELINE, LLC

December 2018

Unsecured Term Loan

December 2021

US 50

Floating

1Reflects 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 3.991 per cent.

2Reflects coupon rate on re-opening of a pre-existing senior unsecured notes issue. The notes were issued at a discount to par, resulting in a re-issuance yield of 4.439 per cent.

3Reflects coupon rate on re-opening of a pre-existing MTN issue. The MTNs were issued at a discount to par, resulting in a re-issuance yield of 3.41 per cent.

Schedule of Repayments of Long-Term Debt

At December 31, 2020, principal repayments for the next five years on the Company's long-term debt are approximately as follows:


(millions of Canadian $)	2021	2022	2023	2024	2025

Principal repayments on long-term debt	1,972	1,901	1,861	286	2,712

Schedule of Retired Long-Term Debt

The Company retired/repaid long-term debt over the three years ended December 31, 2020 as follows:

(millions of Canadian $, unless otherwise noted)

Company

Retirement/Repayment Date

Type

Amount

Interest Rate

TRANSCANADA PIPELINES LIMITED

November 2020

Debentures

250

11.80

October 2020

Senior Unsecured Notes

US 1,000

3.80

March 20201

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

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

August 2018

Senior Unsecured Notes

US 850

6.50

March 2018

Debentures

150

9.45

January 2018

Senior Unsecured Notes

US 500

1.875

January 2018

Senior Unsecured Notes

US 250

Floating

PORTLAND NATURAL GAS TRANSMISSION SYSTEM

October 2020

Unsecured Loan Facility

US 99

Floating

May 2018

Senior Secured Notes

US 18

5.90

COLUMBIA PIPELINE GROUP, INC.

June 2020

Senior Unsecured Notes

US 750

3.30

June 2018

Senior Unsecured Notes

US 500

2.45

GAS TRANSMISSION NORTHWEST LLC

June 2020

Senior Unsecured Notes

US 100

5.29

May 2019

Unsecured Term Loan

US 35

Floating

TC PIPELINES, LP

June 2019

Unsecured Term Loan

US 50

Floating

December 2018

Unsecured Term Loan

US 170

Floating

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

March 2018

Senior Unsecured Notes

US 9

6.73

1Related 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.

Schedule of Interest Expense


year ended December 31	2020	2019	2018
(millions of Canadian $)

Interest on long-term debt	1,963	1,931	1,877
Interest on junior subordinated notes	470	427	391
Interest on short-term debt	46	106	73
Capitalized interest	(294)	(186)	(124)
Amortization and other financial charges1	43	55	48
	2,228	2,333	2,265

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

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-SubTopic 10
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+ Details

JUNIOR SUBORDINATED NOTES (Tables)

12 Months Ended

Dec. 31, 2020

Junior Subordinated Notes [Abstract]

Schedule of Junior Subordinated Notes


		2020			2019
Outstanding loan amount	Maturity Date	Outstanding at December 31	Effective Interest Rate1		Outstanding at December 31	Effective Interest Rate1
(millions of Canadian $, unless otherwise noted)

TRANSCANADA PIPELINES LIMITED
US$1,000 notes issued 2007 at 6.35%2	2067	1,275	4.1	%	1,296	5.1	%
US$750 notes issued 2015 at 5.875%3,4	2075	957	5.0	%	972	6.0	%
US$1,200 notes issued 2016 at 6.125%3,4	2076	1,530	5.8	%	1,556	6.7	%
US$1,500 notes issued 2017 at 5.55%3,4	2077	1,913	4.7	%	1,944	5.7	%
$1,500 notes issued 2017 at 4.90%3,4	2077	1,500	4.5	%	1,500	5.4	%
US$1,100 notes issued 2019 at 5.75%3,4	2079	1,403	5.4	%	1,426	6.3	%
		8,578			8,694
Unamortized debt discount and issue costs		(80)			(80)
		8,498			8,614

1The 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.

4The coupon rate is initially a fixed interest rate for the first 10 years and converts to a floating rate thereafter.

REDEEMABLE NON-CONTROLLING INTERESTS AND NON-CONTROLLING INTERESTS (Tables)

12 Months Ended

Dec. 31, 2020

Noncontrolling Interest [Abstract]

Schedule of Redeemable Non-controlling Interest

The changes in Redeemable non-controlling interest classified in mezzanine equity were as follows:


year ended December 31			2020
(millions of Canadian $)

Balance at beginning of year			—
Class A Interests issued			1,033
Net loss attributable to redeemable non-controlling interest1			(10)
Class A Interests transferred to Current liabilities			(630)
Balance at end of year			393

Schedule of Non-controlling Interests

The Company's Non-controlling interests included on the Consolidated balance sheet were as follows:


at December 31	2020	2019
(millions of Canadian $)

Non-controlling interests in TC PipeLines, LP	1,682	1,634

The Company's Net income /(loss) attributable to non-controlling interests included in the Consolidated statement of income were as follows:


year ended December 31	2020	2019	2018
(millions of Canadian $)

Non-controlling interests in TC PipeLines, LP	307	293	(185)
Redeemable non-controlling interest	(10)	—	—


	297	293	(185)

COMMON SHARES (Tables)

12 Months Ended

Dec. 31, 2020

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, 2018	881,376	21,167
At-the-market equity issuance program1	20,050	1,118
Dividend reinvestment and share purchase plan	15,937	855
Exercise of options	734	34
Outstanding at December 31, 2018	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

1Net of issue costs and deferred income taxes.

Schedule of Weighted Average Shares


Weighted Average Common Shares Outstanding
(millions)	2020	2019	2018

Basic	940	929	902
Diluted	940	931	903

Schedule of Stock Options Activity


	Number of Options (thousands)	Weighted Average Exercise Prices	Weighted Average Remaining Contractual Life (years)

Options outstanding at January 1, 2020	9,094	$55.77
Options granted	1,714	$75.06
Options exercised	(1,664)	$54.47
Options forfeited/expired	(148)	$63.95
Options Outstanding at December 31, 2020	8,996	$59.55	3.8
Options Exercisable at December 31, 2020	5,395	$55.74	2.8

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	2020		2019		2018

Weighted average fair value	$7.73		$6.37		$5.80
Expected life (years)1	5.7		5.7		5.7
Interest rate	1.5	%	1.9	%	2.1	%
Volatility2	17	%	19	%	16	%
Dividend yield	4.2	%	5.0	%	4.2	%

1Expected life is based on historical exercise activity.

2Volatility 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	2020	2019	2018
(millions of Canadian $, unless otherwise noted)

Total intrinsic value of options exercised	31	75	10
Total fair value of options that have vested	101	143	101
Total options vested	2.0 million	2.1 million	2.1 million

PREFERRED SHARES (Tables)

12 Months Ended

Dec. 31, 2020

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Schedule of Preferred Shares


at December 31, 2020	Number of Shares Outstanding	Current Yield			Annual Dividend Per Share1,2	Redemption Price Per Share	Redemption and Conversion Option Date	Right to Convert Into	Carrying Value December 313
									2020	2019	2018
	(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	233
Series 2	7,423	Floating		4	Floating	$25.00	December 31, 2024	Series 1	179	179	306
Series 3	9,997	1.694	%	5	$0.4235	$25.00	June 30, 2025	Series 4	246	209	209
Series 4	4,003	Floating		4	Floating	$25.00	June 30, 2025	Series 3	97	134	134
Series 5	12,714	2.263	%		$0.56575	$25.00	January 30, 2021	Series 6	310	310	310
Series 6	1,286	Floating		4	Floating	$25.00	January 30, 2021	Series 5	32	32	32
Series 7	24,000	3.903	%	6	$0.97575	$25.00	April 30, 2024	Series 8	589	589	589
Series 9	18,000	3.762	%	6	$0.9405	$25.00	October 30, 2024	Series 10	442	442	442
Series 11	10,000	3.351	%	7	$0.83775	$25.00	November 28, 2025	Series 12	244	244	244
Series 13	20,000	5.50	%		$1.375	$25.00	May 31, 2021	Series 14	493	493	493
Series 15	40,000	4.90	%		$1.225	$25.00	May 31, 2022	Series 16	988	988	988
									3,980	3,980	3,980

3Net of underwriting commissions and deferred income taxes.

5The fixed rate dividend for Series 3 preferred shares decreased from 2.152 per cent to 1.694 per cent on June 30, 2020 and is due to reset on every fifth anniversary thereafter.

- Definition

Tabular disclosure of an entity's stock, including par or stated value per share, number and dollar amount of share subscriptions, shares authorized, shares issued, shares outstanding, number and dollar amount of shares held in an employee trust, dividend per share, total dividends, share conversion features, par value plus additional paid in capital, the value of treasury stock and other information necessary to a fair presentation, and EPS information. Stock by class includes common, convertible, and preferred stocks which are not redeemable or redeemable solely at the option of the issuer. Includes preferred stock with redemption features that are solely within the control of the issuer and mandatorily redeemable stock if redemption is required to occur only upon liquidation or termination of the reporting entity. If more than one issue is outstanding, state the title of each issue and the corresponding dollar amount; dollar amount of any shares subscribed but unissued and the deduction of subscriptions receivable there from; number of shares authorized, issued, and outstanding.

+ References

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+ Details

OTHER COMPREHENSIVE (LOSS) / INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCI) (Tables)

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

Components of Other Comprehensive (Loss)/Income

Components of other comprehensive (loss)/ income, including the portion attributable to non-controlling interests and related tax effects, were as follows:


year ended December 31, 2020	Before Tax Amount	Income Tax Recovery/(Expense)	Net of Tax Amount
(millions of Canadian $)

Foreign currency translation 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 losses on net investment in foreign operations	(914)	(30)	(944)
Reclassification to net income 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)


year ended December 31, 2018	Before Tax Amount	Income Tax Recovery/(Expense)	Net of Tax Amount
(millions of Canadian $)

Foreign currency translation gains on net investment in foreign operations	1,323	35	1,358

Change in fair value of net investment hedges	(57)	15	(42)
Change in fair value of cash flow hedges	(14)	4	(10)
Reclassification to net income of gains and losses on cash flow hedges	27	(6)	21
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(153)	39	(114)
Reclassification to net income of actuarial gains and losses on pension and other post-retirement benefit plans	20	(5)	15
Other comprehensive income on equity investments	113	(27)	86
Other Comprehensive Income	1,259	55	1,314

Schedule of Changes in Accumulated Other Comprehensive Income

The changes in AOCI by component were as follows:


	Currency Translation Adjustments	Cash Flow Hedges	Pension and Other Post-Retirement Benefit Plan Adjustments	Equity Investments	Total1

AOCI balance at January 1, 2018	(1,043)	(31)	(203)	(454)	(1,731)
Other comprehensive income /(loss) before reclassifications2	1,150	(9)	(114)	72	1,099
Amounts reclassified from AOCI	—	16	15	12	43
Net current period other comprehensive income /(loss)	1,150	7	(99)	84	1,142
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform	—	1	(12)	(6)	(17)
AOCI balance at December 31, 2018	107	(23)	(314)	(376)	(606)
Other comprehensive loss before reclassifications2	(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 reclassifications2	(543)	(567)	12	(292)	(1,390)
Amounts reclassified from AOCI3	—	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)

1All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

Schedule of Reclassifications out of Accumulated Other Comprehensive Income

Details about reclassifications out of AOCI into the Consolidated statement of income were as follows:


	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statement of Income1
year ended December 31	2020	2019	2018
(millions of Canadian $)

Cash flow hedges
Commodities	(1)	(7)	(4)	Revenues (Power and Storage)
Interest rate	(28)	(12)	(18)	Interest expense
Interest rate	(613)	—	—	Net (loss)/ gain on assets sold/held for sale2
	(642)	(19)	(22)	Total before tax
	160	5	6	Income tax expense
	(482)	(14)	(16)	Net of tax3
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial losses	(23)	(14)	(16)	Plant operating costs and other4
Settlement charge	—	—	(4)	Plant operating costs and other4
	(23)	(14)	(20)	Total before tax
	6	4	5	Income tax expense
	(17)	(10)	(15)	Net of tax
Equity investments
Equity income	(15)	(8)	(16)	Income from equity investments
	4	3	4	Income tax expense
	(11)	(5)	(12)	Net of tax3
Currency translation adjustments
Foreign currency translation gains on disposal of foreign operations	—	13	—	Net (loss)/ gain on assets sold/held for sale
	—	—	—	Income tax expense
	—	13	—	Net of tax

1Amounts in parentheses indicate expenses to the Consolidated statement of income.

4These AOCI components are included in the computation of net benefit cost. Refer to Note 24, Employee post-retirement benefits, for additional information.

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)

12 Months Ended

Dec. 31, 2020

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	2020	2019	2018
(millions of Canadian $)

DB Plans	124	122	103
Other post-retirement benefit plans	9	22	23
Savings and DC Plans	58	61	59
	191	205	185

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 Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2020	2019	2020	2019

Change in Benefit Obligation1
Benefit obligation – beginning of year	4,058	3,653	427	430
Service cost	155	126	6	5
Interest cost	133	142	14	17
Employee contributions	6	5	—	—
Benefits paid	(249)	(213)	(21)	(24)
Actuarial loss	242	394	36	13


Foreign exchange rate changes	(19)	(49)	(5)	(14)
Benefit obligation – end of year	4,326	4,058	457	427
Change in Plan Assets
Plan assets at fair value – beginning of year	3,693	3,321	406	376
Actual return on plan assets	485	505	56	52
Employer contributions2	124	122	9	22
Employee contributions	6	5	—	—
Benefits paid	(249)	(212)	(21)	(24)

Foreign exchange rate changes	(21)	(48)	(9)	(20)
Plan assets at fair value – end of year	4,038	3,693	441	406
Funded Status – Plan Deficit	(288)	(365)	(16)	(21)

2Excludes a $13 million letter of credit provided to the Canadian DB Plan for funding purposes (2019 – $12 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 Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2020	2019	2020	2019

Other long-term assets (Note 13)	29	—	178	162
Accounts payable and other	—	—	(8)	(8)
Other long-term liabilities (Note 16)	(317)	(365)	(186)	(175)
	(288)	(365)	(16)	(21)

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 Benefit Plans		Other Post-Retirement Benefit Plans
(millions of Canadian $)	2020	2019	2020	2019

Projected benefit obligation1	(3,292)	(4,058)	(194)	(182)
Plan assets at fair value	2,975	3,693	—	—
Funded Status – Plan Deficit	(317)	(365)	(194)	(182)

1The 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	2020	2019
(millions of Canadian $)

Accumulated benefit obligation	(3,957)	(3,719)
Plan assets at fair value	4,038	3,693
Funded Status – Plan Surplus /(Deficit)	81	(26)

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for Plans Not Fully Funded

Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of DB Plans that were not fully funded:


at December 31
(millions of Canadian $)	20201	2019

Accumulated benefit obligation	—	(2,397)
Plan assets at fair value	—	2,351
Funded Status – Plan Deficit	—	(46)

1The Company's DB Plans with respect to the accumulated benefit obligation and fair value of plan assets were fully funded at December 31, 2020.

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:


	Percentage of Plan Assets				Target Allocations
at December 31	2020		2019		2020

Debt securities	33	%	32	%	25% to 45%
Equity securities	57	%	58	%	35% to 65%
Alternatives	10	%	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 Plan Assets
(millions of Canadian $)	2020	2019	2020		2019

Debt securities	13	9	0.3	%	0.2	%
Equity securities	5	15	0.1	%	0.4	%

Schedule of Plan Assets for DB Plans and Other Post-Retirement Benefits Measured at Fair Value


at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $)	2020	2019	2020	2019	2020	2019	2020	2019	2020	2019

Asset Category
Cash and Cash Equivalents	87	58	—	—	—	—	87	58	2	1
Equity Securities:
Canadian	276	402	177	189	—	—	453	591	10	14
U.S.	594	523	211	156	—	—	805	679	18	17
International	114	46	380	320	—	—	494	366	11	9
Global	116	136	368	297	—	—	484	433	11	11
Emerging	35	8	125	126	—	—	160	134	4	3
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	207	198	—	—	207	198	5	5
Provincial	—	—	283	246	—	—	283	246	6	6
Municipal	—	—	13	12	—	—	13	12	—	—
Corporate	—	—	151	125	—	—	151	125	3	3
U.S. Bonds:
Federal	444	421	14	7	—	—	458	428	10	11

Municipal	—	—	2	1	—	—	2	1	—	—
Corporate	72	67	143	120	—	—	215	187	5	5
International:
Government	8	7	6	4	—	—	14	11	—	—
Corporate	—	—	48	52	—	—	48	52	1	1
Mortgage backed	47	46	4	7	—	—	51	53	1	1
Other Investments:
Real estate	—	—	—	—	213	196	213	196	5	5
Infrastructure	—	—	—	—	203	181	203	181	5	4
Private equity funds	—	—	—	—	1	2	1	2	—	—
Derivatives	—	—	(8)	—	—	—	(8)	—	—	—
Funds held on deposit	145	146	—	—	—	—	145	146	3	4
	1,938	1,860	2,124	1,860	417	379	4,479	4,099	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, 2018			362
Purchases and sales			35
Realized and unrealized losses			(18)
Balance at December 31, 2019			379
Purchases and sales			42
Realized and unrealized losses			(4)
Balance at December 31, 2020			417

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

2021	208	25
2022	210	25
2023	213	25
2024	215	25
2025	217	25
2026 to 2030	1,115	120

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:


	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31	2020		2019		2020		2019

Discount rate	2.70	%	3.20	%	2.75	%	3.35	%
Rate of compensation increase	2.60	%	3.00	%	—		—

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:


	Pension Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2020		2019		2018		2020		2019		2018

Discount rate	3.20	%	3.90	%	3.60	%	3.35	%	4.10	%	3.70	%
Expected long-term rate of return on plan assets	6.40	%	6.60	%	6.70	%	3.50	%	4.30	%	4.00	%
Rate of compensation increase	3.00	%	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:


at December 31	Pension Benefit Plans			Other Post-Retirement Benefit Plans
(millions of Canadian $)	2020	2019	2018	2020	2019	2018

Service cost1	155	126	121	6	5	4
Other components of net benefit cost1
Interest cost	133	142	134	14	17	14
Expected return on plan assets	(230)	(222)	(221)	(14)	(15)	(16)
Amortization of actuarial loss	21	12	15	2	2	1

Amortization of regulatory asset	25	14	18	2	2	—



Settlement charge – AOCI	—	—	4	—	—	—
	(51)	(54)	(50)	4	6	(1)
Net Benefit Cost Recognized	104	72	71	10	11	3

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:


	2020		2019		2018
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)




Net loss	358	22	398	20	364	53

Schedule of the Pre-Tax Amounts Recognized in OCI

Pre-tax amounts recognized in OCI were as follows:


	2020		2019		2018
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)

Amortization of net loss from AOCI to net income	(21)	(2)	(12)	(2)	(15)	(1)


Settlement	—	—	—	—	(4)	—
Funded status adjustment	(18)	3	52	(37)	110	43
	(39)	1	40	(39)	91	42

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2020

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:

2020

2019

at December 31

Fair
Value1,2

Notional Amount

Fair
Value1,2

Notional Amount

(millions of Canadian $, unless otherwise noted)

U.S. dollar foreign exchange options (maturing 2021)

US 2,200

US 3,000

U.S. dollar cross-currency interest rate swaps (maturing 2022 to 2025)3

US 400

US 100

US 2,600

US 3,100

1Fair value equals carrying value.

2No amounts have been excluded from the assessment of hedge effectiveness.

3In 2020, Net income includes net realized gains of $1 million (2019 – nil) 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

2020

2019

(millions of Canadian $, unless otherwise noted)

Notional amount

27,700 (US 21,800)

29,300 (US 22,600)

Fair value

33,800 (US 26,500)

33,400 (US 25,700)

The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations was as follows:


at December 31, 2020	Power	Natural Gas	Liquids	Foreign Exchange	Interest Rate

Purchases1	185	13	26	—	—
Sales1	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

1Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.


at December 31, 2019	Power	Natural Gas	Liquids	Foreign Exchange	Interest Rate

Purchases1	492	14	39	—	—
Sales1	2,089	22	53	—	—
Millions of U.S. dollars	—	—	—	3,153	1,600
Millions of Mexican pesos	—	—	—	800	—
Maturity dates	2020-2024	2020-2027	2020	2020	2020-2030

1Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.

Schedule of Financial Instruments


	2020		2019
at December 31	Carrying Amount	Fair Value	Carrying Amount	Fair Value
(millions of Canadian $)

Long-term debt, including current portion1,2 (Note 18)	(36,885)	(46,054)	(36,985)	(43,187)
Junior subordinated notes (Note 19)	(8,498)	(8,908)	(8,614)	(8,777)
	(45,383)	(54,962)	(45,599)	(51,964)

1Long-term debt is recorded at amortized cost, except for US$200 million at December 31, 2019 that was attributed to hedged risk and recorded at fair value.

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:


	2020		2019
at December 31	LMCI Restricted Investments	Other Restricted Investments1	LMCI Restricted Investments	Other Restricted Investments1
(millions of Canadian $)

Fair value of fixed income securities2,3
Maturing within 1 year	—	17	—	6
Maturing within 1-5 years	—	66	26	100
Maturing within 5-10 years	985	—	801	—
Maturing after 10 years	85	—	61	—
Fair value of equity securities2,4	736	—	556	—
	1,806	83	1,444	106

1Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.

2Available-for-sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet.

3Classified in Level II of the fair value hierarchy.

4Classified in Level I of the fair value hierarchy.

The balance sheet classification of the fair value of derivative instruments as at December 31, 2020 was as follows:


at December 31, 2020	Cash Flow Hedges	Net Investment Hedges	Held for Trading	Total Fair Value of Derivative Instruments1
(millions of Canadian $)

Other current assets (Note 6)
Commodities2	—	—	13	13
Foreign exchange	—	47	175	222

	—	47	188	235
Other long-term assets (Note 13)

Foreign exchange	—	22	19	41

	—	22	19	41
Total Derivative Assets	—	69	207	276

Accounts payable and other (Note 15)
Commodities2	(8)	—	(32)	(40)
Foreign exchange	—	(1)	(10)	(11)
Interest rate3	(21)	—	—	(21)
	(29)	(1)	(42)	(72)
Other long-term liabilities (Note 16)
Commodities2	(6)	—	(4)	(10)

Interest rate3	(49)	—	—	(49)
	(55)	—	(4)	(59)
Total Derivative Liabilities	(84)	(1)	(46)	(131)
Total Derivatives	(84)	68	161	145

1Fair value equals carrying value.

2Includes purchases and sales of power, natural gas and liquids.

The balance sheet classification of the fair value of derivative instruments as at December 31, 2019 was as follows:


at December 31, 2019	Cash Flow Hedges	Fair Value Hedges	Net Investment Hedges	Held for Trading	Total Fair Value of Derivative Instruments1
(millions of Canadian $)

Other current assets (Note 6)
Commodities2	—	—	—	118	118
Foreign exchange	—	—	10	61	71
Interest rate	—	1	—	—	1
	—	1	10	179	190
Other long-term assets (Note 13)

Foreign exchange	—	—	5	—	5
Interest rate	2	—	—	—	2
	2	—	5	—	7
Total Derivative Assets	2	1	15	179	197

Accounts payable and other (Note 15)
Commodities2	(4)	—	—	(104)	(108)
Foreign exchange	—	—	(1)	(3)	(4)
Interest rate	(3)	—	—	—	(3)
	(7)	—	(1)	(107)	(115)
Other long-term liabilities (Note 16)
Commodities2	(6)	—	—	(11)	(17)
Foreign exchange	—	—	(1)	—	(1)
Interest rate	(63)	—	—	—	(63)
	(69)	—	(1)	(11)	(81)
Total Derivative Liabilities	(76)	—	(2)	(118)	(196)
Total Derivatives	(74)	1	13	61	1

1Fair value equals carrying value.

2Includes purchases and sales of power, natural gas and liquids.

Unrealized Gain (Loss) on Investments


	2020		2019		2018
year ended December 31 (millions of Canadian $)	LMCI restricted investments1	Other restricted investments2	LMCI restricted investments1	Other restricted investments2	LMCI restricted investments1	Other restricted investments2

Net unrealized gains	130	1	32	3	11	—
Net realized gains /(losses)3	20	1	60	—	(4)	—

2Gains and losses on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income.

3Realized gains and losses on the sale of LMCI restricted investments are determined using the average cost basis.

Realized Gain (Loss) on Investments


	2020		2019		2018
year ended December 31 (millions of Canadian $)	LMCI restricted investments1	Other restricted investments2	LMCI restricted investments1	Other restricted investments2	LMCI restricted investments1	Other restricted investments2

Net unrealized gains	130	1	32	3	11	—
Net realized gains /(losses)3	20	1	60	—	(4)	—

2Gains and losses on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income.

3Realized 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

Derivatives in fair value hedging relationships

The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities:


at December 31		Carrying amount				Fair value hedging adjustments1
(millions of Canadian $)	2020		2019		2020		2019


Long-term debt		—		(260)		—		(1)

1At December 31, 2020 and 2019, adjustments for discontinued hedging relationships included in these balances were nil.

The following summary does not include hedges of the net investment in foreign operations:


year ended December 31	2020	2019	2018
(millions of Canadian $)

Derivative instruments held for trading1
Amount of unrealized (losses)/ gains in the year
Commodities	(23)	(111)	28
Foreign exchange	126	245	(248)
Amount of realized gains /(losses) in the year
Commodities	183	378	351
Foreign exchange	(33)	(70)	(24)
Derivative instruments in hedging relationships2
Amount of realized gains /(losses) in the year
Commodities	6	(6)	(1)
Interest rate	(16)	2	(1)

2In 2020, 2019 and 2018, 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	2020	2019	2018
(millions of Canadian $)




Fair Value Hedges
Interest rate contracts1
Hedged items	(3)	(19)	(71)
Derivatives designated as hedging instruments	1	1	(4)
Cash Flow Hedges
Reclassification of losses on derivative instruments from AOCI to net income2,3
Interest rate contracts1	(648)	(12)	(22)
Commodity contracts4	(1)	(7)	(5)

3There are no amounts recognized in earnings that were excluded from effectiveness testing.

4Presented within Revenues (Power and Storage) in the Consolidated statement of income.

Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships


year ended December 31	2020	2019	2018
(millions of Canadian $, pre-tax)

Change in fair value of derivative instruments recognized in OCI1
Commodities	(5)	(15)	(1)

Interest rate	(766)	(63)	(13)
	(771)	(78)	(14)

1No 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, 2020	Gross Derivative Instruments	Amounts Available for Offset1	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)

1Amounts available for offset do not include cash collateral pledged or received.


at December 31, 2019	Gross Derivative Instruments	Amounts Available for Offset1	Net Amounts
(millions of Canadian $)

Derivative instrument assets
Commodities	118	(76)	42
Foreign exchange	76	(5)	71
Interest rate	3	(1)	2
	197	(82)	115
Derivative instrument liabilities
Commodities	(125)	76	(49)
Foreign exchange	(5)	5	—
Interest rate	(66)	1	(65)
	(196)	82	(114)

1Amounts 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, 2020	Gross Derivative Instruments	Amounts Available for Offset1	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)

1Amounts available for offset do not include cash collateral pledged or received.


at December 31, 2019	Gross Derivative Instruments	Amounts Available for Offset1	Net Amounts
(millions of Canadian $)

Derivative instrument assets
Commodities	118	(76)	42
Foreign exchange	76	(5)	71
Interest rate	3	(1)	2
	197	(82)	115
Derivative instrument liabilities
Commodities	(125)	76	(49)
Foreign exchange	(5)	5	—
Interest rate	(66)	1	(65)
	(196)	82	(114)

1Amounts 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, 2020	Quoted Prices in Active Markets (Level I)	Significant Other Observable Inputs (Level II)1	Significant Unobservable Inputs (Level III)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

1There were no transfers from Level II to Level III for the year ended December 31, 2020.


at December 31, 2019	Quoted Prices in Active Markets (Level I)	Significant Other Observable Inputs (Level II)1	Significant Unobservable Inputs (Level III)1	Total
(millions of Canadian $)

Derivative instrument assets
Commodities	81	37	—	118
Foreign exchange	—	76	—	76
Interest rate	—	3	—	3
Derivative instrument liabilities
Commodities	(77)	(41)	(7)	(125)
Foreign exchange	—	(5)	—	(5)
Interest rate	—	(66)	—	(66)
	4	4	(7)	1

1There were no transfers from Level II to Level III for the year ended December 31, 2019.

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)	2020	2019

Balance at beginning of year	(7)	(4)
Transfers out of Level III	—	4
Total gains /(losses) included in Net income	3	(3)
Total losses included in OCI	—	(4)



Balance at end of year1	(4)	(7)

1Revenues include unrealized gains of $3 million attributed to derivatives in the Level III category that were still held at December 31, 2020 (2019 – unrealized losses of $3 million).

CHANGES IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2020

CHANGES IN OPERATING WORKING CAPITAL

Schedule of changes in operating working capital


year ended December 31	2020	2019	2018
(millions of Canadian $)

Decrease /(increase) in Accounts receivable	129	31	(69)
Increase in Inventories	(55)	(42)	(49)

(Increase)/ decrease in Other current assets	(221)	(15)	45
(Decrease)/ increase in Accounts payable and other	(162)	352	(70)
(Decrease)/ increase in Accrued interest	(18)	(33)	41

(Increase)/ Decrease in Operating Working Capital	(327)	293	(102)

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Schedule of Guarantees


		2020		2019
at December 31	Term	Potential Exposure1	Carrying Value	Potential Exposure1	Carrying Value
(millions of Canadian $)

Northern Courier pipeline	to 2055	300	26	300	27
Sur de Texas	to 2021	100	—	109	—
Bruce Power	to 2023	88	—	88	—
Other jointly-owned entities	to 2043	78	4	100	10
		566	30	597	37

1TC Energy's share of the potential estimated current or contingent exposure.

VARIABLE INTEREST ENTITIES (Tables)

12 Months Ended

Dec. 31, 2020

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 $)	2020	2019

ASSETS
Current Assets
Cash and cash equivalents	254	106
Accounts receivable	61	88
Inventories	26	27
Other	11	8
	352	229
Plant, Property and Equipment	3,325	3,050
Equity Investments	714	785
Goodwill	424	431
Other Long-Term Assets	8	—
	4,823	4,495
LIABILITIES
Current Liabilities
Accounts payable and other	109	70
Redeemable non-controlling interest	633	—
Accrued interest	21	21
Current portion of long-term debt	579	187
	1,342	278
Regulatory Liabilities	60	45
Other Long-Term Liabilities	11	9
Deferred Income Tax Liabilities	12	9
Long-Term Debt	2,468	2,694
	3,893	3,035

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 $)	2020	2019

Balance sheet
Equity investments
Bruce Power	3,306	3,256
Pipeline equity investments and other1	1,371	1,464
Off-balance sheet2
Bruce Power	1,183	1,521
Pipeline equity investments	1,506	425
Maximum exposure to loss	7,366	6,666

2 Includes maximum potential exposure to guarantees plus future expected and contingent funding commitments.

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

DESCRIPTION OF TC ENERGY'S BUSINESS (Details)	12 Months Ended
DESCRIPTION OF TC ENERGY'S BUSINESS (Details)	Dec. 31, 2020 segment plant km mi Bcf
Segment Reporting Information [Line Items]
Number of business segments in which the entity operates (in segments) \| segment	5
Canadian Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) \| km	40,707
Investments of regulated natural gas pipelines (in miles) \| mi	25,294
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	4,946
Wholly owned and operated crude oil pipeline systems (in miles) \| mi	3,075
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)	12 Months Ended
ACCOUNTING POLICIES (Details)	Dec. 31, 2020
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) - CAD ($) $ in Millions	12 Months Ended
SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segmented information
Revenues	$ 12,999	$ 13,255	$ 13,679
Income from equity investments	1,019	920	714
Plant operating costs and other	(3,878)	(3,913)	(3,593)
Commodity purchases resold		(365)	(1,486)
Property taxes	(727)	(727)	(569)
Depreciation and amortization	(2,590)	(2,464)	(2,350)
Goodwill and other asset impairment charges	0	0	(801)
Net (loss)/ gain on assets sold/held for sale	(50)	(121)	170
Segmented earnings	6,773	6,585	5,764
Interest expense	(2,228)	(2,333)	(2,265)
Allowance for funds used during construction	349	475	526
Interest income and other	213	460	(76)
Income before Income Taxes	5,107	5,187	3,949
Income tax expense	(194)	(754)	(432)
Net Income	4,913	4,433	3,517
Net income attributable to non-controlling interests	(297)	(293)	185
Net Income Attributable to Controlling Interests	4,616	4,140	3,702
Preferred share dividends	(159)	(164)	(163)
Net Income Attributable to Common Shares	4,457	3,976	3,539
Capital spending
Capital expenditures	8,013	7,475	9,418
Capital projects in development	122	707	496
Contributions to equity investments	765	602	1,015
Capital spending	8,900	8,784	10,929
Assets	100,300	99,279
Geographic Information
Plant, Property and Equipment	69,775	65,489
Canada
Geographic Information
Plant, Property and Equipment	24,092	23,362
Canada – domestic
Segmented information
Revenues	4,392	4,059	4,187
Canada – export
Segmented information
Revenues	1,059	1,035	1,075
United States
Segmented information
Revenues	6,832	7,558	7,798
Geographic Information
Plant, Property and Equipment	39,698	36,184
Mexico
Segmented information
Revenues	716	603	619
Geographic Information
Plant, Property and Equipment	5,985	5,943
Intersegment eliminations
Segmented information
Revenues	(185)	(183)	(218)
Corporate
Segmented information
Revenues	(185)	(183)	(218)
Income from equity investments	86	(53)	5
Plant operating costs and other	169	166	159
Commodity purchases resold		0	0
Property taxes	0	0	0
Depreciation and amortization	0	0	0
Goodwill and other asset impairment charges			0
Net (loss)/ gain on assets sold/held for sale	0	0	0
Segmented earnings	70	(70)	(54)
Capital spending
Capital expenditures	58	32	45
Capital projects in development	0	0	0
Contributions to equity investments	0	0	0
Capital spending	58	32	45
Assets	5,210	4,743
Canadian Natural Gas Pipelines
Segmented information
Revenues	4,469	4,010	4,038
Canadian Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	4,469	4,010	4,038
Income from equity investments	12	12	12
Plant operating costs and other	(1,631)	(1,473)	(1,405)
Commodity purchases resold		0	0
Property taxes	(284)	(275)	(266)
Depreciation and amortization	(1,273)	(1,159)	(1,129)
Goodwill and other asset impairment charges			0
Net (loss)/ gain on assets sold/held for sale	364	0	0
Segmented earnings	1,657	1,115	1,250
Capital spending
Capital expenditures	3,503	3,900	2,442
Capital projects in development	0	6	36
Contributions to equity investments	105	0	0
Capital spending	3,608	3,906	2,478
Assets	22,852	21,983
Geographic Information
Plant, Property and Equipment	19,325	19,258
Canadian Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues	0	0	0
U.S. Natural Gas Pipelines
Segmented information
Revenues	5,031	4,978	4,314
U.S. Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	5,196	5,142	4,476
Income from equity investments	264	264	256
Plant operating costs and other	(1,485)	(1,581)	(1,368)
Commodity purchases resold		0	0
Property taxes	(337)	(345)	(199)
Depreciation and amortization	(801)	(754)	(664)
Goodwill and other asset impairment charges			(801)
Net (loss)/ gain on assets sold/held for sale	0	21	0
Segmented earnings	2,837	2,747	1,700
Capital spending
Capital expenditures	2,785	2,500	5,591
Capital projects in development	0	0	1
Contributions to equity investments	0	16	179
Capital spending	2,785	2,516	5,771
Assets	43,217	41,627
Geographic Information
Plant, Property and Equipment	28,169	26,360
U.S. Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues	(165)	(164)	(162)
Mexico Natural Gas Pipelines
Segmented information
Revenues	716	603	619
Mexico Natural Gas Pipelines \| Operating segments
Segmented information
Revenues	716	603	619
Income from equity investments	127	56	22
Plant operating costs and other	(57)	(54)	(34)
Commodity purchases resold		0	0
Property taxes	0	0	0
Depreciation and amortization	(117)	(115)	(97)
Goodwill and other asset impairment charges			0
Net (loss)/ gain on assets sold/held for sale	0	0	0
Segmented earnings	669	490	510
Capital spending
Capital expenditures	173	323	463
Capital projects in development	0	0	0
Contributions to equity investments	0	34	334
Capital spending	173	357	797
Assets	7,215	7,207
Geographic Information
Plant, Property and Equipment	5,968	5,920
Mexico Natural Gas Pipelines \| Intersegment eliminations
Segmented information
Revenues	0	0	0
Liquids Pipelines
Segmented information
Revenues	2,371	2,879	2,584
Liquids Pipelines \| Operating segments
Segmented information
Revenues	2,371	2,879	2,584
Income from equity investments	75	70	64
Plant operating costs and other	(654)	(728)	(630)
Commodity purchases resold		0	0
Property taxes	(101)	(101)	(98)
Depreciation and amortization	(332)	(341)	(341)
Goodwill and other asset impairment charges			0
Net (loss)/ gain on assets sold/held for sale	0	69	0
Segmented earnings	1,359	1,848	1,579
Capital spending
Capital expenditures	1,315	239	110
Capital projects in development	122	701	459
Contributions to equity investments	5	14	12
Capital spending	1,442	954	581
Assets	16,744	15,931
Geographic Information
Plant, Property and Equipment	14,409	11,975
Liquids Pipelines \| Intersegment eliminations
Segmented information
Revenues	0	0	0
Power and Storage
Segmented information
Revenues	412	785	2,124
Power and Storage \| Operating segments
Segmented information
Revenues	432	804	2,180
Income from equity investments	455	571	355
Plant operating costs and other	(220)	(243)	(315)
Commodity purchases resold		(365)	(1,486)
Property taxes	(5)	(6)	(6)
Depreciation and amortization	(67)	(95)	(119)
Goodwill and other asset impairment charges			0
Net (loss)/ gain on assets sold/held for sale	(414)	(211)	170
Segmented earnings	181	455	779
Capital spending
Capital expenditures	179	481	767
Capital projects in development	0	0	0
Contributions to equity investments	655	538	490
Capital spending	834	1,019	1,257
Assets	5,062	7,788
Geographic Information
Plant, Property and Equipment	1,283	1,301
Power and Storage \| Intersegment eliminations
Segmented information
Revenues	$ (20)	$ (19)	$ (56)

REVENUES - Disaggregation of Revenues (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	May 22, 2020
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 12,647	$ 12,670	$ 12,794
Other revenues	352	585	885
Revenues	12,999	13,255	13,679
Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	11,522	11,279	10,280
Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	192	662	1,771
Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	933	729	743
Fee revenue from affiliates	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	4,469	4,010	4,038
Other revenues	0	0	0
Revenues	$ 4,469	4,010	4,038
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	$ 4,408	4,010	4,038
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	61	0	0
U.S. Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,955	4,895	4,203
Other revenues	76	83	111
Revenues	5,031	4,978	4,314
U.S. Natural Gas Pipelines \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,301	4,245	3,549
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	654	650	654
Mexico Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	716	603	619
Other revenues	0	0	0
Revenues	$ 716	603	619
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	$ 607	601	614
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	109	2	5
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,209	2,427	2,082
Other revenues	162	452	502
Revenues	2,371	2,879	2,584
Liquids Pipelines \| Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,206	2,423	2,079
Liquids Pipelines \| Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0
Liquids Pipelines \| Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3	4	3
Power and Storage
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	298	735	1,852
Other revenues	114	50	272
Revenues	412	785	2,124
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	192	662	1,771
Power and Storage \| Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 106	$ 73	$ 81

REVENUES - Contract Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 1,330	$ 1,458
Contract assets (Note 6)	132	153
Long-term contract assets (Note 13)	192	102
Contract liabilities	129	61
Long-term contract liabilities (Note 16)	203	226
Revenue recognized	$ 18	$ 6

REVENUES - Remaining Performance Obligations - Narrative (Details) $ in Billions	Dec. 31, 2020 CAD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 25.5
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 3.7
Future revenues, expected timing of satisfaction, period	1 year

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Other Assets [Abstract]
Fair value of derivative contracts (Note 25)	$ 235	$ 190
Cash provided as collateral	142	52
Contract assets (Note 5)	132	153
Regulatory assets (Note 11)	131	43
Prepaid expenses	126	60
Other	114	129
Other current assets, total	$ 880	$ 627

PLANT, PROPERTY AND EQUIPMENT (Details) - CAD ($) $ in Millions	May 22, 2020	Mar. 31, 2020	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Cost				$ 99,372	$ 92,807
Accumulated Depreciation				29,597	27,318
Net Book Value				69,775	65,489
Disposal group, disposed of by sale, not discontinued operations \| Coastal GasLink
Property, Plant and Equipment [Line Items]
Ownership interest sold	65.00%
Coastal GasLink
Property, Plant and Equipment [Line Items]
Ownership interest sold	65.00%
Keystone XL
Property, Plant and Equipment [Line Items]
Net Book Value				2,800
Capitalized development costs		$ 1,700
Bison
Property, Plant and Equipment [Line Items]
Impairment charge			$ 722
Impairment charge, net of tax and noncontrolling interest			140
Gain on contract termination			130
Gain on contract termination, net of tax and noncontrolling interest			$ 25
Canadian Natural Gas Pipelines \| Under construction \| NGTL System
Property, Plant and Equipment [Line Items]
Accumulated Depreciation				0	0
Operating segments \| Canadian Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost				39,347	38,090
Accumulated Depreciation				20,022	18,832
Net Book Value				19,325	19,258
Operating segments \| Canadian Natural Gas Pipelines \| NGTL System
Property, Plant and Equipment [Line Items]
Cost				22,406	20,238
Accumulated Depreciation				7,832	7,226
Net Book Value				14,574	13,012
Operating segments \| Canadian Natural Gas Pipelines \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost				15,014	14,715
Accumulated Depreciation				10,682	10,151
Net Book Value				4,332	4,564
Operating segments \| Canadian Natural Gas Pipelines \| Other
Property, Plant and Equipment [Line Items]
Cost				1,885	1,861
Accumulated Depreciation				1,508	1,455
Net Book Value				377	406
Operating segments \| Canadian Natural Gas Pipelines \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost				1,927	3,137
Accumulated Depreciation				1,508	1,455
Net Book Value				419	1,682
Operating segments \| Canadian Natural Gas Pipelines \| Pipeline \| NGTL System
Property, Plant and Equipment [Line Items]
Cost				14,190	11,556
Accumulated Depreciation				5,278	4,846
Net Book Value				8,912	6,710
Operating segments \| Canadian Natural Gas Pipelines \| Pipeline \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost				10,297	10,145
Accumulated Depreciation				7,443	7,109
Net Book Value				2,854	3,036
Operating segments \| Canadian Natural Gas Pipelines \| Compression \| NGTL System
Property, Plant and Equipment [Line Items]
Cost				5,421	4,205
Accumulated Depreciation				1,906	1,771
Net Book Value				3,515	2,434
Operating segments \| Canadian Natural Gas Pipelines \| Compression \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost				3,930	3,867
Accumulated Depreciation				3,000	2,823
Net Book Value				930	1,044
Operating segments \| Canadian Natural Gas Pipelines \| Metering and other \| NGTL System
Property, Plant and Equipment [Line Items]
Cost				1,393	1,296
Accumulated Depreciation				648	609
Net Book Value				745	687
Operating segments \| Canadian Natural Gas Pipelines \| Metering and other \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost				637	643
Accumulated Depreciation				239	219
Net Book Value				398	424
Operating segments \| Canadian Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| NGTL System
Property, Plant and Equipment [Line Items]
Cost				21,004	17,057
Accumulated Depreciation				7,832	7,226
Net Book Value				13,172	9,831
Operating segments \| Canadian Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost				14,864	14,655
Accumulated Depreciation				10,682	10,151
Net Book Value				4,182	4,504
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| NGTL System
Property, Plant and Equipment [Line Items]
Cost				1,402	3,181
Net Book Value				1,402	3,181
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| Canadian Mainline
Property, Plant and Equipment [Line Items]
Cost				150	60
Accumulated Depreciation				0	0
Net Book Value				150	60
Operating segments \| Canadian Natural Gas Pipelines \| Under construction \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost				42	1,276
Accumulated Depreciation				0	0
Net Book Value				42	1,276
Operating segments \| U.S. Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost				33,536	31,250
Accumulated Depreciation				5,367	4,890
Net Book Value				28,169	26,360
Operating segments \| U.S. Natural Gas Pipelines \| Other Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost				9,042	8,638
Accumulated Depreciation				2,960	2,907
Net Book Value				6,082	5,731
Operating segments \| U.S. Natural Gas Pipelines \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost				18,943	17,471
Accumulated Depreciation				1,018	720
Net Book Value				17,925	16,751
Operating segments \| U.S. Natural Gas Pipelines \| ANR
Property, Plant and Equipment [Line Items]
Cost				5,551	5,141
Accumulated Depreciation				1,389	1,263
Net Book Value				4,162	3,878
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Other
Property, Plant and Equipment [Line Items]
Cost				1,568	1,530
Accumulated Depreciation				578	616
Net Book Value				990	914
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost				10,198	9,708
Accumulated Depreciation				557	389
Net Book Value				9,641	9,319
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| ANR
Property, Plant and Equipment [Line Items]
Cost				1,685	1,594
Accumulated Depreciation				512	472
Net Book Value				1,173	1,122
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Columbia Gulf
Property, Plant and Equipment [Line Items]
Cost				2,638	2,597
Accumulated Depreciation				151	114
Net Book Value				2,487	2,483
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| GTN
Property, Plant and Equipment [Line Items]
Cost				2,330	2,257
Accumulated Depreciation				1,008	969
Net Book Value				1,322	1,288
Operating segments \| U.S. Natural Gas Pipelines \| Pipeline \| Great Lakes
Property, Plant and Equipment [Line Items]
Cost				2,117	2,090
Accumulated Depreciation				1,223	1,208
Net Book Value				894	882
Operating segments \| U.S. Natural Gas Pipelines \| Compression \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost				4,287	4,094
Accumulated Depreciation				276	206
Net Book Value				4,011	3,888
Operating segments \| U.S. Natural Gas Pipelines \| Compression \| ANR
Property, Plant and Equipment [Line Items]
Cost				2,146	2,050
Accumulated Depreciation				489	436
Net Book Value				1,657	1,614
Operating segments \| U.S. Natural Gas Pipelines \| Metering and other \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost				3,388	3,244
Accumulated Depreciation				185	125
Net Book Value				3,203	3,119
Operating segments \| U.S. Natural Gas Pipelines \| Metering and other \| ANR
Property, Plant and Equipment [Line Items]
Cost				1,289	1,245
Accumulated Depreciation				388	355
Net Book Value				901	890
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				8,653	8,474
Accumulated Depreciation				2,960	2,907
Net Book Value				5,693	5,567
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost				17,873	17,046
Accumulated Depreciation				1,018	720
Net Book Value				16,855	16,326
Operating segments \| U.S. Natural Gas Pipelines \| Property, plant and equipment excluding under construction \| ANR
Property, Plant and Equipment [Line Items]
Cost				5,120	4,889
Accumulated Depreciation				1,389	1,263
Net Book Value				3,731	3,626
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				389	164
Accumulated Depreciation				0	0
Net Book Value				389	164
Operating segments \| U.S. Natural Gas Pipelines \| Under construction \| Columbia Gas
Property, Plant and Equipment [Line Items]
Cost				1,070	425
Accumulated Depreciation				0	0
Net Book Value				1,070	425
Operating segments \| U.S. Natural Gas Pipelines \| Under construction \| ANR
Property, Plant and Equipment [Line Items]
Cost				431	252
Net Book Value				431	252
Operating segments \| Mexico Natural Gas Pipelines
Property, Plant and Equipment [Line Items]
Cost				6,581	6,438
Accumulated Depreciation				613	518
Net Book Value				5,968	5,920
Operating segments \| Mexico Natural Gas Pipelines \| Pipeline
Property, Plant and Equipment [Line Items]
Cost				2,952	2,988
Accumulated Depreciation				411	340
Net Book Value				2,541	2,648
Operating segments \| Mexico Natural Gas Pipelines \| Compression
Property, Plant and Equipment [Line Items]
Cost				480	486
Accumulated Depreciation				69	54
Net Book Value				411	432
Operating segments \| Mexico Natural Gas Pipelines \| Metering and other
Property, Plant and Equipment [Line Items]
Cost				624	643
Accumulated Depreciation				133	124
Net Book Value				491	519
Operating segments \| Mexico Natural Gas Pipelines \| Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost				4,056	4,117
Accumulated Depreciation				613	518
Net Book Value				3,443	3,599
Operating segments \| Mexico Natural Gas Pipelines \| Under construction
Property, Plant and Equipment [Line Items]
Cost				2,525	2,321
Accumulated Depreciation				0	0
Net Book Value				2,525	2,321
Operating segments \| Liquids Pipelines
Property, Plant and Equipment [Line Items]
Cost				16,869	14,142
Accumulated Depreciation				2,460	2,167
Net Book Value				14,409	11,975
Operating segments \| Liquids Pipelines \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost				16,671	13,948
Accumulated Depreciation				2,451	2,163
Net Book Value				14,220	11,785
Operating segments \| Liquids Pipelines \| Pipeline \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost				9,254	9,378
Accumulated Depreciation				1,579	1,403
Net Book Value				7,675	7,975
Operating segments \| Liquids Pipelines \| Pipeline \| Intra-Alberta Pipelines
Property, Plant and Equipment [Line Items]
Cost				142	138
Accumulated Depreciation				6	2
Net Book Value				136	136
Operating segments \| Liquids Pipelines \| Pumping equipment \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost				1,025	1,035
Accumulated Depreciation				228	204
Net Book Value				797	831
Operating segments \| Liquids Pipelines \| Tanks and other \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost				3,522	3,488
Accumulated Depreciation				644	556
Net Book Value				2,878	2,932
Operating segments \| Liquids Pipelines \| Tanks and other \| Intra-Alberta Pipelines
Property, Plant and Equipment [Line Items]
Cost				56	56
Accumulated Depreciation				3	2
Net Book Value				53	54
Operating segments \| Liquids Pipelines \| Property, plant and equipment excluding under construction \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost				13,801	13,901
Accumulated Depreciation				2,451	2,163
Net Book Value				11,350	11,738
Operating segments \| Liquids Pipelines \| Property, plant and equipment excluding under construction \| Intra-Alberta Pipelines
Property, Plant and Equipment [Line Items]
Cost				198	194
Accumulated Depreciation				9	4
Net Book Value				189	190
Operating segments \| Liquids Pipelines \| Under construction \| Keystone Pipeline System
Property, Plant and Equipment [Line Items]
Cost				2,870	47
Accumulated Depreciation				0	0
Net Book Value				2,870	47
Operating segments \| Power and Storage
Property, Plant and Equipment [Line Items]
Cost				2,046	2,004
Accumulated Depreciation				763	703
Net Book Value				1,283	1,301
Operating segments \| Power and Storage \| Natural Gas
Property, Plant and Equipment [Line Items]
Cost				1,255	1,256
Accumulated Depreciation				569	522
Net Book Value				686	734
Operating segments \| Power and Storage \| Natural Gas Storage and Other
Property, Plant and Equipment [Line Items]
Cost				780	742
Accumulated Depreciation				194	181
Net Book Value				586	561
Operating segments \| Power and Storage \| Property, plant and equipment excluding under construction
Property, Plant and Equipment [Line Items]
Cost				2,035	1,998
Accumulated Depreciation				763	703
Net Book Value				1,272	1,295
Operating segments \| Power and Storage \| Under construction
Property, Plant and Equipment [Line Items]
Cost				11	6
Accumulated Depreciation				0	0
Net Book Value				11	6
Corporate
Property, Plant and Equipment [Line Items]
Cost				993	883
Accumulated Depreciation				372	208
Net Book Value				$ 621	$ 675
TC PipeLines, LP
Property, Plant and Equipment [Line Items]
Noncontrolling interest, ownership interest by parent			25.50%	25.50%

LEASES - (Lessee) Narrative (Details) - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2019	Dec. 31, 2020	Dec. 31, 2018	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Operating lease termination period		1 year
Right-of-use asset		$ 473		$ 530
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]		us-gaap:PropertyPlantAndEquipment		us-gaap:PropertyPlantAndEquipment
Net rental expense on operating leases			$ 84
Northern Courier pipeline \| Liquids Pipelines
Lessee, Lease, Description [Line Items]
Ownership interest percentage	15.00%	15.00%
Disposal group, disposed of by sale, not discontinued operations \| Northern Courier pipeline
Lessee, Lease, Description [Line Items]
Ownership interest sold	85.00%
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 Lease Cost and Other Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Operating lease cost
Operating lease cost	$ 124	$ 117
Sublease income	(13)	(11)
Net operating lease cost	111	106
Cash paid for amounts included in the measurement of operating lease liabilities	77	76
ROU assets obtained in exchange for new operating lease liabilities	$ 14	$ 9
Weighted average remaining lease term	10 years	10 years
Weighted average discount rate	3.50%	3.50%

LEASES - (Lessee) Maturities of Operating Lease Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Less than one year	$ 72	$ 73
One to two years	61	69
Two to three years	59	59
Three to four years	58	58
Four to five years	54	57
More than five years	269	323
Total operating lease payments	573	639
Imputed interest	(90)	(107)
Operating lease liabilities	483	532
Operating lease, reported as accounts payable and other	56	56
Operating lease, reported as other long-term liabilities	$ 427	$ 476
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesNoncurrent	us-gaap:OtherLiabilitiesNoncurrent
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:AccountsPayableAndOtherAccruedLiabilitiesCurrent	us-gaap:AccountsPayableAndOtherAccruedLiabilitiesCurrent
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:PropertyPlantAndEquipment	us-gaap:PropertyPlantAndEquipment

LEASES - (Lessor) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Lessor, Lease, Description [Line Items]
Fixed portion of the operating lease income	$ 130	$ 180
Operating lease income			$ 373
Cost	99,372	92,807
Accumulated Depreciation	29,597	27,318
Assets leased to others
Lessor, Lease, Description [Line Items]
Cost	858	834
Accumulated Depreciation	$ 327	$ 301

LEASES - (Lessor) Future Lease Payments to be Received Under Operating Leases (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Less than one year	$ 119	$ 123
One to two years	111	116
Two to three years	109	111
Three to four years	109	109
Four to five years	94	109
More than five years	70	164
Total payments to be received	$ 612	$ 732

EQUITY INVESTMENTS - Ownership Information of Equity Investments (Details) $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2019	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2020 USD ($)	Nov. 13, 2020	May 22, 2020	Dec. 31, 2019 USD ($)
Equity Investments
Income /(Loss) from Equity Investments		$ 1,019	$ 920	$ 714
Equity Investments		6,677	6,506
Grand Rapids
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets		98	101
Northern Courier pipeline
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets		$ 56	62
Canadian Natural Gas Pipelines \| TQM
Equity Investments
Ownership interest percentage		50.00%			50.00%
Income /(Loss) from Equity Investments		$ 12	12	12
Equity Investments		$ 90	79
Canadian Natural Gas Pipelines \| Coastal GasLink
Equity Investments
Ownership interest percentage		35.00%			35.00%		35.00%
Income /(Loss) from Equity Investments		$ 0	0	0
Equity Investments		211	0
Difference between the carrying value of the investment and the underlying equity in the net assets		$ 188
U.S. Natural Gas Pipelines \| Northern Border
Equity Investments
Ownership interest percentage		50.00%			50.00%
Income /(Loss) from Equity Investments		$ 100	91	87
Equity Investments		$ 521	549
Difference between the carrying value of the investment and the underlying equity in the net assets					$ 116,000,000			$ 116,000,000
U.S. Natural Gas Pipelines \| Millennium
Equity Investments
Ownership interest percentage		47.50%			47.50%
Income /(Loss) from Equity Investments		$ 96	92	75
Equity Investments		$ 482	496
U.S. Natural Gas Pipelines \| Iroquois
Equity Investments
Ownership interest percentage		50.00%			50.00%
Income /(Loss) from Equity Investments		$ 52	54	60
Equity Investments		197	241
Difference between the carrying value of the investment and the underlying equity in the net assets					$ 39,000,000			40,000,000
U.S. Natural Gas Pipelines \| Pennant Midstream
Equity Investments
Income /(Loss) from Equity Investments		0	12	17
Equity Investments		0	0
U.S. Natural Gas Pipelines \| Pipeline equity investments and other
Equity Investments
Income /(Loss) from Equity Investments		16	15	17
Equity Investments		$ 120	112
Mexico Natural Gas Pipelines \| Sur de Texas
Equity Investments
Ownership interest percentage		60.00%			60.00%
Income /(Loss) from Equity Investments		$ 213	3	27
Equity Investments		$ 680	600
Difference between the carrying value of the investment and the underlying equity in the net assets					$ 79,000,000			$ 0
Liquids Pipelines \| Grand Rapids
Equity Investments
Ownership interest percentage		50.00%			50.00%
Income /(Loss) from Equity Investments		$ 53	56	65
Equity Investments		$ 998	1,028
Liquids Pipelines \| Northern Courier pipeline
Equity Investments
Ownership interest percentage	15.00%	15.00%			15.00%
Income /(Loss) from Equity Investments		$ 22	14	0
Equity Investments		$ 53	62
Liquids Pipelines \| HoustonLink Pipeline
Equity Investments
Ownership interest percentage		50.00%			50.00%
Income /(Loss) from Equity Investments		$ 0	0	(1)
Equity Investments		$ 19	19
Power and Storage \| Bruce Power
Equity Investments
Ownership interest percentage		48.40%			48.40%
Income /(Loss) from Equity Investments		$ 439	527	311
Equity Investments		3,306	3,256
Difference between the carrying value of the investment and the underlying equity in the net assets		796	829
Power and Storage \| Portlands Energy
Equity Investments
Income /(Loss) from Equity Investments		12	35	36
Equity Investments		$ 0	0
Difference between the carrying value of the investment and the underlying equity in the net assets			76
Power and Storage \| TransCanada Turbines
Equity Investments
Ownership interest percentage		100.00%			100.00%
Income /(Loss) from Equity Investments		$ 4	9	$ 8
Equity Investments		$ 0	$ 64
Business acquisition, percentage of voting interests acquired						50.00%
Northern Courier pipeline \| Disposal group, disposed of by sale, not discontinued operations
Equity Investments
Ownership interest sold	85.00%

EQUITY INVESTMENTS - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Equity Investments
Distributions received from equity investments	$ 1,123	$ 1,399	$ 1,106
Returns of capital	0	186	121
Contributions to equity investments	$ 765	602	1,015
Sur de Texas
Equity Investments
Contributions to equity investments		$ 32	$ 179

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income
Revenues	$ 12,999	$ 13,255	$ 13,679
Operating and other expenses	(7,195)	(7,469)	(8,799)
Net income	4,616	4,140	3,702
Income from equity investments	1,019	920	714
Balance Sheet
Current assets	5,201	7,651
Current liabilities	(11,987)	(12,899)
Group of Investees
Income
Revenues	5,838	5,693	4,836
Operating and other expenses	(3,341)	(3,408)	(3,545)
Net income	2,047	1,990	1,515
Income from equity investments	1,019	920	$ 714
Balance Sheet
Current assets	2,911	2,305
Non-current assets	26,957	21,865
Current liabilities	(3,727)	(2,060)
Non-current liabilities	$ (15,309)	$ (11,461)

LOANS RECEIVABLE FROM AFFILIATES - Narrative (Details)	Dec. 31, 2020 CAD ($)	Dec. 31, 2020 MXN ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 MXN ($)	Dec. 31, 2017 MXN ($)
Revolving credit facility \| Line of credit \| Coastal GasLink
Loans and Leases Receivable Disclosure [Line Items]
Revolving credit facility, borrowing capacity	$ 200,000,000
Line of credit, outstanding amount	$ 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
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	$ 1,300,000,000	$ 20,900,000,000	$ 1,400,000,000	$ 20,900,000,000

LOANS RECEIVABLE FROM AFFILIATES - Schedule of Loan Receivable Interest Income and Foreign Exchange Impact (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Loans and Leases Receivable Disclosure [Line Items]
Foreign exchange gain (loss)	$ (86)	$ 53	$ (5)
Sur de Texas \| Interest income \| Joint venture
Loans and Leases Receivable Disclosure [Line Items]
Interest income	110	147	120
Foreign exchange gain (loss)	(86)	53	(5)
Sur de Texas \| Income from equity investments \| Joint venture
Loans and Leases Receivable Disclosure [Line Items]
Interest expense	(110)	(147)	(120)
Foreign exchange gain (loss)	$ 86	$ (53)	$ 5

RATE-REGULATED BUSINESSES - Narrative (Details) $ in Millions			1 Months Ended	12 Months Ended
	Apr. 17, 2020	Feb. 01, 2019	Feb. 28, 2018	Dec. 31, 2020 pipeline	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016 USD ($)	Dec. 31, 2014 CAD ($)	Dec. 31, 2013 USD ($)
Columbia Gas Transmission
Public Utilities, General Disclosures [Line Items]
Maximum cost recovery and return on investment								$ 1,100,000,000		$ 1,500,000,000
Cost recovery and return on investment, additional period								3 years
NGTL System
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity				10.10%	10.10%	10.10%
Deemed common equity, percent				40.00%	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%
After-tax annual contribution to reduce revenue requirement									$ 20
Fixed toll term									6 years
Approved composite depreciation rate						3.90%	3.20%
Unanimous negotiated settlement period	6 years								6 years
Great Lakes
Public Utilities, General Disclosures [Line Items]
Maximum regulatory transportation rate increase (decrease)		2.00%	(27.00%)
TC Pipe Lines LP
Public Utilities, General Disclosures [Line Items]
Noncontrolling interest, ownership interest by parent				25.50%		25.50%
TC Pipe Lines LP
Public Utilities, General Disclosures [Line Items]
Number of wholly-owned or partially owned pipelines \| pipeline				8

RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 CAD ($)
Regulatory Assets
Regulatory Assets	$ 1,884		$ 1,630
Less: Current portion included in Other current assets (Note 6)	131		43
Regulatory Assets, noncurrent	1,753		1,587
Regulatory Liabilities
Regulatory Liabilities	4,301		4,468
Less: Current portion included in Accounts payable and other (Note 15)	153		696
Regulatory Liabilities, noncurrent	4,148		3,772
Operating and debt-service regulatory liabilities
Regulatory Liabilities
Regulatory Liabilities	$ 48		139
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Pensions and other post retirement benefits \| ANR PIPELINE COMPANY
Regulatory Liabilities
Regulatory Liabilities	$ 40		41
Long term adjustment account
Regulatory Liabilities
Regulatory Liabilities	$ 227		660
Remaining Recovery/ Settlement Period (years)	6 years	6 years
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
Bridging amortization account
Regulatory Liabilities
Regulatory Liabilities	$ 537		428
Remaining Recovery/ Settlement Period (years)	10 years	10 years
Pipeline abandonment trust balances
Regulatory Liabilities
Regulatory Liabilities	$ 1,842		1,462
Cost of removal
Regulatory Liabilities
Regulatory Liabilities	246		253
Deferred income taxes
Regulatory Liabilities
Regulatory Liabilities	115		151
Deferred income taxes - U.S. Tax Reform
Regulatory Liabilities
Regulatory Liabilities	1,170		1,239
Other
Regulatory Liabilities
Regulatory Liabilities	58		60
Postretirement benefit costs \| ANR PIPELINE COMPANY
Regulatory Liabilities
Amount to be addressed In next settlement	40	$ 32
Deferred income taxes
Regulatory Assets
Regulatory Assets	1,287		1,088
Operating and debt-service regulatory assets
Regulatory Assets
Regulatory Assets	$ 54		2
Remaining Recovery/ Settlement Period (years)	1 year	1 year
Pensions and other post retirement benefits
Regulatory Assets
Regulatory Assets	$ 401		417
Regulatory Liabilities
Regulatory Liabilities	18		35
Foreign exchange on long-term debt
Regulatory Assets
Regulatory Assets	$ 7		16
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)	9 years	9 years
Other
Regulatory Assets
Regulatory Assets	$ 135		$ 107

GOODWILL - Acquisitions (Details) - CAD ($) $ in Millions	12 Months Ended
GOODWILL - Acquisitions (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Goodwill
Balance at the beginning of the period	$ 12,887
Balance at the end of the period	12,679	$ 12,887
U.S. Natural Gas Pipelines
Goodwill
Balance at the beginning of the period	12,887	14,178
Sale of Columbia Midstream assets		(595)
Foreign exchange rate changes	(208)	(696)
Balance at the end of the period	$ 12,679	$ 12,887

GOODWILL - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
GOODWILL - Narrative (Details) $ in Millions, $ in Millions	Dec. 31, 2018 CAD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 USD ($)	Aug. 31, 2019 CAD ($)
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill		$ 12,679		$ 12,887
U.S. Natural Gas Pipelines
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	$ 14,178	$ 12,679		$ 12,887
Midstream
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill						$ 595
Tuscarora
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill			$ 82		$ 82
Goodwill impairment charge	79
Goodwill impairment charge, net of tax and noncontrolling interest	$ 15
Goodwill accumulated impairment loss			$ 59		$ 59

OTHER LONG-TERM ASSETS - Summary (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Capital projects in development	$ 231	$ 1,715
Employee post-retirement benefits (Note 24)	207	162
Long-term contract assets (Note 5)	192	102
Deferred income tax assets (Note 17)	177	37
Fair value of derivative contracts (Note 25)	41	7
Other	131	145
Total other assets	$ 979	$ 2,168

- Definition

Amount of asset, recognized in statement of financial position, for overfunded defined benefit pension and other postretirement plans.

+ References + Details

OTHER LONG-TERM ASSETS - Narrative (Details) $ in Millions			1 Months Ended	12 Months Ended
OTHER LONG-TERM ASSETS - Narrative (Details) $ in Millions	May 22, 2020	Mar. 31, 2020 CAD ($)	Nov. 30, 2018 CAD ($) party	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)
Finite-Lived Intangible Assets [Line Items]
Capital projects in development				$ 231	$ 1,715
Reimbursement of costs related to capital projects in development				$ 0	0	$ 470
Disposal group, disposed of by sale, not discontinued operations \| Coastal GasLink
Finite-Lived Intangible Assets [Line Items]
Ownership interest sold	65.00%
Keystone XL
Finite-Lived Intangible Assets [Line Items]
Capitalized development costs		$ 1,700
Capital projects in development					$ 1,500
Coastal GasLink
Finite-Lived Intangible Assets [Line Items]
Reimbursement of costs related to capital projects in development			$ 470
Number of parties (in parties) \| party			5
Ownership interest sold	65.00%

NOTES PAYABLE (Details)	12 Months Ended
NOTES PAYABLE (Details)	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2020 MXN ($)	Jun. 30, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2019 MXN ($)
Notes payable
Outstanding	$ 4,176,000,000	$ 4,300,000,000
Subsidiaries
Notes payable
Unused Capacity	800,000,000	800,000,000
Revolving credit facility
Notes payable
Cost to maintain	21,000,000	11,000,000	$ 12,000,000
Notes payable
Notes payable
Denominated value	656,000,000	1,353,000,000		$ 1,709,000,000			$ 2,068,000,000
Revolving and demand credit facility
Notes payable
Total Facilities	12,400,000,000	12,600,000,000				$ 2,000,000,000.0
TCPL \| Revolving credit facility \| Maturing December 2024
Notes payable
Total Facilities	3,000,000,000.0	3,000,000,000.0
Unused Capacity	2,300,000,000
TCPL \| Notes payable
Notes payable
Outstanding	$ 2,836,000,000	$ 4,034,000,000
Weighted average interest rate per annum	0.40%	2.10%		0.40%	0.40%		2.10%	2.10%
USA \| Notes payable
Notes payable
Outstanding	$ 1,149,000,000	$ 0		$ 900,000,000			$ 0
Weighted average interest rate per annum	0.40%	0.00%		0.40%	0.40%		0.00%	0.00%
Mexico subsidiary \| Revolving credit facility
Notes payable
Total Facilities					$ 5,000,000,000.0			$ 5,000,000,000.0
Unused Capacity					$ 2,000,000,000.0
Mexico subsidiary \| Notes payable
Notes payable
Outstanding	$ 191,000,000	$ 266,000,000		$ 150,000,000			$ 205,000,000
Weighted average interest rate per annum	1.70%	2.70%		1.70%	1.70%		2.70%	2.70%
TCPL/TCPL USA/Columbia/TransCanada American Investments Ltd. \| Revolving credit facility \| Maturing December 2021
Notes payable
Total Facilities				$ 4,500,000,000			$ 4,500,000,000
Unused Capacity				1,900,000,000
TCPL/TCPL USA/Columbia/TransCanada American Investments Ltd. \| Revolving credit facility \| Maturing December 2022
Notes payable
Total Facilities				1,000,000,000.0			$ 1,000,000,000.0
Unused Capacity				$ 1,000,000,000.0
TCPL/TCPL USA \| Revolving credit facility
Notes payable
Total Facilities	$ 2,100,000,000	$ 2,100,000,000
Unused Capacity	$ 1,100,000,000

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Payables and Accruals [Abstract]
Trade payables	$ 3,057	$ 3,314
Regulatory liabilities (Note 11)	153	696
Contract liabilities	129	61
Fair value of derivative contracts (Note 25)	72	115
Other	405	358
Accounts payable and other	$ 3,816	$ 4,544

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred Costs, Noncurrent [Abstract]
Employee post-retirement benefits (Note 24)	$ 503	$ 540
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesNoncurrent	us-gaap:OtherLiabilitiesNoncurrent
Operating lease obligations (Note 8)	$ 427	$ 476
Long-term contract liabilities (Note 5)	203	226
Fair value of derivative contracts (Note 25)	59	81
Asset retirement obligations	54	62
Guarantees	30	32
Other	199	197
Other long-term liabilities	$ 1,475	$ 1,614

INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	12 Months Ended
INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current
Canada	$ (54)	$ 84	$ 65
Foreign	306	615	250
Total	252	699	315
Deferred
Canada	(224)	(29)	49
Foreign	166	84	235
Deferred – U.S. Tax Reform and 2018 FERC Actions	0	0	(167)
Total	(58)	55	117
Income Tax Expense	$ 194	$ 754	$ 432

INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Canada	$ 691	$ 1,144	$ 433
Foreign	4,416	4,043	3,516
Income before Income Taxes	$ 5,107	$ 5,187	$ 3,949

- Definition

Amount of income (loss) from continuing operations, including income (loss) from equity method investments, before deduction of income tax expense (benefit), and income (loss) attributable to noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8906-108599

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 940
-SubTopic 20
-Section 25
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=68072869&loc=d3e41242-110953

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8736-108599

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(10))
-URI http://asc.fasb.org/extlink&oid=120395209&loc=SL114868664-224227

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(8))
-URI http://asc.fasb.org/extlink&oid=120400993&loc=SL114874131-224263

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 235
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-URI http://asc.fasb.org/extlink&oid=120399901&loc=d3e537907-122884

Reference 9: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8924-108599

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(15))
-URI http://asc.fasb.org/extlink&oid=120399700&loc=SL114874048-224260

+ Details

INCOME TAXES - Reconciliation of Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income before income taxes	$ 5,107	$ 5,187	$ 3,949
Federal and provincial statutory tax rate	24.00%	26.50%	27.00%
Expected income tax expense	$ 1,226	$ 1,375	$ 1,066
Valuation allowance releases	(400)	(259)
Foreign income tax rate differentials	(258)	(180)	(432)
Income tax differential related to regulated operations	(228)	(159)	(54)
(Income)/ loss from non-controlling interests and equity investments	(141)	(78)	50
Alberta tax rate reduction		(32)	0
Non-taxable portion of capital gains	(62)	(28)	(11)
Non-deductible goodwill on the Columbia Midstream asset disposition		154	0
U.S. Tax Reform and 2018 FERC Actions	0	0	(167)
Other	57	(39)	(20)
Income Tax Expense	$ 194	$ 754	$ 432

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred Income Tax Assets
Tax loss and credit carryforwards	$ 1,389	$ 1,046
Regulatory and other deferred amounts	532	692
Difference in accounting and tax bases of impaired assets and assets held for sale	537	538
Unrealized foreign exchange losses on long-term debt	154	260
Financial instruments	48	23
Other	70	70
Deferred tax assets, gross	2,730	2,629
Less: Valuation allowance	243	673
Deferred tax assets, net of Valuation allowance	2,487	1,956
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment	6,661	6,197
Equity investments	1,087	1,087
Taxes on future revenue requirement	287	232
Other	81	106
Deferred tax liabilities, gross	8,116	7,622
Net Deferred Income Tax Liabilities	5,629	5,666
Deferred Income Tax Assets
Other long-term assets (Note 13)	177	37
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities	$ 5,806	$ 5,703

INCOME TAXES - Narrative (Details) $ in Millions		12 Months Ended
INCOME TAXES - Narrative (Details) $ in Millions	May 22, 2020	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Net operating loss carryforwards
Valuation allowance		$ 243,000,000	$ 673,000,000
Valuation allowance releases		(400,000,000)	(259,000,000)
Deferred income tax liabilities on the unremitted earnings of foreign investments		684,000,000	648,000,000
Income tax payments, net of refunds		252,000,000	713,000,000	$ 338,000,000
Interest expense (recovery) reflected within net tax expense		4,000,000	4,000,000	(1,000,000)
Accrued interest expense		11,000,000	7,000,000
Income tax penalties expense		0	0	0
Income tax penalties accrued		0	0
Deferred income tax recovery				$ (115,000,000)
Coastal GasLink
Net operating loss carryforwards
Ownership interest sold	65.00%
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards		3,671,000,000	1,929,000,000
Capital loss carryforwards unrecognized		253,000,000	598,000,000
Canada federal and provincial \| Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits		$ 106,000,000	$ 102,000,000
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards					$ 849	$ 1,098
Mexican Tax Authority
Net operating loss carryforwards
Unused net operating loss carryforwards					$ 13	$ 4

INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefit at beginning of year	$ 29	$ 19	$ 15
Gross increases – tax positions in prior years	26	13	13
Gross decreases – tax positions in prior years	(2)	(1)	(5)
Gross increases – tax positions in current year	1	0	0
Lapse of statutes of limitations	(2)	(2)	(4)
Unrecognized Tax Benefit at End of Year	$ 52	$ 29	$ 19

LONG-TERM DEBT - Amounts Outstanding and Principal Repayments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Debt Instrument [Line Items]
Outstanding	$ 36,956	$ 37,019
Current portion of long-term debt	(1,972)	(2,705)
Unamortized debt discount and issue costs	(238)	(228)
Fair value adjustments	167	194
Noncurrent portion of long-term debt	34,913	34,280
Increase in fair value of interest rate hedge	1
Repayments of Long-term Debt [Abstract]
2021	1,972
2022	1,901
2023	1,861
2024	286
2025	2,712
Columbian Pipeline
Debt Instrument [Line Items]
Increase (decrease) in fair value of acquired liabilities, long-term debt	167	193
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	30,228	29,433
TRANSCANADA PIPELINES LIMITED \| Debentures, Maturity Date 2020
Debt Instrument [Line Items]
Outstanding	$ 0	$ 250
Interest Rate	0.00%	11.80%	0.00%	11.80%
TRANSCANADA PIPELINES LIMITED \| Debentures, Maturity Date of 2021
Debt Instrument [Line Items]
Outstanding	$ 510	$ 518	$ 400,000,000	$ 400,000,000
Interest Rate	9.90%	9.90%	9.90%	9.90%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes
Debt Instrument [Line Items]
Outstanding	$ 11,491	$ 9,491
Interest Rate	4.50%	4.60%	4.50%	4.60%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 18,227	$ 19,174	$ 14,292,000,000	$ 14,792,000,000
Interest Rate	5.30%	5.20%	5.30%	5.20%
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	$ 901	$ 905
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	$ 255	$ 259	$ 200,000,000	$ 200,000,000
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	$ 42	$ 42	$ 33,000,000	$ 33,000,000
Interest Rate	7.50%	7.50%	7.50%	7.50%
Columbian Pipeline \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 1,913	$ 2,916	$ 1,500,000,000	$ 2,250,000,000
Interest Rate	4.90%	4.40%	4.90%	4.40%
TC PIPELINES, LP
Debt Instrument [Line Items]
Outstanding	$ 2,104	$ 2,139
TC PIPELINES, LP \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 1,530	$ 1,556	$ 1,200,000,000	$ 1,200,000,000
Interest Rate	4.40%	4.40%	4.40%	4.40%
TC PIPELINES, LP \| Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding	$ 574	$ 583	$ 450,000,000	$ 450,000,000
Interest Rate	1.40%	2.90%	1.40%	2.90%
ANR PIPELINE COMPANY \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 858	$ 872	$ 672,000,000	$ 672,000,000
Interest Rate	7.20%	7.20%	7.20%	7.20%
GAS TRANSMISSION NORTHWEST LLC \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 415	$ 324	$ 325,000,000	$ 250,000,000
Interest Rate	4.30%	5.60%	4.30%	5.60%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 253	$ 284	$ 198,000,000	$ 219,000,000
Interest Rate	7.60%	7.70%	7.60%	7.70%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Debt Instrument [Line Items]
Outstanding	$ 191	$ 51
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 159	$ 0	$ 125,000,000	$ 0
Interest Rate	2.80%	0.00%	2.80%	0.00%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Unsecured Loan Facility
Debt Instrument [Line Items]
Outstanding	$ 32	$ 51	$ 25,000,000	$ 39,000,000
Interest Rate	1.30%	3.00%	1.30%	3.00%
TUSCARORA GAS TRANSMISSION COMPANY \| Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding	$ 29	$ 30	$ 23,000,000	$ 23,000,000
Interest Rate	2.20%	2.80%	2.20%	2.80%
NORTH BAJA PIPELINE, LLC \| Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding	$ 64	$ 65	$ 50,000,000	$ 50,000,000
Interest Rate	1.20%	2.80%	1.20%	2.80%

LONG-TERM DEBT - Issued (Details) $ in Millions, $ in Millions			1 Months Ended
	May 22, 2020	Jun. 30, 2019 CAD ($)	Oct. 31, 2020 USD ($)	Jun. 30, 2020 USD ($)	Apr. 30, 2020 CAD ($)	Apr. 30, 2020 USD ($)	Sep. 30, 2019 CAD ($)	Jul. 31, 2019 CAD ($)	Apr. 30, 2019 CAD ($)	Dec. 31, 2018 USD ($)	Oct. 31, 2018 USD ($)	Jul. 31, 2018 CAD ($)	May 31, 2018 USD ($)	Apr. 30, 2018 USD ($)	Dec. 31, 2020
Senior Secured Credit Facilities due April 2027
Debt Instrument [Line Items]
Amount					$ 1,500
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					$ 800
Interest Rate							4.18%					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%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due March 2049
Debt Instrument [Line Items]
Amount											$ 1,000
Interest Rate											5.10%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due May 2028
Debt Instrument [Line Items]
Amount											$ 400		$ 1,000
Interest Rate											4.25%		4.25%
Long-term debt, re-issuance yield											4.439%
TRANSCANADA PIPELINES LIMITED \| Medium Term Notes due March 2028
Debt Instrument [Line Items]
Amount												$ 200
Interest Rate												3.39%
Long-term debt, re-issuance yield												3.41%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due May 2048
Debt Instrument [Line Items]
Amount													$ 1,000
Interest Rate													4.875%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due May 2038
Debt Instrument [Line Items]
Amount													$ 500
Interest Rate													4.75%
GAS TRANSMISSION NORTHWEST LLC \| Senior Unsecured Notes due June 2030
Debt Instrument [Line Items]
Amount				$ 175
Interest Rate				3.12%
COASTAL GASLINK PIPELINE LIMITED PARTNERSHIP \| Senior Secured Credit Facilities due April 2027
Debt Instrument [Line Items]
Amount					$ 1,603
NOURTHERN COURIER PIPELINE LIMTED PARTNERSHIP \| Senior Secured Notes due June 2042
Debt Instrument [Line Items]
Amount		$ 1,000						$ 1,000
Interest Rate								3.365%
NORTH BAJA PIPELINE, LLC \| Unsecured Term Loan due December 2021
Debt Instrument [Line Items]
Amount										$ 50
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Senior Unsecured Notes Due October 2030
Debt Instrument [Line Items]
Amount			$ 125
Interest Rate													2.84%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Unsecured Loan Facility due April 2023
Debt Instrument [Line Items]
Amount														$ 19
Disposal group, disposed of by sale, not discontinued operations \| NOURTHERN COURIER PIPELINE LIMTED PARTNERSHIP
Debt Instrument [Line Items]
Ownership interest sold								85.00%
Disposal group, disposed of by sale, not discontinued operations \| COASTAL GASLINK PIPELINE LIMITED PARTNERSHIP
Debt Instrument [Line Items]
Ownership interest sold	65.00%
Liquids Pipelines \| NOURTHERN COURIER PIPELINE LIMTED PARTNERSHIP
Debt Instrument [Line Items]
Ownership interest percentage								15.00%							15.00%
Canadian Natural Gas Pipelines \| COASTAL GASLINK PIPELINE LIMITED PARTNERSHIP
Debt Instrument [Line Items]
Ownership interest percentage	35.00%														35.00%

LONG-TERM DEBT - Retired/Repaid (Details) $ in Millions, $ in Millions	1 Months Ended																	12 Months Ended
	Nov. 30, 2020 CAD ($)	Oct. 31, 2020 USD ($)	Jun. 30, 2020 USD ($)	Mar. 31, 2020 USD ($)	Nov. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	May 31, 2019 CAD ($)	May 31, 2019 USD ($)	Mar. 31, 2019 CAD ($)	Jan. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Aug. 31, 2018 USD ($)	Jun. 30, 2018 USD ($)	May 31, 2018 USD ($)	Mar. 31, 2018 CAD ($)	Mar. 31, 2018 USD ($)	Jan. 31, 2018 USD ($)	Dec. 31, 2020 CAD ($)
TRANSCANADA PIPELINES LIMITED \| Debentures due November 2020
Debt Instrument [Line Items]
Amount	$ 250
Interest Rate	11.80%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due October 2020
Debt Instrument [Line Items]
Amount		$ 1,000
Interest Rate		3.80%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due March 2020
Debt Instrument [Line Items]
Amount				$ 750
Interest Rate				4.60%
Amortization of debt Issue costs																		$ 8
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
Interest Rate							9.35%	9.35%
TRANSCANADA PIPELINES LIMITED \| Debentures due March 2019
Debt Instrument [Line Items]
Amount									$ 100
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%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due August 2018
Debt Instrument [Line Items]
Amount												$ 850
Interest Rate												6.50%
TRANSCANADA PIPELINES LIMITED \| Debentures due March 2018
Debt Instrument [Line Items]
Amount															$ 150
Interest Rate															9.45%	9.45%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due January 2018, fixed interest rate
Debt Instrument [Line Items]
Amount																	$ 500
Interest Rate																	1.875%
TRANSCANADA PIPELINES LIMITED \| Senior Unsecured Notes due January 2018, floating interest rate
Debt Instrument [Line Items]
Amount																	$ 250
COLUMBIA PIPELINE GROUP, INC. \| Senior Unsecured Notes due June 2020
Debt Instrument [Line Items]
Amount			$ 750
Interest Rate			3.30%
COLUMBIA PIPELINE GROUP, INC. \| Senior Unsecured Notes due June 2018
Debt Instrument [Line Items]
Amount													$ 500
Interest Rate													2.45%
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
TC PIPELINES, LP \| Unsecured Term Loan Due June 2019
Debt Instrument [Line Items]
Amount						$ 50
TC PIPELINES, LP \| Unsecured Term Loan due December 2018
Debt Instrument [Line Items]
Amount											$ 170
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Unsecured Loan Facility due October 2020
Debt Instrument [Line Items]
Amount		$ 99
PORTLAND NATURAL GAS TRANSMISSION SYSTEM \| Senior Secured Notes due May 2018
Debt Instrument [Line Items]
Amount														$ 18
Interest Rate														5.90%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP \| Senior Unsecured Notes due March 2018
Debt Instrument [Line Items]
Amount																$ 9
Interest Rate															6.73%	6.73%

LONG-TERM DEBT - Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Interest Expense [Abstract]
Capitalized interest	$ (294)	$ (186)	$ (124)
Amortization and other financial charges	43	55	48
Interest expense	2,228	2,333	2,265
Interest payments, net of interest capitalized	2,203	2,295	2,156
Short-term debt
Interest Expense [Abstract]
Interest on debt	46	106	73
Long-term debt (excluding junior subordinated notes)
Interest Expense [Abstract]
Interest on debt	1,963	1,931	1,877
Junior subordinated notes
Interest Expense [Abstract]
Interest on debt	$ 470	$ 427	$ 391

JUNIOR SUBORDINATED NOTES (Details)	1 Months Ended	12 Months Ended
JUNIOR SUBORDINATED NOTES (Details)	Sep. 30, 2019 USD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 USD ($)
Debt Instrument [Line Items]
Outstanding		$ 36,956,000,000			$ 37,019,000,000
Unamortized debt discount and issue costs		(238,000,000)			(228,000,000)
Long-term Debt						$ 200,000,000
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding		30,228,000,000			29,433,000,000
TRANSCANADA PIPELINES LIMITED \| Junior subordinated notes
Debt Instrument [Line Items]
Outstanding		8,578,000,000			8,694,000,000
Unamortized debt discount and issue costs		(80,000,000)			(80,000,000)
Long-term Debt		$ 8,498,000,000			8,614,000,000
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		$ 1,275,000,000			$ 1,296,000,000
Effective Interest Rate		4.10%		4.10%	5.10%	5.10%
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		$ 957,000,000			$ 972,000,000
Effective Interest Rate		5.00%		5.00%	6.00%	6.00%
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		$ 1,530,000,000			$ 1,556,000,000
Effective Interest Rate		5.80%		5.80%	6.70%	6.70%
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		$ 1,913,000,000			$ 1,944,000,000
Effective Interest Rate		4.70%		4.70%	5.70%	5.70%
TRANSCANADA PIPELINES LIMITED \| Canadian junior subordinated debt, due 2077 \| Junior subordinated notes
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,500,000,000
Stated interest rate		4.90%		4.90%
Outstanding		$ 1,500,000,000			$ 1,500,000,000
Effective Interest Rate		4.50%		4.50%	5.40%	5.40%
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		$ 1,403,000,000			$ 1,426,000,000
Effective Interest Rate		5.40%		5.40%	6.30%	6.30%
Stated interest rate, period of time		10 years
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 \| September 2029 until September 2049 \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Variable interest rate	4.404%
TRANSCANADA PIPELINES LIMITED \| Trust Notes - Series 2019-A \| September 2049 until September 2079 \| Junior subordinated notes \| LIBOR
Debt Instrument [Line Items]
Variable interest rate	5.154%
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 \| First Ten Years \| Notes payable
Debt Instrument [Line Items]
Stated interest rate	5.50%

REDEEMABLE NON-CONTROLLING INTERESTS AND NON-CONTROLLING INTERESTS - Narrative (Details) $ in Millions				12 Months Ended
	Jan. 08, 2021 USD ($)	Dec. 31, 2020 CAD ($)	Mar. 31, 2020 USD ($)	Dec. 31, 2020 CAD ($)	Jan. 04, 2021 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018
Non-controlling interests
Amount committed from others			$ 1,100,000,000
Class A Interests issued				$ 1,033
Amount reclassified		$ 630
Redeemable non-controlling interest		$ 633		633		$ 0
Redeemable noncontrolling interest, interest expense				$ 3
Subsequent Event
Non-controlling interests
Repurchase of Class A Interests	$ 497,000,000
Keystone XL \| Revolving credit facility \| Line of credit \| Subsequent Event
Non-controlling interests
Revolving credit facility, borrowing capacity					$ 4,100,000,000
Proceeds from lines of credit	$ 579,000,000
TC Pipe Lines LP \| Noncontrolling Interest
Non-controlling interests
Percentage of non-controlling interests		74.50%		74.50%		74.50%
TC Pipe Lines LP \| Noncontrolling Interest \| Minimum
Non-controlling interests
Percentage of non-controlling interests							74.30%
TC Pipe Lines LP \| Noncontrolling Interest \| Maximum
Non-controlling interests
Percentage of non-controlling interests							74.50%

REDEEMABLE NON-CONTROLLING INTERESTS AND NON-CONTROLLING INTERESTS - Schedule of Redeemable Non-controlling interest (Details) - CAD ($) $ in Millions		12 Months Ended
	Dec. 31, 2020	Dec. 31, 2020	Dec. 31, 2019
Increase (Decrease) in Temporary Equity [Roll Forward]
Balance at beginning of year		$ 0
Class A Interests issued		1,033
Redeemable non-controlling interest		(10)	$ 0
Class A Interests transferred to Current liabilities	$ (630)
Balance at end of year	$ 393	$ 393	$ 0

REDEEMABLE NON-CONTROLLING INTERESTS AND NON-CONTROLLING INTERESTS - Schedule of Non-controlling Interests (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Non-controlling interests
Non-controlling interests in TC PipeLines, LP	$ 1,682	$ 1,634
Non-controlling interest in TC PipeLines, LP	307	293	$ (185)
Redeemable non-controlling interest	(10)	0
Total non-controlling interests	297	293	(185)
Equity Attributable to Non-Controlling Interests
Non-controlling interests
Total non-controlling interests	(307)	(293)	$ 185
TC PipeLines, LP \| Equity Attributable to Non-Controlling Interests
Non-controlling interests
Non-controlling interests in TC PipeLines, LP	$ 1,682	$ 1,634

- Definition

Total of all stockholders' equity (deficit) items, net of receivables from officers, directors, owners, and affiliates of the entity which is directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent (that is, noncontrolling interest, previously referred to as minority interest).

+ References + Details

COMMON SHARES - Reconciliation and Weighted Average Common Shares Outstanding (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)	938,000
Outstanding at the beginning of the period	$ 24,387
Exercise of options (in shares)	1,664
Outstanding at the end of the period (in shares)	940,000	938,000
Outstanding at the end of the period	$ 24,488	$ 24,387
Weighted Average Common Shares Outstanding
Basic (in shares)	940,000	929,000	902,000
Diluted (in shares)	940,000	931,000	903,000
Common Shares
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)	938,400	918,097	881,376
Outstanding at the beginning of the period	$ 24,387	$ 23,174	$ 21,167
At-the-market equity issuance program (in shares)			20,050
At-the-market equity issuance program			$ 1,118
Dividend reinvestment and share purchase plan (in shares)		15,165	15,937
Dividend reinvestment and share purchase plan		$ 931	$ 855
Exercise of options (in shares)	1,664	5,138	734
Exercise of options	$ 101	$ 282	$ 34
Outstanding at the end of the period (in shares)	940,064	938,400	918,097
Outstanding at the end of the period	$ 24,488	$ 24,387	$ 23,174
Weighted Average Common Shares Outstanding
Basic (in shares)	940,000	929,000	902,000
Diluted (in shares)	940,000	931,000	903,000

COMMON SHARES - TC Energy Corporation At-the-Market Equity Issuance Program (Details) - At-the-Market Equity Issuance Program - CAD ($)		1 Months Ended		12 Months Ended
	Dec. 07, 2020	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2020
Subsidiary, Sale of Stock [Line Items]
Stock issuance program, period in effect (in months)	25 months		25 months
Authorized amount		$ 2,000,000,000.0	$ 1,000,000,000.0			$ 1,000,000,000.0
Additional authorized amount		$ 1,000,000,000.0
Treasury stock reissued during period (in shares)				0	20,000,000
Price per share (in Canadian dollars per share)					$ 56.13
Consideration received on transaction					$ 1,100,000,000
Payments of stock issuance costs					$ 10,000,000

COMMON SHARES - Dividend Reinvestment and Share Purchase Plan (Details)	12 Months Ended
	Dec. 31, 2019
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Discount of shares issued from treasury	2.00%
Price of shares issued from treasury	100.00%

COMMON SHARES - Options (Details)	12 Months Ended
COMMON SHARES - Options (Details)	Dec. 31, 2020 $ / shares shares
Number of Options (thousands)
Outstanding at the beginning of the period (in shares)	9,094,000
Granted (in shares)	1,714,000
Exercised (in shares)	(1,664,000)
Options forfeited/expired (in shares)	(148,000)
Outstanding at the end of the period (in shares)	8,996,000
Options Exercisable (in shares)	5,395,000
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share) \| $ / shares	$ 55.77
Granted (in Canadian dollars per share) \| $ / shares	75.06
Exercised (in Canadian dollars per share) \| $ / shares	54.47
Options forfeited/expired (in Canadian dollars per share) \| $ / shares	63.95
Outstanding at the end of the period (in Canadian dollars per share) \| $ / shares	59.55
Options Exercisable at December 31, 2020 (in Canadian dollars per share) \| $ / shares	$ 55.74
Weighted Average Remaining Contractual Life (years)
Options Outstanding at December 31, 2020	3 years 9 months 18 days
Options Exercisable at December 31, 2020	2 years 9 months 18 days
Number of shares available for grant (in shares)	6,396,168
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 Assumptions Used (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Weighted average fair value (in dollars per share)	$ 7.73	$ 6.37	$ 5.80
Expected life	5 years 8 months 12 days	5 years 8 months 12 days	5 years 8 months 12 days
Interest rate	1.50%	1.90%	2.10%
Volatility	17.00%	19.00%	16.00%
Dividend yield	4.20%	5.00%	4.20%
Expense for stock options	$ 12	$ 13	$ 13
Unrecognized compensation costs related to non-vested stock options	$ 14
Employee Stock Option
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Expense recognition period	1 year 8 months 12 days

COMMON SHARES - Summary of Additional Stock Options Information (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Total intrinsic value of options exercised	$ 31	$ 75	$ 10
Total fair value of options that have vested	$ 101	$ 143	$ 101
Total options vested (in shares)	2.0	2.1	2.1
Options, exercisable, intrinsic value	$ 5
Options, outstanding, intrinsic value	$ 5

COMMON SHARES - Shareholder Rights Plan (Details)	Dec. 31, 2020 shares
Shareholder Rights Plan
Number of rights entitled to each common share (in shares)	1

PREFERRED SHARES (Details) $ / shares in Units, $ in Millions						1 Months Ended	6 Months Ended	12 Months Ended
	Nov. 30, 2020	Jun. 30, 2020 shares	Dec. 31, 2019 CAD ($) shares	Oct. 30, 2019	Apr. 30, 2019	Dec. 31, 2020 CAD ($) $ / shares shares	Dec. 31, 2020 CAD ($) $ / shares shares	Dec. 31, 2020 CAD ($) $ / shares shares	Dec. 31, 2018 CAD ($)
Preferred Shares [Line Items]
Carrying Value December 31 \| $			$ 3,980			$ 3,980	$ 3,980	$ 3,980	$ 3,980
Series 1
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						14,577,000	14,577,000	14,577,000
Current Yield								3.479%
Annual Dividend Rate per Share (in Canadian dollars per share)								$ 0.86975
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			$ 360			$ 360	$ 360	$ 360	233
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%	1.92%	1.92%
Series 2
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						7,423,000	7,423,000	7,423,000
Current Yield								2.029%
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			$ 179			$ 179	$ 179	$ 179	306
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%	1.92%	1.92%
Series 3
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						9,997,000	9,997,000	9,997,000
Current Yield		2.152%					1.694%	1.694%
Annual Dividend Rate per Share (in Canadian dollars per share)								$ 0.4235
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			$ 209			$ 246	$ 246	$ 246	209
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%	1.28%	1.28%
Series 4
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						4,003,000	4,003,000	4,003,000
Current Yield								1.389%
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			134			$ 97	$ 97	$ 97	134
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%	1.28%	1.28%
Series 5
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						12,714,000	12,714,000	12,714,000
Current Yield								2.263%
Annual Dividend Rate per Share (in Canadian dollars per share)								$ 0.56575
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			310			$ 310	$ 310	$ 310	310
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%	1.54%	1.54%
Series 6
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						1,286,000	1,286,000	1,286,000
Current Yield								1.676%
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			32			$ 32	$ 32	$ 32	32
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%	1.54%	1.54%
Series 7
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						24,000,000	24,000,000	24,000,000
Current Yield					4.00%			3.903%
Annual Dividend Rate per Share (in Canadian dollars per share)								$ 0.97575
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			589			$ 589	$ 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%	2.38%	2.38%
Series 9
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						18,000,000	18,000,000	18,000,000
Current Yield				4.25%				3.762%
Annual Dividend Rate per Share (in Canadian dollars per share)								$ 0.9405
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			442			$ 442	$ 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%	2.35%	2.35%
Series 11
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						10,000,000	10,000,000	10,000,000
Current Yield	3.80%					3.351%		3.351%
Annual Dividend Rate per Share (in Canadian dollars per share)								$ 0.83775
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			244			$ 244	$ 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%	2.96%	2.96%
Series 13
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						20,000,000	20,000,000	20,000,000
Current Yield								5.50%
Annual Dividend Rate per Share (in Canadian dollars per share)								$ 1.375
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			493			$ 493	$ 493	$ 493	493
Series 13 \| 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						4.69%	4.69%	4.69%
Preferred stock, fixed percentage added To Bond Or Treasury Bill rate for calculating dividend yield, minimum						5.50%	5.50%	5.50%
Series 15
Preferred Shares [Line Items]
Number of Shares Outstanding (in shares) \| shares						40,000,000	40,000,000	40,000,000
Current Yield								4.90%
Annual Dividend Rate per Share (in Canadian dollars per share)								$ 1.225
Redemption Price Per Share (in Canadian dollars per share)						$ 25.00	$ 25.00	$ 25.00
Carrying Value December 31 \| $			$ 988			$ 988	$ 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%	3.85%	3.85%
Preferred stock, fixed percentage added To Bond Or Treasury Bill rate for calculating dividend yield, minimum						4.90%	4.90%	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%	2.38%	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%	2.35%	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%	2.96%	2.96%
Series 14 \| 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						4.69%	4.69%	4.69%
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%	3.85%	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)						$ 25.50	$ 25.50	$ 25.50

OTHER COMPREHENSIVE (LOSS) / INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCI) - Components (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Before Tax Amount
Other Comprehensive Loss	$ (1,056)	$ (1,055)	$ 1,259
Income Tax Recovery/(Expense)
Other Comprehensive Loss	138	3	55
Net of Tax Amount
Other comprehensive (loss)/ income (Note 23)	(918)	(1,052)	1,314
Foreign currency translation losses on net investment in foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(647)	(914)	1,323
Reclassification from accumulated other comprehensive Income		(13)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	38	(30)	35
Reclassification from AOCI		0
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(609)	(944)	1,358
Reclassification from accumulated other comprehensive income		(13)
Change in fair value of net investment hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	48	46	(57)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	(12)	(11)	15
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	36	35	(42)
Change in fair value and reclassification of gains and losses of cash flow hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(771)	(78)	(14)
Reclassification from accumulated other comprehensive Income	649	19	27
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	188	16	4
Reclassification from AOCI	(160)	(5)	(6)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(583)	(62)	(10)
Reclassification from accumulated other comprehensive income	489	14	21
Unrealized actuarial gains and losses and reclassification of actuarial gains and losses of pension and other post-retirement benefits
Before Tax Amount
Other comprehensive income (loss), before reclassifications	15	(15)	(153)
Reclassification from accumulated other comprehensive Income	23	14	20
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	(3)	5	39
Reclassification from AOCI	(6)	(4)	(5)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	12	(10)	(114)
Reclassification from accumulated other comprehensive income	17	10	15
Other comprehensive loss on equity investments
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(373)
Other Comprehensive Loss		(114)	113
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	93
Other Comprehensive Loss		32	(27)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	$ (280)
Other comprehensive (loss)/ income (Note 23)		$ (82)	$ 86

OTHER COMPREHENSIVE (LOSS) / INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCI) - Reconciliation (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	$ 32,397,000,000	$ 30,993,000,000
Other comprehensive (loss)/ income (Note 23)	(918,000,000)	(1,052,000,000)	$ 1,314,000,000
Balance at end of year	33,080,000,000	32,397,000,000	30,993,000,000
Cash flow hedge loss to be reclassified within twelve months	37,000,000
Cash flow hedge loss to be reclassified within twelve months, net of tax	28,000,000
Currency Translation Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(730,000,000)	107,000,000	(1,043,000,000)
Other comprehensive (loss) / income, before reclassifications	(543,000,000)	(824,000,000)	1,150,000,000
Amounts reclassified from AOCI	0	(13,000,000)	0
Other comprehensive (loss)/ income (Note 23)	(543,000,000)	(837,000,000)	1,150,000,000
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform			0
Balance at end of year	(1,273,000,000)	(730,000,000)	107,000,000
Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(58,000,000)	(23,000,000)	(31,000,000)
Other comprehensive (loss) / income, before reclassifications	(567,000,000)	(49,000,000)	(9,000,000)
Amounts reclassified from AOCI	482,000,000	14,000,000	16,000,000
Other comprehensive (loss)/ income (Note 23)	(85,000,000)	(35,000,000)	7,000,000
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform			1,000,000
Balance at end of year	(143,000,000)	(58,000,000)	(23,000,000)
Pension and Other Post-Retirement Benefit Plan Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(314,000,000)	(314,000,000)	(203,000,000)
Other comprehensive (loss) / income, before reclassifications	12,000,000	(10,000,000)	(114,000,000)
Amounts reclassified from AOCI	17,000,000	10,000,000	15,000,000
Other comprehensive (loss)/ income (Note 23)	29,000,000	0	(99,000,000)
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform			(12,000,000)
Balance at end of year	(285,000,000)	(314,000,000)	(314,000,000)
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(457,000,000)	(376,000,000)	(454,000,000)
Other comprehensive (loss) / income, before reclassifications	(292,000,000)	(86,000,000)	72,000,000
Amounts reclassified from AOCI	11,000,000	5,000,000	12,000,000
Other comprehensive (loss)/ income (Note 23)	(281,000,000)	(81,000,000)	84,000,000
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform			(6,000,000)
Balance at end of year	(738,000,000)	(457,000,000)	(376,000,000)
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(1,559,000,000)	(606,000,000)	(1,731,000,000)
Other comprehensive (loss) / income, before reclassifications	(1,390,000,000)	(969,000,000)	1,099,000,000
Amounts reclassified from AOCI	510,000,000	16,000,000	43,000,000
Other comprehensive (loss)/ income (Note 23)	(880,000,000)	(953,000,000)	1,142,000,000
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform			(17,000,000)
Balance at end of year	(2,439,000,000)	(1,559,000,000)	(606,000,000)
Accumulated foreign currency adjustment attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive (loss) / income, before reclassifications	(30,000,000)	(85,000,000)	166,000,000
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	(16,000,000)	(13,000,000)	(1,000,000)
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	$ 1,000,000	$ 1,000,000	$ 0

OTHER COMPREHENSIVE (LOSS) / INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCI) - Reclassifications (Details) - CAD ($) $ in Millions		12 Months Ended
	May 22, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Storage)		$ 12,999	$ 13,255	$ 13,679
Interest expense		(2,228)	(2,333)	(2,265)
Net (loss)/ gain on assets sold/held for sale		(50)	(121)	170
Total before tax		5,107	5,187	3,949
Income tax expense		(194)	(754)	(432)
Plant operating costs and other		3,878	3,913	3,593
Income from equity investments		1,019	920	714
Net Income Attributable to Common Shares		4,457	3,976	3,539
Reclassification to net income of gains and losses on cash flow hedges		(489)	(14)	(21)
Disposal group, disposed of by sale, not discontinued operations \| Coastal GasLink
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net (loss)/ gain on assets sold/held for sale	$ 364
Ownership interest sold	65.00%
Coastal GasLink
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Ownership interest sold	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)
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		(642)	(19)	(22)
Income tax expense		160	5	6
Net Income Attributable to Common Shares		(482)	(14)	(16)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Cash flow hedges \| Interest rate
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense		(28)	(12)	(18)
Net (loss)/ gain on assets sold/held for sale		(613)	0	0
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		(23)	(14)	(16)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Settlement charge
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other			0	(4)
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		(23)	(14)	(20)
Income tax expense		6	4	5
Net Income Attributable to Common Shares		(17)	(10)	(15)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income tax expense		4	3	4
Income from equity investments		(15)	(8)	(16)
Net Income Attributable to Common Shares		(11)	(5)	(12)
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Currency translation adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net (loss)/ gain on assets sold/held for sale			13	0
Income tax expense			0	0
Net Income Attributable to Common Shares			13	0
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		7	0	5
Amounts Reclassified From Accumulated Other Comprehensive Loss \| Accumulated net gain (loss) from equity investments attributable to noncontrolling interest
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income Attributable to Common Shares		0	0	2
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)		$ (1)	$ (7)	$ (4)

EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments, Changes and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized	11 years	11 years	12 years
Expense for savings plan and DC Plans	$ 58	$ 61	$ 59
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Savings and DC Plans	58	61	59
Total cash contributions	191	205	$ 185
Change in Plan Assets
Plan assets at fair value – beginning of year	4,099
Plan assets at fair value – end of year	4,479	4,099
Amounts recognized in the Balance Sheet
Other long-term assets (Note 13)	207	162
Other long-term liabilities (Note 16)	$ (503)	$ (540)
Pension Benefit Plans
Employee post-retirement benefits
Consecutive period of employment for highest average earnings	3 years
Expected average remaining service life of employees over which past service costs are amortized	9 years	9 years	9 years
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans	$ 124	$ 122	$ 103
Total amount outstanding under letters of credit	13	12
Change in Benefit Obligation
Benefit obligation – beginning of year	4,058	3,653
Service cost	155	126
Interest cost	133	142
Employee contributions	6	5
Benefits paid	(249)	(213)
Actuarial loss	242	394
Foreign exchange rate changes	(19)	(49)
Benefit obligation – end of year	4,326	4,058	3,653
Change in Plan Assets
Plan assets at fair value – beginning of year	3,693	3,321
Actual return on plan assets	485	505
Employer contributions	124	122
Employee contributions	6	5
Benefits paid	(249)	(212)
Foreign exchange rate changes	(21)	(48)
Plan assets at fair value – end of year	4,038	3,693	3,321
Funded Status – Plan Deficit	$ (288)	$ (365)
Discount rate	2.70%	3.20%
Amounts recognized in the Balance Sheet
Other long-term assets (Note 13)	$ 29	$ 0
Accounts payable and other	0	0
Other long-term liabilities (Note 16)	(317)	(365)
Net	(288)	(365)
Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans	9	22	23
Change in Benefit Obligation
Benefit obligation – beginning of year	427	430
Service cost	6	5
Interest cost	14	17
Employee contributions	0	0
Benefits paid	(21)	(24)
Actuarial loss	36	13
Foreign exchange rate changes	(5)	(14)
Benefit obligation – end of year	457	427	430
Change in Plan Assets
Plan assets at fair value – beginning of year	406	376
Actual return on plan assets	56	52
Employer contributions	9	22
Employee contributions	0	0
Benefits paid	(21)	(24)
Foreign exchange rate changes	(9)	(20)
Plan assets at fair value – end of year	441	406	376
Funded Status – Plan Deficit	$ (16)	$ (21)
Discount rate	2.75%	3.35%
Amounts recognized in the Balance Sheet
Other long-term assets (Note 13)	$ 178	$ 162
Accounts payable and other	(8)	(8)
Other long-term liabilities (Note 16)	(186)	(175)
Net	(16)	(21)
Canadian \| Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Letter of credit to the DB Plan	13	$ 12	17
Total amount outstanding under letters of credit	$ 302
U.S. \| Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Settlement and curtailment gain (loss), after tax			4
Net periodic benefit cost, settlement charge			$ 4

EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Benefit obligation and fair value of plan assets for plans that are not fully funded
Plan assets at fair value	$ 4,479	$ 4,099
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	$ (4,326)	$ (4,058)	$ (3,653)
Plan assets at fair value	4,038	3,693	3,321
Funded Status – Plan Deficit	(288)	(365)
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(3,957)	(3,719)
Plan assets at fair value	4,038	3,693
Funded Status – Plan Deficit	$ 81	$ (26)
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	33.00%	32.00%
Company debt or common shares included in plan assets, amount	$ 13	$ 9
Company debt or common shares included in plan assets, percentage	0.30%	0.20%
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	57.00%	58.00%
Company debt or common shares included in plan assets, amount	$ 5	$ 15
Company debt or common shares included in plan assets, percentage	0.10%	0.40%
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	10.00%	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	$ (3,292)	$ (4,058)
Plan assets at fair value	2,975	3,693
Funded Status – Plan Deficit	(317)	(365)
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	0	(2,397)
Plan assets at fair value	0	2,351
Funded Status – Plan Deficit	0	(46)
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	(457)	(427)	(430)
Plan assets at fair value	441	406	$ 376
Funded Status – Plan Deficit	(16)	(21)
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	(194)	(182)
Plan assets at fair value	0	0
Funded Status – Plan Deficit	$ (194)	$ (182)

EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	$ 4,099
Plan assets at fair value – end of year	4,479	$ 4,099
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	379	362
Purchases and sales	42	35
Realized and unrealized losses	(4)	(18)
Plan assets at fair value – end of year	$ 417	$ 379

- Definition

Amount of asset segregated and restricted to provide benefit under defined benefit plan. Asset includes, but is not limited to, stock, bond, other investment, earning from investment, and contribution by employer and employee.

+ References + Details

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for savings plan and DC Plans	$ 59
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits	6.30%
Percentage level to which average annual rate was assumed to decrease	4.80%
Pension Benefit Plans
DB Plans
Company's expected funding contributions	$ 128
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	13
Estimated future benefit payments, which reflect expected future service
2021	208
2022	210
2023	213
2024	215
2025	217
2026 to 2030	$ 1,115
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	2.70%	3.20%
Rate of compensation increase	2.60%	3.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	3.20%	3.90%	3.60%
Expected long-term rate of return on plan assets	6.40%	6.60%	6.70%
Rate of compensation increase	3.00%	3.00%	3.00%
Net benefit cost
Service cost	$ 155	$ 126	$ 121
Other components of net benefit cost
Interest cost	133	142	134
Expected return on plan assets	(230)	(222)	(221)
Amortization of actuarial loss	21	12	15
Amortization of regulatory asset	25	14	18
Settlement charge – AOCI	0	0	4
Other components of net benefit cost	(51)	(54)	(50)
Net Benefit Cost Recognized	104	72	71
Pre-tax amounts recognized in AOCI
Net loss	358	398	364
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to net income	(21)	(12)	(15)
Settlement	0	0	(4)
Funded status adjustment	(18)	52	110
Total pre-tax amounts recognized in OCI	(39)	$ 40	$ 91
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	6
Estimated future benefit payments, which reflect expected future service
2021	25
2022	25
2023	25
2024	25
2025	25
2026 to 2030	$ 120
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	2.75%	3.35%
Rate of compensation increase	0.00%	0.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	3.35%	4.10%	3.70%
Expected long-term rate of return on plan assets	3.50%	4.30%	4.00%
Rate of compensation increase	0.00%	0.00%	0.00%
Net benefit cost
Service cost	$ 6	$ 5	$ 4
Other components of net benefit cost
Interest cost	14	17	14
Expected return on plan assets	(14)	(15)	(16)
Amortization of actuarial loss	2	2	1
Amortization of regulatory asset	2	2	0
Settlement charge – AOCI	0	0	0
Other components of net benefit cost	4	6	(1)
Net Benefit Cost Recognized	10	11	3
Pre-tax amounts recognized in AOCI
Net loss	22	20	53
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to net income	(2)	(2)	(1)
Settlement	0	0	0
Funded status adjustment	3	(37)	43
Total pre-tax amounts recognized in OCI	$ 1	$ (39)	$ 42

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Derivative [Line Items]
Fair Value	$ 145	$ 1
Designated as a net investment hedge
Derivative [Line Items]
Fair Value	68	13
Designated as a net investment hedge \| US$ denominated
Derivative [Line Items]
Notional Amount			$ 2,600	$ 3,100
Designated as a net investment hedge \| U.S. dollar foreign exchange options (maturing 2021)
Derivative [Line Items]
Fair Value	45	10
Designated as a net investment hedge \| U.S. dollar foreign exchange options (maturing 2021) \| US$ denominated
Derivative [Line Items]
Notional Amount			2,200	3,000
Designated as a net investment hedge \| U.S. dollar cross-currency interest rate swaps (maturing 2022 to 2025)
Derivative [Line Items]
Fair Value	23	3
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	$ 100
Net realized gains related to the interest component	$ 1	$ 0

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, 2020 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 USD ($)
Derivative [Line Items]
Notional amount	$ 27,700		$ 29,300
Fair value	$ 33,800		$ 33,400
US$ denominated
Derivative [Line Items]
Notional amount		$ 21,800		$ 22,600
Fair value		$ 26,500		$ 25,700

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	$ (36,956)	$ (37,019)
Junior subordinated notes (Note 19)	(8,498)	(8,614)
Long-term debt				$ 200
Interest rate swap agreements
Carrying and fair values of non-derivative financial instruments
Unrealized losses on hedged items	0	3
Long-term debt hedged			$ 200	$ 200
Level II \| Carrying Amount
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	(36,885)	(36,985)
Junior subordinated notes (Note 19)	(8,498)	(8,614)
Total liabilities	(45,383)	(45,599)
Level II \| Fair Value
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion	(46,054)	(43,187)
Junior subordinated notes (Note 19)	(8,908)	(8,777)
Total liabilities	$ (54,962)	$ (51,964)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Total Derivatives
Derivative Assets	$ 276	$ 197
Derivative Liabilities	(131)	(196)
Total Derivatives	145	1
Payments to settle interest rate hedge	(130)	0	$ 0
Total trading activity
Total Derivatives
Derivative Assets	207	179
Derivative Liabilities	(46)	(118)
Total Derivatives	161	61
Cash Flow Hedges
Total Derivatives
Derivative Assets	0	2
Derivative Liabilities	(84)	(76)
Total Derivatives	(84)	(74)
Fair Value Hedges
Total Derivatives
Derivative Assets		1
Derivative Liabilities		0
Total Derivatives		1
Net Investment Hedges
Total Derivatives
Derivative Assets	69	15
Derivative Liabilities	(1)	(2)
Total Derivatives	68	13
Other current assets
Total Derivatives
Derivative Assets	235	190
Other current assets \| Total trading activity
Total Derivatives
Derivative Assets	188	179
Other current assets \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Fair Value Hedges
Total Derivatives
Derivative Assets		1
Other current assets \| Net Investment Hedges
Total Derivatives
Derivative Assets	47	10
Other current assets \| Commodities
Total Derivatives
Derivative Assets	13	118
Other current assets \| Commodities \| Commodities
Total Derivatives
Derivative Assets	13	118
Other current assets \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Assets		0
Other current assets \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Foreign exchange
Total Derivatives
Derivative Assets	222	71
Other current assets \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Assets	175	61
Other current assets \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Assets		0
Other current assets \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Assets	47	10
Other current assets \| Interest rate
Total Derivatives
Derivative Assets		1
Other current assets \| Interest rate \| Interest rate
Total Derivatives
Derivative Assets		0
Other current assets \| Interest rate \| Cash Flow Hedges
Total Derivatives
Derivative Assets		0
Other current assets \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Assets		1
Other current assets \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Assets		0
Other long-term assets
Total Derivatives
Derivative Assets	41	7
Other long-term assets \| Total trading activity
Total Derivatives
Derivative Assets	19	0
Other long-term assets \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	2
Other long-term assets \| Fair Value Hedges
Total Derivatives
Derivative Assets		0
Other long-term assets \| Net Investment Hedges
Total Derivatives
Derivative Assets	22	5
Other long-term assets \| Foreign exchange
Total Derivatives
Derivative Assets	41	5
Other long-term assets \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Assets	19	0
Other long-term assets \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Other long-term assets \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Assets		0
Other long-term assets \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Assets	22	5
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 \| Fair Value Hedges
Total Derivatives
Derivative Assets		0
Other long-term assets \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Assets		0
Accounts payable and other
Total Derivatives
Derivative Liabilities	(72)	(115)
Accounts payable and other \| Total trading activity
Total Derivatives
Derivative Liabilities	(42)	(107)
Accounts payable and other \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(29)	(7)
Accounts payable and other \| Fair Value Hedges
Total Derivatives
Derivative Liabilities		0
Accounts payable and other \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	(1)	(1)
Accounts payable and other \| Commodities
Total Derivatives
Derivative Liabilities	(40)	(108)
Accounts payable and other \| Commodities \| Commodities
Total Derivatives
Derivative Liabilities	(32)	(104)
Accounts payable and other \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(8)	(4)
Accounts payable and other \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Liabilities		0
Accounts payable and other \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Foreign exchange
Total Derivatives
Derivative Liabilities	(11)	(4)
Accounts payable and other \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Liabilities	(10)	(3)
Accounts payable and other \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Accounts payable and other \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Liabilities		0
Accounts payable and other \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	(1)	(1)
Accounts payable and other \| Interest rate
Total Derivatives
Derivative Liabilities	(21)	(3)
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	(21)	(3)
Accounts payable and other \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Liabilities		0
Accounts payable and other \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities
Total Derivatives
Derivative Liabilities	(59)	(81)
Other long-term liabilities \| Total trading activity
Total Derivatives
Derivative Liabilities	(4)	(11)
Other long-term liabilities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(55)	(69)
Other long-term liabilities \| Fair Value Hedges
Total Derivatives
Derivative Liabilities		0
Other long-term liabilities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	(1)
Other long-term liabilities \| Commodities
Total Derivatives
Derivative Liabilities	(10)	(17)
Other long-term liabilities \| Commodities \| Commodities
Total Derivatives
Derivative Liabilities	(4)	(11)
Other long-term liabilities \| Commodities \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(6)	(6)
Other long-term liabilities \| Commodities \| Fair Value Hedges
Total Derivatives
Derivative Liabilities		0
Other long-term liabilities \| Commodities \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities \| Foreign exchange
Total Derivatives
Derivative Liabilities		(1)
Other long-term liabilities \| Foreign exchange \| Foreign exchange
Total Derivatives
Derivative Liabilities		0
Other long-term liabilities \| Foreign exchange \| Cash Flow Hedges
Total Derivatives
Derivative Liabilities		0
Other long-term liabilities \| Foreign exchange \| Fair Value Hedges
Total Derivatives
Derivative Liabilities		0
Other long-term liabilities \| Foreign exchange \| Net Investment Hedges
Total Derivatives
Derivative Liabilities		(1)
Other long-term liabilities \| Interest rate
Total Derivatives
Derivative Liabilities	(49)	(63)
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	(49)	(63)
Other long-term liabilities \| Interest rate \| Fair Value Hedges
Total Derivatives
Derivative Liabilities		0
Other long-term liabilities \| Interest rate \| Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
LMCI Restricted Investments
Fair value
Fair value of equity securities	736	556
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains	130	32	11
Net realized gains/(losses)	20	60	(4)
Other Restricted Investments
Fair value
Fair value of equity securities	0	0
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains	1	3	0
Net realized gains/(losses)	1	0	$ 0
Fixed income securities \| LMCI Restricted Investments
Fair value
Maturing within 1 year	0	0
Maturing within 1-5 years	0	26
Maturing within 5-10 years	985	801
Maturing after 10 years	85	61
Fair value of securities	1,806	1,444
Fixed income securities \| Other Restricted Investments
Fair value
Maturing within 1 year	17	6
Maturing within 1-5 years	66	100
Maturing within 5-10 years	0	0
Maturing after 10 years	0	0
Fair value of securities	$ 83	$ 106

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Fair Value Hedging Relationships (Details) - CAD ($)	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value hedging adjustments, discontinued hedges	$ 0	$ 0
Long-term debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Carrying amount	0	(260,000,000)
Fair value hedging adjustments	$ 0	$ (1,000,000)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional and Maturity Summary (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) GWh Bcf MMBbls	Dec. 31, 2019 USD ($) GWh Bcf MMBbls	Dec. 31, 2020 MXN ($)	Dec. 31, 2019 MXN ($)
Commodities \| Power
Derivative [Line Items]
Notional amount, energy (gwh) \| GWh	0	0
Commodities \| Power \| Purchases
Derivative [Line Items]
Notional amount, energy (gwh) \| GWh	185	492
Commodities \| Power \| Sales
Derivative [Line Items]
Notional amount, energy (gwh) \| GWh	1,786	2,089
Commodities \| Natural Gas
Derivative [Line Items]
Notional amount	$ 0	$ 0	$ 0	$ 0
Commodities \| Natural Gas \| Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| Bcf	13	14
Commodities \| Natural Gas \| Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| Bcf	14	22
Commodities \| Liquids
Derivative [Line Items]
Notional amount	$ 0	$ 0	0	0
Commodities \| Liquids \| Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| MMBbls	26	39
Commodities \| Liquids \| Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| MMBbls	30	53
Foreign exchange
Derivative [Line Items]
Notional amount	$ 4,432	$ 3,153	1,700	800
Foreign exchange \| Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| Bcf	0	0
Foreign exchange \| Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| Bcf	0	0
Interest rate
Derivative [Line Items]
Notional amount	$ 1,100	$ 1,600	$ 0	$ 0
Interest rate \| Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| MMBbls	0	0
Interest rate \| Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) \| MMBbls	0	0

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses) / Gains on Derivative Instruments (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
U.S. Northeast Merchant Power Assets
Derivative [Line Items]
Gain (loss) on cash flow hedge	$ 0	$ 0	$ 0
Commodities
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	(23,000,000)	(111,000,000)	28,000,000
Amount of realized gains /(losses) in the year	183,000,000	378,000,000	351,000,000
Commodities \| Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized gains /(losses) in the year	6,000,000	(6,000,000)	(1,000,000)
Foreign exchange
Derivative [Line Items]
Amount of unrealized (losses) / gains in the year	126,000,000	245,000,000	(248,000,000)
Amount of realized gains /(losses) in the year	(33,000,000)	(70,000,000)	(24,000,000)
Interest rate \| Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized gains /(losses) in the year	$ (16,000,000)	$ 2,000,000	$ (1,000,000)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ (771)	$ (78)	$ (14)
Commodities
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	(5)	(15)	(1)
Interest rate
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI	$ (766)	$ (63)	$ (13)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Effect of Fair Value and Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions		12 Months Ended
	May 22, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disposal group, disposed of by sale, not discontinued operations \| Coastal GasLink
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Ownership interest sold	65.00%
Coastal GasLink
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Ownership interest sold	65.00%
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Change in fair value of derivative instruments recognized in OCI		$ (613)
Interest Expense \| Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged items		(3)	$ (19)	$ (71)
Derivatives designated as hedging instruments		1	1	(4)
Reclassification of gains/(losses) on derivative instruments from AOCI to net income		(648)	(12)	(22)
Change in fair value of derivative instruments recognized in OCI		(613)
Revenue \| Commodity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification of gains/(losses) on derivative instruments from AOCI to net income		$ (1)	$ (7)	$ (5)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD ($)	Dec. 31, 2020	Dec. 31, 2019
Derivative instrument assets
Gross Derivative Instruments	$ 276,000,000	$ 197,000,000
Amounts Available for Offset	(18,000,000)	(82,000,000)
Net Amounts	258,000,000	115,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(131,000,000)	(196,000,000)
Amounts Available for Offset	18,000,000	82,000,000
Net Amounts	(113,000,000)	(114,000,000)
Cash collateral provided by the Company	54,000,000	58,000,000
Letters of credit provided by the Company	15,000,000	25,000,000
Cash collateral received by the Company	0	0
Letters of credit received by the Company	0	0
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	4,000,000	4,000,000
Foreign exchange
Derivative instrument assets
Gross Derivative Instruments	263,000,000	76,000,000
Amounts Available for Offset	(11,000,000)	(5,000,000)
Net Amounts	252,000,000	71,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(11,000,000)	(5,000,000)
Amounts Available for Offset	11,000,000	5,000,000
Net Amounts	0	0
Interest rate
Derivative instrument assets
Gross Derivative Instruments		3,000,000
Amounts Available for Offset		(1,000,000)
Net Amounts		2,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(70,000,000)	(66,000,000)
Amounts Available for Offset	0	1,000,000
Net Amounts	(70,000,000)	(65,000,000)
Power \| Commodities
Derivative instrument assets
Gross Derivative Instruments	13,000,000	118,000,000
Amounts Available for Offset	(7,000,000)	(76,000,000)
Net Amounts	6,000,000	42,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(50,000,000)	(125,000,000)
Amounts Available for Offset	7,000,000	76,000,000
Net Amounts	$ (43,000,000)	$ (49,000,000)

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Fair Value Hierarchy
Derivative instrument assets	$ 276	$ 197
Derivative instrument liabilities	(131)	(196)
Recurring basis
Fair Value Hierarchy
Assets and (liabilities), net	145	1
Recurring basis \| Commodities \| Power
Fair Value Hierarchy
Derivative instrument assets	13	118
Derivative instrument liabilities	(50)	(125)
Recurring basis \| Foreign exchange
Fair Value Hierarchy
Derivative instrument assets	263	76
Derivative instrument liabilities	(11)	(5)
Recurring basis \| Interest rate
Fair Value Hierarchy
Derivative instrument assets		3
Derivative instrument liabilities	(70)	(66)
Recurring basis \| Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	(12)	4
Recurring basis \| Quoted Prices in Active Markets (Level I) \| Commodities \| Power
Fair Value Hierarchy
Derivative instrument assets	3	81
Derivative instrument liabilities	(15)	(77)
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	161	4
Recurring basis \| Significant Other Observable Inputs (Level II) \| Commodities \| Power
Fair Value Hierarchy
Derivative instrument assets	10	37
Derivative instrument liabilities	(31)	(41)
Recurring basis \| Significant Other Observable Inputs (Level II) \| Foreign exchange
Fair Value Hierarchy
Derivative instrument assets	263	76
Derivative instrument liabilities	(11)	(5)
Recurring basis \| Significant Other Observable Inputs (Level II) \| Interest rate
Fair Value Hierarchy
Derivative instrument assets		3
Derivative instrument liabilities	(70)	(66)
Recurring basis \| Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	(4)	(7)
Recurring basis \| Significant Unobservable Inputs (Level III) \| Commodities \| Power
Fair Value Hierarchy
Derivative instrument assets	0	0
Derivative instrument liabilities	(4)	(7)
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 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, 2020	Dec. 31, 2019
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	(7)	(4)
Transfers out of Level III	0	4
Total gains /(losses) included in Net income	3	(3)
Total losses included in OCI	0	(4)
Balance at end of year	$ (4)	$ (7)

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
CHANGES IN OPERATING WORKING CAPITAL
Decrease /(increase) in Accounts receivable	$ 129	$ 31	$ (69)
Increase in Inventories	(55)	(42)	(49)
(Increase)/ decrease in Other current assets	(221)	(15)	45
(Decrease)/ increase in Accounts payable and other	(162)	352	(70)
(Decrease)/ increase in Accrued interest	(18)	(33)	41
(Increase)/ Decrease in Operating Working Capital	$ (327)	$ 293	$ (102)

ACQUISITIONS AND DISPOSITIONS (Details) $ / shares in Units, $ in Millions					1 Months Ended									12 Months Ended			24 Months Ended
	Nov. 13, 2020 USD ($)	May 22, 2020 CAD ($)	Apr. 29, 2020 CAD ($)	Jun. 30, 2019 CAD ($)	Apr. 30, 2020 CAD ($)	Oct. 31, 2019 CAD ($)	Oct. 31, 2019 USD ($) $ / shares	Aug. 31, 2019 CAD ($)	Aug. 31, 2019 USD ($)	Jul. 31, 2019 CAD ($)	May 31, 2019 CAD ($)	Oct. 31, 2018 CAD ($)	Jul. 31, 2018 CAD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2020 CAD ($)	Nov. 12, 2020	May 21, 2019 USD ($)
Business Acquisition [Line Items]
Net (loss)/ gain on assets sold/held for sale														$ (50,000,000)	$ (121,000,000)	$ 170,000,000
Proceeds from sale of assets, net of transaction costs														3,407,000,000	2,398,000,000	614,000,000
Goodwill														12,679,000,000	12,887,000,000		$ 12,679,000,000
Income tax expense														194,000,000	754,000,000	432,000,000
Payments for unredeemed shares						$ 373,000,000	$ 284							$ 0	$ 373,000,000	$ 0
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					$ 1,500,000,000
Coastal GasLink \| Canadian Natural Gas Pipelines
Business Acquisition [Line Items]
Ownership interest percentage		35.00%												35.00%			35.00%
Option to acquire percentage of voting interests		10.00%
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								$ 21,000,000
Gain (loss) on disposition of property plant equipment, net of tax								152,000,000
Gain (loss) on disposition of property plant and equipment foreign currency translation amount								4,000,000
Goodwill								$ 595,000,000
Columbia Midstream assets \| 2019
Business Acquisition [Line Items]
Income tax expense														$ (18,000,000)
Northern Courier pipeline \| Liquids Pipelines
Business Acquisition [Line Items]
Ownership interest percentage										15.00%				15.00%			15.00%
TransCanada Turbines \| TransCanada Turbines
Business Acquisition [Line Items]
Ownership interest percentage																		50.00%
Business acquisition, percentage of voting interests acquired	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%
Total consideration		$ 656,000,000
Net (loss)/ gain on assets sold/held for sale		364,000,000
Gain (loss) on sale, net of tax		402,000,000
Revaluation of retained interest, gain (loss)		231,000,000
Disposal group, disposed of by sale, not discontinued operations \| Northern Courier pipeline
Business Acquisition [Line Items]
Ownership interest sold										85.00%
Total consideration										$ 144,000,000
Net (loss)/ gain on assets sold/held for sale										69,000,000
Gain (loss) on sale, net of tax										115,000,000
Disposal group, disposed of by sale, not discontinued operations \| SRP
Business Acquisition [Line Items]
Total consideration																			$ 448
Net (loss)/ gain on assets sold/held for sale											$ 68,000,000
Gain (loss) on sale, net of tax											54,000,000
Foreign currency translation gain											$ 9,000,000
Disposal group, disposed of by sale, not discontinued operations \| Cartier Wind
Business Acquisition [Line Items]
Ownership interest sold												62.00%
Proceeds from sale of assets, net of transaction costs												$ 630,000,000
Gain (loss) on disposition of property plant equipment												170,000,000
Gain (loss) on disposition of property plant equipment, net of tax												$ 143,000,000
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			$ 2,800,000,000
Net (loss)/ gain on assets sold/held for sale			(414,000,000)														$ (693,000,000)
Gain (loss) on sale, net of tax			$ (283,000,000)														$ (477,000,000)
Northern Courier pipeline \| Senior Secured Notes due June 2042
Business Acquisition [Line Items]
Proceeds from issuance of debt				$ 1,000,000,000.0						$ 1,000,000,000
TCPL \| Medium Term Notes due March 2028
Business Acquisition [Line Items]
Proceeds from issuance of debt													$ 200,000,000
Coastal GasLink \| Senior Secured Credit Facilities due April 2027
Business Acquisition [Line Items]
Revolving credit facility, borrowing capacity		$ 6,800,000,000
Proceeds from issuance of debt					$ 1,603,000,000

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Narrative (Details)		12 Months Ended
	Mar. 31, 2021 CAD ($) shares	Dec. 31, 2020 CAD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2018 CAD ($)
Other Commitments
Purchase commitment		$ 224,000,000	$ 236,000,000	$ 207,000,000
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites		24,000,000	$ 30,000,000
TC PipeLines, LP \| Scenario, Forecast
Other Commitments
Common shares issued to common unitholders	0.70
Common shares issued (in shares) \| shares	38,000,000
Gain (loss) recognized from transaction	$ 0
Canadian Natural Gas Pipelines \| Capital expenditures
Other Commitments
Purchase commitment		900,000,000
U.S. Natural Gas Pipelines \| Capital expenditures
Other Commitments
Purchase commitment		300,000,000
Mexico Natural Gas Pipelines \| Capital expenditures
Other Commitments
Purchase commitment		200,000,000
Liquids Pipelines \| Capital expenditures
Other Commitments
Purchase commitment		900,000,000
Power and Storage \| Capital expenditures
Other Commitments
Purchase commitment		$ 300,000,000

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - Contingent financial obligation - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Guarantees
Potential Exposure	$ 566	$ 597
Carrying Value	30	37
Northern Courier pipeline
Guarantees
Potential Exposure	300	300
Carrying Value	26	27
Sur de Texas
Guarantees
Potential Exposure	100	109
Carrying Value	0	0
Bruce Power
Guarantees
Potential Exposure	88	88
Carrying Value	0	0
Other jointly-owned entities
Guarantees
Potential Exposure	78	100
Carrying Value	$ 4	$ 10

VARIABLE INTEREST ENTITIES - Narrative (Details)	12 Months Ended
VARIABLE INTEREST ENTITIES - Narrative (Details)	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable interest entity ownership percentage	100.00%

VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current Assets
Cash and cash equivalents	$ 1,530	$ 1,343
Accounts receivable	2,162	2,422
Inventories	629	452
Other	880	627
Total Current Assets	5,201	7,651
Plant, Property and Equipment	69,775	65,489
Equity Investments	6,677	6,506
Goodwill	12,679	12,887
Other Long-Term Assets	979	2,168
Total Assets	100,300	99,279
Current Liabilities
Accounts payable and other	3,816	4,544
Redeemable non-controlling interest	633	0
Accrued interest	595	613
Current portion of long-term debt	1,972	2,705
Total Current Liabilities	11,987	12,899
Total Regulatory Liabilities	4,148	3,772
Deferred Income Tax Liabilities	5,806	5,703
Total Liabilities	66,827	66,882
VIE, Primary Beneficiary
Current Assets
Cash and cash equivalents	254	106
Accounts receivable	61	88
Inventories	26	27
Other	11	8
Total Current Assets	352	229
Plant, Property and Equipment	3,325	3,050
Equity Investments	714	785
Goodwill	424	431
Other Long-Term Assets	8	0
Total Assets	4,823	4,495
Current Liabilities
Accounts payable and other	109	70
Redeemable non-controlling interest	633	0
Accrued interest	21	21
Current portion of long-term debt	579	187
Total Current Liabilities	1,342	278
Total Regulatory Liabilities	60	45
Other Long-Term Liabilities	11	9
Deferred Income Tax Liabilities	12	9
Long-Term Debt	2,468	2,694
Total Liabilities	$ 3,893	$ 3,035

VARIABLE INTEREST ENTITIES - Carrying Value of Non-consolidated VIEs and Maximum Exposure (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Balance sheet
Equity Investments	$ 6,677	$ 6,506
Off-balance sheet
Maximum exposure to loss	7,366	6,666
Bruce Power
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	1,183	1,521
Bruce Power \| VIE, Not Primary Beneficiary
Balance sheet
Equity Investments	3,306	3,256
Pipeline equity investments and other \| VIE, Not Primary Beneficiary
Balance sheet
Equity Investments	1,371	1,464
Pipeline equity investments
Off-balance sheet
Off-balance Sheet potential exposure to guarantees	$ 1,506	$ 425

SUBSEQUENT EVENTS (Details) $ in Millions	Jan. 31, 2021 USD ($)	Dec. 31, 2020 CAD ($)	Dec. 09, 2020 USD ($)	Dec. 31, 2019 CAD ($)	Dec. 31, 2019 USD ($)
Subsequent Event [Line Items]
Long-term debt					$ 200,000,000
Plant, Property and Equipment		$ 69,775		$ 65,489
Other Long-Term Assets		979		$ 2,168
Keystone XL
Subsequent Event [Line Items]
Plant, Property and Equipment		2,800
Other Long-Term Assets		$ 200
COLUMBIA PIPELINE GROUP, INC. \| Term loan \| Delayed Draw Term Loan due June 2022
Subsequent Event [Line Items]
Debt instrument, face amount			$ 4,200,000,000
Subsequent Event \| COLUMBIA PIPELINE GROUP, INC. \| Term loan \| Delayed Draw Term Loan due June 2022
Subsequent Event [Line Items]
Long-term debt	$ 4,000,000,000.0

EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Employee post-retirement benefits
Fair value of plan assets	$ 4,479	$ 4,099
Percentage of Total Portfolio	100.00%	100.00%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 1,938	$ 1,860
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	2,124	1,860
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	417	379	$ 362
Cash and Cash Equivalents
Employee post-retirement benefits
Fair value of plan assets	$ 87	$ 58
Percentage of Total Portfolio	2.00%	1.00%
Cash and Cash Equivalents \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 87	$ 58
Cash and Cash Equivalents \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	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	$ 453	$ 591
Percentage of Total Portfolio	10.00%	14.00%
Equity Securities, Canadian \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 276	$ 402
Equity Securities, Canadian \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	177	189
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	$ 805	$ 679
Percentage of Total Portfolio	18.00%	17.00%
Equity Securities, U.S. \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 594	$ 523
Equity Securities, U.S. \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	211	156
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	$ 494	$ 366
Percentage of Total Portfolio	11.00%	9.00%
Equity Securities, International \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 114	$ 46
Equity Securities, International \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	380	320
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	$ 484	$ 433
Percentage of Total Portfolio	11.00%	11.00%
Equity Securities, Global \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 116	$ 136
Equity Securities, Global \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	368	297
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	$ 160	$ 134
Percentage of Total Portfolio	4.00%	3.00%
Equity Securities, Emerging \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 35	$ 8
Equity Securities, Emerging \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	125	126
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	$ 207	$ 198
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	207	198
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	$ 283	$ 246
Percentage of Total Portfolio	6.00%	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	283	246
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	$ 13	$ 12
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	13	12
Fixed Income Securities, Canadian Bonds, Municipal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Corporate
Employee post-retirement benefits
Fair value of plan assets	$ 151	$ 125
Percentage of Total Portfolio	3.00%	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	151	125
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	$ 458	$ 428
Percentage of Total Portfolio	10.00%	11.00%
Fixed Income Securities, U.S. Bonds, Federal \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 444	$ 421
Fixed Income Securities, U.S. Bonds, Federal \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	14	7
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	$ 2	$ 1
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	2	1
Fixed Income Securities, U.S. Bonds, Municipal \| Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, U.S. Bonds, Corporate
Employee post-retirement benefits
Fair value of plan assets	$ 215	$ 187
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	$ 72	$ 67
Fixed Income Securities, U.S. Bonds, Corporate \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	143	120
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	$ 14	$ 11
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	$ 8	$ 7
Fixed Income Securities, International, Government \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	6	4
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	$ 48	$ 52
Percentage of Total Portfolio	1.00%	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	48	52
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	$ 51	$ 53
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	$ 47	$ 46
Fixed Income Securities, International, Mortgage-backed \| Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	4	7
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	$ 213	$ 196
Percentage of Total Portfolio	5.00%	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	213	196
Infrastructure
Employee post-retirement benefits
Fair value of plan assets	$ 203	$ 181
Percentage of Total Portfolio	5.00%	4.00%
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	203	181
Private equity funds
Employee post-retirement benefits
Fair value of plan assets	$ 1	$ 2
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	2
Derivatives
Employee post-retirement benefits
Fair value of plan assets	$ (8)	$ 0
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	(8)	0
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	$ 145	$ 146
Percentage of Total Portfolio	3.00%	4.00%
Funds held on deposit \| Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 145	$ 146
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