TC Energy (TRP) 40-F 13 Feb 20 2019 FY Annual report (Canada) Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2019shares
Entity Information [Line Items]
Document Type	40-F
Entity Registrant Name	TC ENERGY CORPORATION
Entity File Number	1-31690
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2019
Current Fiscal Year End Date	--12-31
Entity Central Index Key	0001232384
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
Audited Annual Financial Statements	true
Annual Information Form	true
Entity Common Stock, Shares Outstanding	938,399,506
Entity Emerging Growth Company	false
Entity Interactive Data Current	Yes
Entity Current Reporting Status	Yes
Amendment Flag	false
TRANSCANADA PIPELINES LIMITED
Entity Information [Line Items]
Document Type	40-F
Entity Registrant Name	TRANSCANADA PIPELINES LIMITED
Entity File Number	1-8887
Document Period End Date	Dec. 31, 2019
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2019
Current Fiscal Year End Date	--12-31
Entity Central Index Key	0000099070
Entity Tax Identification Number	52-2179728
Security Reporting Obligation	15(d)
Entity Common Stock, Shares Outstanding	902,108,711
Amendment Flag	false
Business Contact
Entity Information [Line Items]
Contact Personnel Name	TransCanada PipeLine USA Ltd
Entity Address, Address Line One	700 Louisiana Street
Entity Address, Address Line Two	Suite 700
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002-2700
City Area Code	832
Local Phone Number	320-5201

Consolidated statement of incom

Consolidated statement of income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues	$ 13,255	$ 13,679	$ 13,449
Income from Equity Investments (Note 10)	920	714	773
Operating and Other Expenses
Plant operating costs and other	3,909	3,591	3,906
Commodity purchases resold	369	1,488	2,382
Property taxes	727	569	569
Depreciation and amortization	2,464	2,350	2,055
Goodwill and other asset impairment charges (Notes 8, 12 and 13)	0	801	1,257
Total Operating and Other Expenses	7,469	8,799	10,169
(Loss)/Gain on Assets Held for Sale/Sold (Notes 6 and 27)	(121)	170	631
Financial Charges
Interest expense (Note 18)	2,333	2,265	2,069
Allowance for funds used during construction	(475)	(526)	(507)
Interest income and other	(460)	76	(184)
Total Financial Charges	1,398	1,815	1,378
Income before Income Taxes	5,187	3,949	3,306
Income Tax Expense/(Recovery) (Note 17)
Current	699	315	149
Deferred	55	284	566
Deferred – U.S. Tax Reform and 2018 FERC Actions	0	(167)	(804)
Income Tax (Recovery)/Expense	754	432	(89)
Net Income	4,433	3,517	3,395
Net income/(loss) attributable to non-controlling interests (Note 20)	293	(185)	238
Net Income Attributable to Controlling Interests	4,140	3,702	3,157
Preferred share dividends	164	163	160
Net Income Attributable to Common Shares	$ 3,976	$ 3,539	$ 2,997
Net Income per Common Share (Note 21)
Basic (in dollars per share)	$ 4.28	$ 3.92	$ 3.44
Diluted (in dollars per share)	4.27	3.92	3.43
Dividends Declared per Common Share (in dollars per share)	$ 3	$ 2.76	$ 2.50
Weighted Average Number of Common Shares (Note 20)
Basic (in shares)	929	902	872
Diluted (in shares)	931	903	874
Canadian Natural Gas Pipelines
Revenues	$ 4,010	$ 4,038	$ 3,693
U.S. Natural Gas Pipelines
Revenues	4,978	4,314	3,584
Mexico Natural Gas Pipelines
Revenues	603	619	570
Liquids Pipelines
Revenues	2,879	2,584	2,009
Power and Storage
Revenues	$ 785	$ 2,124	$ 3,593

Consolidated statement of compr

Consolidated statement of comprehensive income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net Income	$ 4,433	$ 3,517	$ 3,395
Other Comprehensive (Loss)/Income, Net of Income Taxes
Foreign currency translation losses and gains on net investment in foreign operations	(944)	1,358	(749)
Reclassification of foreign currency translation gains on disposal of foreign operations	(13)	0	(77)
Change in fair value of net investment hedges	35	(42)	0
Change in fair value of cash flow hedges	(62)	(10)	3
Reclassification to net income of gains and losses on cash flow hedges	14	21	(2)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(10)	(114)	(11)
Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans	10	15	16
Other comprehensive (loss)/income on equity investments	(82)	86	(106)
Other comprehensive (loss)/income (Note 23)	(1,052)	1,314	(926)
Comprehensive Income	3,381	4,831	2,469
Comprehensive income/(loss) attributable to non-controlling interests	194	(13)	83
Comprehensive Income Attributable to Controlling Interests	3,187	4,844	2,386
Preferred share dividends	164	163	160
Comprehensive Income Attributable to Common Shares	$ 3,023	$ 4,681	$ 2,226

Consolidated statement of cash

Consolidated statement of cash flows $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)
Cash Generated from Operations
Net income	$ 4,433	$ 3,517	$ 3,395
Depreciation and amortization	2,464	2,350	2,055
Goodwill and other asset impairment charges (Notes 8, 12 and 13)	0	801	1,257
Deferred income taxes (Note 17)	55	284	566
Deferred income taxes – U.S. Tax Reform and 2018 FERC Actions (Note 17)	0	(167)	(804)
Income from equity investments (Note 10)	(920)	(714)	(773)
Distributions received from operating activities of equity investments (Note 10)	1,213	985	970
Employee post-retirement benefits funding, net of expense (Note 24)	(45)	(35)	(64)
Loss/(gain) on assets held for sale/sold (Notes 6 and 27)	121	(170)	(631)
Equity allowance for funds used during construction	(299)	(374)	(362)
Unrealized (gains)/losses on financial instruments	(134)	220	(149)
Foreign exchange (gains)/losses on Loan receivable from affiliate (Note 10)	(53)	5	63
Other	(46)	(45)	(20)
Decrease/(increase) in operating working capital (Note 26)	293	(102)	(273)
Net cash provided by operations	7,082	6,555	5,230
Investing Activities
Capital expenditures (Note 4)	(7,475)	(9,418)	(7,383)
Capital projects in development (Note 4)	(707)	(496)	(146)
Contributions to equity investments (Notes 4 and 10)	(602)	(1,015)	(1,681)
Proceeds from sales of assets, net of transaction costs	2,398	614	4,683
Reimbursement of costs related to capital projects in development (Note 13)	0	470	634
Other distributions from equity investments (Note 10)	186	121	362
Payment for unredeemed shares of Columbia Pipeline Group, Inc. (Note 15)	(373)	0	0
Deferred amounts and other	(299)	(295)	(168)
Net cash used in investing activities	(6,872)	(10,019)	(3,699)
Financing Activities
Notes payable issued, net	1,656	817	1,038
Long-term debt issued, net of issue costs	3,024	6,238	3,643
Long-term debt repaid	(3,502)	(3,550)	(7,085)
Junior subordinated notes issued, net of issue costs	1,436	0	3,468
Dividends on common shares	(1,798)	(1,571)	(1,339)
Dividends on preferred shares	(160)	(158)	(155)
Distributions to non-controlling interests	(216)	(225)	(283)
Common shares issued, net of issue costs	253	1,148	274
Partnership units of TC PipeLines, LP issued, net of issue costs	0	49	225
Common units of Columbia Pipeline Partners LP acquired	0	0	(1,205)
Net cash provided by/(used in) financing activities	693	2,748	(1,419)
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	(6)	73	(39)
Increase/(Decrease) in Cash and Cash Equivalents	897	(643)	73
Cash and Cash Equivalents, Beginning of year	446	1,089	1,016
Cash and Cash Equivalents, End of year	$ 1,343	$ 446	$ 1,089

Consolidated balance sheet

Consolidated balance sheet - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 1,343	$ 446
Accounts receivable	2,422	2,535
Inventories	452	431
Assets held for sale (Note 6)	2,807	543
Other (Note 7)	627	1,180
Total Current Assets	7,651	5,135
Plant, Property and Equipment (Note 8)	65,489	66,503
Loan Receivable from Affiliate (Note 10)	1,434	1,315
Equity Investments (Note 10)	6,506	7,113
Restricted Investments	1,557	1,207
Regulatory Assets (Note 11)	1,587	1,548
Goodwill (Note 12)	12,887	14,178
Intangible and Other Assets (Note 13)	2,168	1,921
Total Assets	99,279	98,920
Current Liabilities
Notes payable (Note 14)	4,300	2,762
Accounts payable and other (Note 15)	4,544	5,408
Dividends payable	737	668
Accrued interest	613	646
Current portion of long-term debt (Note 18)	2,705	3,462
Total Current Liabilities	12,899	12,946
Regulatory Liabilities (Note 11)	3,772	3,930
Other Long-Term Liabilities (Note 16)	1,614	1,008
Deferred Income Tax Liabilities (Note 17)	5,703	6,026
Long-Term Debt (Note 18)	34,280	36,509
Junior Subordinated Notes (Note 19)	8,614	7,508
Total Liabilities	66,882	67,927
EQUITY
Common shares, no par value (Note 21)	24,387	23,174
Preferred shares (Note 22)	3,980	3,980
Additional paid-in capital	0	17
Retained earnings	3,955	2,773
Accumulated other comprehensive loss (Note 23)	(1,559)	(606)
Controlling Interests	30,763	29,338
Non-controlling interests (Note 20)	1,634	1,655
Total Equity	32,397	30,993
Total Liabilities and Equity	$ 99,279	$ 98,920

Consolidated balance sheet (Par

Consolidated balance sheet (Parenthetical) - shares shares in Millions	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common shares issued	938	918
Common shares outstanding	938	918

Consolidated statement of equit

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, 2016			$ 20,099			$ 1,138	$ (960)	$ 1,726
Shares issued:
Under dividend reinvestment and share purchase plan			790
On exercise of stock options			62
Under at-the-market equity issuance program, net of issue costs			216
Issuance of stock options, net of exercises					$ 6
Dilution from TC PipeLines, LP units issued					26			225
Asset drop-downs to TC PipeLines, LP					(202)
Columbia Pipeline Partners LP acquisition					(171)			(41)
Reclassification of additional paid-in capital deficit to retained earnings					341
Net income attributable to controlling interests	$ 3,157					3,157
Common share dividends						(2,184)
Preferred share dividends						(159)
Adjustment related to employee share-based payments						12
Reclassification of additional paid-in capital deficit to retained earnings						(341)
Other comprehensive (loss)/income attributable to controlling interests (Note 23)	(926)						(771)
Net income/(loss) attributable to non-controlling interests	(238)							238
Other comprehensive (loss)/income attributable to non-controlling interests								(155)
Distributions declared to non-controlling interests								(280)
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					26			225
Decrease in TC Energy's ownership of TC PipeLines, LP					(171)			(41)
Reclassification from common units subject to rescission (Note 20)								106
Impact of Columbia Pipeline Partners LP acquisition								33
Balance at end of year at Dec. 31, 2017	26,891	$ 25,039	21,167	$ 3,980		1,623	(1,731)	1,852
Shares issued:
Under dividend reinvestment and share purchase plan			855
On exercise of stock options			34
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
Columbia Pipeline Partners LP acquisition								(9)
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
Proceeds, net of issue costs					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:
Under dividend reinvestment and share purchase plan			931
On exercise of stock options			282
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	$ 0	$ 3,955	$ (1,559)	$ 1,634

DESCRIPTION OF TC ENERGY'S BUSI

DESCRIPTION OF TC ENERGY'S BUSINESS	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
DESCRIPTION OF TC ENERGY'S BUSINESS	DESCRIPTION OF TC ENERGY'S BUSINESS On May 3, 2019, TransCanada Corporation changed its name to TC Energy Corporation (TC Energy or the Company) to better reflect the scope of its operations as a leading North American energy infrastructure company. In addition, the previously disclosed Energy segment has been renamed the Power and Storage segment. TC Energy 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, each of which offers different products and 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 consists of the Company's investments in 40,658 km ( 25,264 miles ) of natural gas pipelines primarily regulated by the Canadian Energy Regulator (CER). The Company also has an investment in the Coastal GasLink pipeline under development which is regulated by the B.C. Oil and Gas Commission (OGC). U.S. Natural Gas Pipelines The U.S. Natural Gas Pipelines segment consists of the Company's investments in 50,089 km ( 31,124 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 consists of the Company's investments in 2,503 km ( 1,554 miles ) of regulated natural gas pipelines. Liquids Pipelines The Liquids Pipelines segment 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 as well as a liquids marketing business. Power and Storage The Power and Storage segment primarily consists of the Company's investments in 10 power generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These assets are located in Alberta, Ontario, Québec and New Brunswick and include the investment in Portlands Energy Centre as well as the Halton Hills and Napanee natural gas-fired power plants which were classified as Assets held for sale at December 31, 2019. Refer to Note 6, Assets held for sale, for additional information.

ACCOUNTING POLICIES

ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2019
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 (GAAP). Amounts are stated in Canadian dollars unless otherwise indicated. Basis of Presentation These consolidated financial statements include the accounts of TC Energy and its subsidiaries. The Company consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. TC Energy uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. 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: • fair value of equity investments (Note 10) and the recoverability of plant, property and equipment (Note 8) • fair value of reporting units that contain goodwill (Notes 12 and 27) • recoverability of capitalized project costs (Note 13) and • fair value of assets and liabilities acquired in a business combination. Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial statements, but they 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 8) • carrying value of regulatory assets and liabilities (Note 11) • carrying value of asset retirement obligations (Note 16) • provisions for income taxes, including U.S. Tax Reform (Note 17) • assumptions used to measure retirement and other post-retirement obligations (Note 24) • fair value of financial instruments (Note 25) and • provisions for commitments, contingencies, guarantees (Note 28) and restructuring costs (Note 29). 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 CER, formerly the National Energy Board (NEB), the Alberta Energy Regulator (AER) or the OGC. 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 appropriately 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 asset 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. Once in operation, the Coastal GasLink pipeline is not expected to apply RRA. 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. 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 risks related to variances in revenues and most costs. These variances 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. 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. 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 midstream assets. Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. 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, crude oil in transit and 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 one 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. Regulated natural gas storage base gas, which is valued at cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver natural gas held in storage. Base gas is not depreciated. When 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. Costs incurred to remove plant, property and equipment from service, net of any salvage proceeds, are also recorded in accumulated depreciation. Midstream and 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 their sale in 2019, plant, property and equipment for midstream assets 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. 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. 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. 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. Non-regulated 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 . Capitalized Project Costs 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 Intangible and other 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. 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, 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 for the reporting unit that will be retained. Loans and Receivables Loans receivable from affiliates and accounts receivable are measured at cost. 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 all 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 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. D eferred 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 Operating and other expenses. For those AROs that the Company records, the following assumptions are used: • when the asset is expected to be retired • the scope and cost of abandonment and reclamation activities that are required, and • appropriate inflation and discount rates. The Company has recorded AROs related to its non-regulated natural gas storage operations, mineral rights and power generation facilities. The scope and timing of asset retirements related to most of the Company's natural gas pipelines and liquids pipelines is 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, with the exception of certain abandoned facilities and certain other facilities on its Columbia Gas pipeline. 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 upon the generation or sale of power using the best estimate of the amount required to settle the 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), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service, and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five -year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life (EARSL) of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the EARSL of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income (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 (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 of the 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 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

ACCOUNTING CHANGES

ACCOUNTING CHANGES	12 Months Ended
	Dec. 31, 2019
Accounting Changes and Error Corrections [Abstract]
ACCOUNTING CHANGES	ACCOUNTING CHANGES Changes in Accounting Policies for 2019 Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the Consolidated statement of income. The new guidance does not make extensive changes to lessor accounting. The new guidance was effective January 1, 2019 and was applied using optional transition relief which allowed entities to initially apply the new lease standard at adoption (January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This transition option allowed the Company to not apply the new guidance, including disclosure requirements, to the comparative periods presented. The Company elected available practical expedients and exemptions upon adoption which allowed the Company: • to not reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard • to carry forward the historical lease classification and its accounting treatment for land easements on existing agreements • to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption • to not separate lease and non-lease components for all leases for which the Company is the lessee and for facility and liquids tank terminals for which the Company is the lessor • to use hindsight in determining the lease term and assessing ROU assets for impairment. The new guidance had a significant impact on the Company's Consolidated balance sheet, but did not have an impact in the Company's Consolidated statements of income and cash flows. The most impactful change was the recognition of ROU assets and lease liabilities for operating leases and providing additional new disclosures about the Company's leasing activities. Refer to Note 9, Leases, for additional information related to the impact of adopting the new guidance. In the application of the new guidance, significant assumptions and judgments are used to determine the following: • whether a contract contains a lease • the duration of the lease term including exercising lease renewal options. The lease term for all of the Company’s leases includes the noncancellable period of the lease plus any additional periods covered by either a Company option to extend (or not to terminate) the lease that the Company is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor • the discount rate for the lease. Lessee Accounting Policy The Company determines if an arrangement is a lease at inception of the contract. Operating leases are recognized as 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. 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. The operating lease ROU asset also includes any prepaid lease payments and initial direct costs incurred and excludes lease incentives. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. 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. 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 the changes in facts and circumstances on which these payments are based occur. Fair value measurement In August 2018, the FASB issued new guidance that amends certain disclosure requirements for fair value measurements. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Company elected to adopt this guidance effective first quarter 2019. The guidance was applied retrospectively and did not have a material impact on the Company's consolidated financial statements. Future Accounting Changes 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 is effective January 1, 2020 and will be applied using a modified retrospective approach. The adoption of this new guidance will 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 is effective January 1, 2020 and will be applied prospectively to all implementation costs incurred after the date of adoption. The adoption of this new guidance will 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 is effective January 1, 2020 and will be applied on a retrospective basis. The adoption of this new guidance will not have a material 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 is effective for annual disclosure requirements at December 31, 2020 and is expected to be applied on a retrospective basis. The Company does not expect the adoption of this new guidance to have a material impact on its consolidated financial statements. 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, however, early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION year ended December 31, 2019 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Storage Corporate 1 Total (millions of Canadian $) Revenues 4,010 4,978 603 2,879 785 — 13,255 Intersegment revenues — 164 — — 19 (183 ) 2 — 4,010 5,142 603 2,879 804 (183 ) 13,255 Income/(loss) from equity investments 12 264 56 70 571 (53 ) 3 920 Plant operating costs and other (1,473 ) (1,581 ) (54 ) (728 ) (239 ) 166 2 (3,909 ) Commodity purchases resold — — — — (369 ) — (369 ) Property taxes (275 ) (345 ) — (101 ) (6 ) — (727 ) Depreciation and amortization (1,159 ) (754 ) (115 ) (341 ) (95 ) — (2,464 ) Gain/(loss) on assets held for sale/sold — 21 — 69 (211 ) — (121 ) Segmented earnings/(losses) 1,115 2,747 490 1,848 455 (70 ) 6,585 Interest expense (2,333 ) Allowance for funds used during construction 475 Interest income and other 3 460 Income before income taxes 5,187 Income tax expense (754 ) Net income 4,433 Net income attributable to non-controlling interests (293 ) Net income attributable to controlling interests 4,140 Preferred share dividends (164 ) Net income attributable to common shares 3,976 Capital spending Capital expenditures 3,900 2,500 323 239 481 32 7,475 Capital projects in development 6 — — 701 — — 707 Contributions to equity investments — 16 34 14 538 — 602 3,906 2,516 357 954 1,019 32 8,784 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income/(loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange losses on the peso-denominated loans from affiliates which are fully offset in Interest income and other. Refer to Note 10, Equity investments, for additional information. year ended December 31, 2018 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Power and Storage Corporate 1 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 ) (313 ) 159 2 (3,591 ) Commodity purchases resold — — — — (1,488 ) — (1,488 ) 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 ) 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 other 3 (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 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains on the peso-denominated loans from affiliates which are fully offset in Interest income and other. Refer to Note 10, Equity investments, for additional information. year ended December 31, 2017 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Power and Storage Corporate 1 Total (millions of Canadian $) Revenues 3,693 3,584 570 2,009 3,593 — 13,449 Intersegment revenues — 51 — — — (51 ) 2 — 3,693 3,635 570 2,009 3,593 (51 ) 13,449 Income/(loss) from equity investments 11 240 (9 ) (3 ) 471 63 3 773 Plant operating costs and other (1,300 ) (1,340 ) (42 ) (623 ) (550 ) (51 ) 2 (3,906 ) Commodity purchases resold — — — — (2,382 ) — (2,382 ) Property taxes (260 ) (181 ) — (89 ) (39 ) — (569 ) Depreciation and amortization (908 ) (594 ) (93 ) (309 ) (151 ) — (2,055 ) Goodwill and other asset impairment charges — — — (1,236 ) (21 ) — (1,257 ) Gain on sale of assets — — — — 631 — 631 Segmented earnings/(losses) 1,236 1,760 426 (251 ) 1,552 (39 ) 4,684 Interest expense (2,069 ) Allowance for funds used during construction 507 Interest income and other 3 184 Income before income taxes 3,306 Income tax recovery 89 Net income 3,395 Net income attributable to non-controlling interests (238 ) Net income attributable to controlling interests 3,157 Preferred share dividends (160 ) Net income attributable to common shares 2,997 Capital spending Capital expenditures 2,106 3,712 833 341 350 41 7,383 Capital projects in development 75 — — 71 — — 146 Contributions to equity investments — 118 1,121 117 325 — 1,681 2,181 3,830 1,954 529 675 41 9,210 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income/(loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains on the peso-denominated loans from affiliates which are fully offset in Interest income and other. Refer to Note 10, Equity investments, for additional information. at December 31 2019 2018 (millions of Canadian $) Total Assets by segment Canadian Natural Gas Pipelines 21,983 18,407 U.S. Natural Gas Pipelines 41,627 44,115 Mexico Natural Gas Pipelines 7,207 7,058 Liquids Pipelines 15,931 17,352 Power and Storage 7,788 8,475 Corporate 4,743 3,513 99,279 98,920 Geographic Information year ended December 31 2019 2018 2017 (millions of Canadian $) Revenues Canada – domestic 4,059 4,187 3,618 Canada – export 1,035 1,075 1,255 United States 7,558 7,798 8,006 Mexico 603 619 570 13,255 13,679 13,449 at December 31 2019 2018 (millions of Canadian $) Plant, Property and Equipment Canada 23,362 23,226 United States 36,184 37,385 Mexico 5,943 5,892 65,489 66,503

REVENUES

REVENUES	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
REVENUES	REVENUES On January 1, 2018, the Company adopted new FASB guidance on revenue from contracts with customers using the modified retrospective transition method for all contracts that were in effect on the date of adoption. Results reported for 2019 and 2018 reflect the application of the new guidance, while the 2017 comparative results were prepared and reported under previous revenue recognition guidance. Disaggregation of Revenues year ended December 31, 2019 Canadian U.S. Mexico Liquids Pipelines Power and Storage Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,010 4,245 601 2,423 — 11,279 Power generation — — — — 662 662 Natural gas storage and other — 650 2 4 73 729 4,010 4,895 603 2,427 735 12,670 Other revenues 1,2 — 83 — 452 50 585 4,010 4,978 603 2,879 785 13,255 1 Other revenues include income from the Company's marketing activities, financial instruments and lease contracts. These arrangements are not in the scope of the revenue guidance. Refer to Note 9, Leases, and Note 25, Risk management and financial instruments, for additional information on income from lease arrangements and financial instruments, respectively. 2 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income taxes, for additional information. year ended December 31, 2018 Canadian U.S. Mexico 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 revenues 1,2 — 111 — 502 272 885 4,038 4,314 619 2,584 2,124 13,679 1 Other revenues include income from the Company's marketing activities, financial instruments and lease contracts. These arrangements are not in the scope of the revenue guidance. Refer to Note 25, Risk management and financial instruments, for additional information on income from financial instruments. 2 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income taxes, for additional information. Revenues from contracts with customers are recognized net of any 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. Contract Balances at December 31 2019 2018 (millions of Canadian $) Receivables from contracts with customers 1,458 1,684 Contract assets (Note 7) 153 159 Long-term contract assets 1 102 21 Contract liabilities 2 61 11 Long-term contract liabilities (Note 16) 226 121 1 Recorded as part of Intangibles and other assets on the Consolidated balance sheet. 2 Comprised of deferred revenue recorded in Accounts payable and other on the Consolidated balance sheet. During the year ended December 31, 2019 , $6 million ( 2018 – $17 million ) of revenue was recognized that was included in the contract liability 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 The following provides a discussion of the transaction price allocated to future performance obligations as well as practical expedients used by the Company. Capacity Arrangements and Transportation As at December 31, 2019 , future revenues from long-term pipeline capacity arrangements and transportation contracts extending through 2046 are approximately $26.6 billion , of which approximately $3.7 billion is expected to be recognized in 2020. Future revenues from long-term capacity arrangements and transportation contracts do not include constrained variable revenues or arrangements to which the right to invoice practical expedient has been applied. As a result, these amounts are not representative of potential total future revenues expected from these contracts. Future revenues from the Company's Canadian natural gas pipelines' regulated firm capacity contracts include fixed revenues for the time periods that tolls under current rate settlements are in effect, which is currently one year. Many of these contracts are long-term in nature and revenues from the remaining performance obligations that extend beyond the current rate settlement term are considered to be fully constrained since future tolls remain unknown. Revenues from these contracts will be recognized once the performance obligation to provide capacity has been satisfied and the regulator has approved the applicable tolls. In addition, the Company considers interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. These variable revenues are recognized on a monthly basis when the Company satisfies the performance obligation and have been excluded from the future revenues disclosure as the Company applies the practical expedient related to variable revenues to these contracts. The future variable revenues earned under these contracts are allocated entirely to unsatisfied performance obligations at December 31, 2019 . The Company also applies the right to invoice practical expedient to all of its U.S. and certain of its Mexico regulated natural gas pipeline capacity arrangements and flow-through revenues. Revenues from regulated capacity arrangements are recognized based on current rates and flow-through revenues are earned from the recovery of operating expenses. These revenues are recognized on a monthly basis as the Company performs the services and are excluded from future revenues disclosures. Revenues from liquids pipelines capacity arrangements have a variable component based on volumes transported. As a result, these variable revenues are excluded from the future revenues disclosures as the Company applies the practical expedient related to variable revenues to these contracts. The future variable revenues earned under these contracts are allocated entirely to unsatisfied performance obligations at December 31, 2019 . Power Generation The Company has long-term power generation contracts extending through 2028. Revenues from power generation have a variable component related to market prices that are subject to factors outside the Company’s influence. These revenues are considered to be fully constrained and are recognized on a monthly basis when the Company satisfies the performance obligation. The Company applies the practical expedient related to variable revenues to these contracts. As a result, future revenues from these contracts are excluded from the disclosures. Natural Gas Storage and Other As at December 31, 2019 , future revenues from long-term natural gas storage and other contracts extending through 2026 are approximately $0.8 billion , of which approximately $414 million is expected to be recognized in 2020. The Company applies the practical expedients related to contracts that are for a duration of one year or less and where it recognizes variable consideration, and therefore excludes the related revenues from the future revenues disclosure. As a result, these amounts are lower than the potential total future revenues from these contracts.

ASSETS HELD FOR SALE

ASSETS HELD FOR SALE	12 Months Ended
	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
ASSETS HELD FOR SALE	ASSETS HELD FOR SALE Ontario Natural Gas-Fired Power Plants On July 30, 2019, TC Energy entered into an agreement to sell the Halton Hills and Napanee power plants as well as its 50 per cent interest in Portlands Energy Centre to a third party for proceeds of approximately $2.87 billion , subject to timing of the close and related adjustments. The sale is expected to close by the end of first quarter 2020 subject to conditions which include regulatory approvals and Napanee completing construction and reaching commercial operations as outlined in the agreement. TC Energy expects this sale to result in a total pre-tax loss of approximately $380 million ( $280 million after tax), with $279 million of the pre-tax loss ( $194 million after tax) recorded at December 31, 2019 after classifying the net assets as held for sale. The remaining loss will be recorded on or before closing of the transaction. At December 31, 2019 , the related assets and liabilities in the Power and Storage segment were classified as held for sale as follows: (millions of Canadian $) Assets held for sale Inventories 11 Other current assets 3 Plant, property and equipment 2,502 Equity investments 276 Intangible and other assets 15 Total assets held for sale 2,807 Liabilities related to assets held for sale Other long-term liabilities 8 Total liabilities related to assets held for sale 1 8 1 Included in Accounts payable and other on the Consolidated balance sheet. Coolidge Generating Station On May 21, 2019, TC Energy completed the sale of its Coolidge generating station, which was reported as Assets held for sale at December 31, 2018 . Refer to Note 27, Acquisitions and dispositions, for additional information.

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2019
Other Assets [Abstract]
OTHER CURRENT ASSETS	OTHER CURRENT ASSETS at December 31 2019 2018 (millions of Canadian $) Fair value of derivative contracts (Note 25) 190 737 Contract assets (Note 5) 153 159 Prepaid expenses 60 41 Cash provided as collateral 52 55 Regulatory assets (Note 11) 43 83 Other 129 105 627 1,180

PLANT, PROPERTY AND EQUIPMENT

PLANT, PROPERTY AND EQUIPMENT	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
PLANT, PROPERTY AND EQUIPMENT	PLANT, PROPERTY AND EQUIPMENT 2019 2018 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 11,556 4,846 6,710 10,764 4,500 6,264 Compression 4,205 1,771 2,434 3,289 1,677 1,612 Metering and other 1,296 609 687 1,247 613 634 17,057 7,226 9,831 15,300 6,790 8,510 Under construction 3,181 — 3,181 2,111 — 2,111 20,238 7,226 13,012 17,411 6,790 10,621 Canadian Mainline Pipeline 10,145 7,109 3,036 10,077 6,777 3,300 Compression 3,867 2,823 1,044 3,642 2,656 986 Metering and other 643 219 424 652 241 411 14,655 10,151 4,504 14,371 9,674 4,697 Under construction 60 — 60 149 — 149 14,715 10,151 4,564 14,520 9,674 4,846 Other Canadian Natural Gas Pipelines 1 Other 1,861 1,455 406 1,842 1,420 422 Under construction 1,276 — 1,276 124 — 124 3,137 1,455 1,682 1,966 1,420 546 38,090 18,832 19,258 33,897 17,884 16,013 U.S. Natural Gas Pipelines Columbia Gas Pipeline 9,708 389 9,319 6,711 251 6,460 Compression 4,094 206 3,888 2,932 132 2,800 Metering and other 3,244 125 3,119 2,884 75 2,809 17,046 720 16,326 12,527 458 12,069 Under construction 425 — 425 4,347 — 4,347 17,471 720 16,751 16,874 458 16,416 ANR Pipeline 1,594 472 1,122 1,600 443 1,157 Compression 2,050 436 1,614 1,978 388 1,590 Metering and other 1,245 355 890 1,217 324 893 4,889 1,263 3,626 4,795 1,155 3,640 Under construction 252 — 252 272 — 272 5,141 1,263 3,878 5,067 1,155 3,912 2019 2018 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Other U.S. Natural Gas Pipelines GTN 2,257 969 1,288 2,322 951 1,371 Great Lakes 2,090 1,208 882 2,180 1,251 929 Columbia Gulf 2,597 114 2,483 1,753 74 1,679 Midstream 2 302 42 260 1,212 91 1,121 Other 3 1,228 574 654 1,190 474 716 8,474 2,907 5,567 8,657 2,841 5,816 Under construction 164 — 164 846 — 846 8,638 2,907 5,731 9,503 2,841 6,662 31,250 4,890 26,360 31,444 4,454 26,990 Mexico Natural Gas Pipelines Pipeline 2,988 340 2,648 3,172 301 2,871 Compression 486 54 432 506 41 465 Metering and other 643 124 519 640 91 549 4,117 518 3,599 4,318 433 3,885 Under construction 2,321 — 2,321 1,990 — 1,990 6,438 518 5,920 6,308 433 5,875 Liquids Pipelines Keystone Pipeline System Pipeline 9,378 1,403 7,975 9,780 1,271 8,509 Pumping equipment 1,035 204 831 1,065 184 881 Tanks and other 3,488 556 2,932 3,598 488 3,110 13,901 2,163 11,738 14,443 1,943 12,500 Under construction 47 — 47 18 — 18 13,948 2,163 11,785 14,461 1,943 12,518 Intra-Alberta Pipelines 4 Pipeline 138 2 136 762 22 740 Pumping equipment — — — 104 3 101 Tanks and other 56 2 54 291 8 283 194 4 190 1,157 33 1,124 Under construction — — — 84 — 84 194 4 190 1,241 33 1,208 14,142 2,167 11,975 15,702 1,976 13,726 Power and Storage Natural Gas 5,6 1,256 522 734 2,062 708 1,354 Natural Gas Storage and Other 742 181 561 741 169 572 1,998 703 1,295 2,803 877 1,926 Under construction 6 6 — 6 1,735 — 1,735 2,004 703 1,301 4,538 877 3,661 Corporate 883 208 675 448 210 238 92,807 27,318 65,489 92,337 25,834 66,503 1 Includes Foothills, Ventures LP, Great Lakes Canada and Coastal GasLink . 2 The Company completed the sale of certain Columbia midstream assets on August 1, 2019. Refer to Note 27, Acquisitions and dispositions, for additional information. 3 Includes Portland, North Baja, Tuscarora and Crossroads. 4 The Company completed the sale of an 85 per cent equity interest in Northern Courier on July 17, 2019 and recorded its remaining 15 per cent interest as an equity investment. Refer to Note 10, Equity Investments, and Note 27, Acquisitions and dispositions, for additional information. 5 Includes Grandview, Bécancour and the Alberta cogeneration natural gas-fired facilities at December 31, 2019. 6 The Company completed the sale of the Coolidge generating station on May 21, 2019. Refer to Note 27, Acquisition and dispositions, for additional information. At July 30, 2019, the cost and accumulated depreciation of the Halton Hills and Napanee power plants were reclassified as Assets held for sale. Refer to Note 6, Assets held for sale, for additional information. Coastal GasLink In December 2019, TC Energy entered into an agreement to sell a 65 per cent equity interest in Coastal GasLink to KKR-Keats Pipeline Investors II (Canada) Ltd. (KKR) and a subsidiary of Alberta Investment Management Corporation (AIMCo), which is expected to close in the first half of 2020. In conjunction with this sale, the Company will provide an option to the 20 First Nations that have executed agreements with Coastal GasLink to acquire a 10 per cent equity interest in Coastal GasLink on similar terms to what has been agreed with KKR and AIMCo. 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. The termination of these agreements 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 . Energy East and Related Projects Impairment In October 2017 , the Company informed the NEB that it would not proceed with the Energy East, Eastern Mainline and Upland projects. Based on this decision, the Company evaluated the carrying value of its Property, plant and equipment related to the Eastern Mainline project including AFUDC. Due to the inability to reach a regulatory decision for this project, there were no recoveries of costs from third parties. As a result, the Company recognized a non-cash impairment charge of $83 million ( $64 million after tax) in the Liquids Pipelines segment. The non-cash charge was recorded in Goodwill and other asset impairment charges in the Consolidated statement of income. Energy Turbine Impairment At December 31, 2017, the Company recognized a non-cash impairment charge of $21 million ($ 16 million

LEASES

LEASES	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
LEASES	LEASES On January 1, 2019, the Company adopted the FASB's new lease guidance using optional transition relief. Results reported for 2019 reflect the application of the new guidance while the 2018 and 2017 comparative results were prepared and reported under previous leases guidance. Impact of New Lease Guidance on Date of Adoption The following table illustrates the impact of the adoption of the new lease guidance on the Company's previously reported Consolidated balance sheet line items: (millions of Canadian $) As reported December 31, 2018 Adjustment January 1, 2019 Plant, property and equipment 66,503 585 67,088 Accounts payable and other 5,408 57 5,465 Other long-term liabilities 1,008 528 1,536 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 is as follows: year ended December 31 (millions of Canadian $) 2019 Operating lease cost 1 117 Sublease income (11 ) Net operating lease cost 106 1 Includes short-term leases and variable lease costs. Other information related to operating leases is noted in the following tables: year ended December 31 (millions of Canadian $) 2019 Cash paid for amounts included in the measurement of operating lease liabilities 76 ROU assets obtained in exchange for new operating lease liabilities 9 at December 31 2019 Weighted average remaining lease term 10 years Weighted average discount rate 3.5 % Maturities of operating lease liabilities and where they are disclosed on the Consolidated balance sheet as at December 31, 2019 are as follows: (millions of Canadian $) 2020 73 2021 69 2022 59 2023 58 2024 57 Thereafter 323 Total operating lease payments 639 Imputed interest (107 ) Operating lease liabilities 532 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities as at December 31, 2019 are reported as follows: (millions of Canadian $) Accounts payable and other 56 Other long-term liabilities (Note 16) 476 532 Future payments reported under previous lease guidance for the Company’s operating leases as at December 31, 2018 were as follows: (millions of Canadian $) Minimum operating lease payments 2019 81 2020 78 2021 76 2022 69 2023 67 Thereafter 390 761 As at December 31, 2019 , the carrying value of the ROU assets recorded under operating leases was $530 million and is included in Plant, property and equipment on the Consolidated balance sheet. Net rental expense on operating leases in 2018 and 2017 was $84 million and $93 million , respectively. 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 is accounted for as an operating lease and has a liquids transportation contract expiring in 2042. On July 17, 2019, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier and now 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. As a result, only the operating lease income prior to this sale has been included in this lease disclosure. 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, 2019 was $180 million . Operating lease income in 2018 and 2017 was $373 million and $251 million , respectively. Future lease payments to be received under operating leases as at December 31, 2019 are as follows: (millions of Canadian $) Future lease payments 2020 123 2021 116 2022 111 2023 109 2024 109 Thereafter 164 732 The cost and accumulated depreciation for facilities accounted for as operating leases was $834 million and $301 million , respectively, at December 31, 2019 ( 2018 – $2,007 million and $324 million
LEASES	LEASES On January 1, 2019, the Company adopted the FASB's new lease guidance using optional transition relief. Results reported for 2019 reflect the application of the new guidance while the 2018 and 2017 comparative results were prepared and reported under previous leases guidance. Impact of New Lease Guidance on Date of Adoption The following table illustrates the impact of the adoption of the new lease guidance on the Company's previously reported Consolidated balance sheet line items: (millions of Canadian $) As reported December 31, 2018 Adjustment January 1, 2019 Plant, property and equipment 66,503 585 67,088 Accounts payable and other 5,408 57 5,465 Other long-term liabilities 1,008 528 1,536 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 is as follows: year ended December 31 (millions of Canadian $) 2019 Operating lease cost 1 117 Sublease income (11 ) Net operating lease cost 106 1 Includes short-term leases and variable lease costs. Other information related to operating leases is noted in the following tables: year ended December 31 (millions of Canadian $) 2019 Cash paid for amounts included in the measurement of operating lease liabilities 76 ROU assets obtained in exchange for new operating lease liabilities 9 at December 31 2019 Weighted average remaining lease term 10 years Weighted average discount rate 3.5 % Maturities of operating lease liabilities and where they are disclosed on the Consolidated balance sheet as at December 31, 2019 are as follows: (millions of Canadian $) 2020 73 2021 69 2022 59 2023 58 2024 57 Thereafter 323 Total operating lease payments 639 Imputed interest (107 ) Operating lease liabilities 532 The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities as at December 31, 2019 are reported as follows: (millions of Canadian $) Accounts payable and other 56 Other long-term liabilities (Note 16) 476 532 Future payments reported under previous lease guidance for the Company’s operating leases as at December 31, 2018 were as follows: (millions of Canadian $) Minimum operating lease payments 2019 81 2020 78 2021 76 2022 69 2023 67 Thereafter 390 761 As at December 31, 2019 , the carrying value of the ROU assets recorded under operating leases was $530 million and is included in Plant, property and equipment on the Consolidated balance sheet. Net rental expense on operating leases in 2018 and 2017 was $84 million and $93 million , respectively. 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 is accounted for as an operating lease and has a liquids transportation contract expiring in 2042. On July 17, 2019, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier and now 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. As a result, only the operating lease income prior to this sale has been included in this lease disclosure. 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, 2019 was $180 million . Operating lease income in 2018 and 2017 was $373 million and $251 million , respectively. Future lease payments to be received under operating leases as at December 31, 2019 are as follows: (millions of Canadian $) Future lease payments 2020 123 2021 116 2022 111 2023 109 2024 109 Thereafter 164 732 The cost and accumulated depreciation for facilities accounted for as operating leases was $834 million and $301 million , respectively, at December 31, 2019 ( 2018 – $2,007 million and $324 million

EQUITY INVESTMENTS

EQUITY INVESTMENTS	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	EQUITY INVESTMENTS (millions of Canadian $) Ownership Income/(Loss) from Equity Investments Equity Investments year ended December 31 at December 31 2019 2018 2017 2019 2018 Canadian Natural Gas Pipelines TQM 50.0 % 12 12 11 79 71 U.S. Natural Gas Pipelines Northern Border 1 50.0 % 91 87 87 549 677 Millennium 47.5 % 92 75 66 496 511 Iroquois 2 50.0 % 54 60 59 241 291 Pennant Midstream 3 nil 12 17 11 — 256 Other Various 15 17 17 112 113 Mexico Natural Gas Pipelines Sur de Texas 4 60.0 % 3 27 66 600 627 TransGas nil — — (12 ) — — Liquids Pipelines Grand Rapids 5 50.0 % 56 65 17 1,028 1,028 Northern Courier 6 15.0 % 14 — — 62 — Other 7 Various — (1 ) (20 ) 19 21 Power and Storage Bruce Power 8 48.4 % 527 311 434 3,256 3,166 Portlands Energy Centre 9 50.0 % 35 36 31 — 289 TransCanada Turbines 50.0 % 9 8 6 64 63 920 714 773 6,506 7,113 1 At December 31, 2019 , the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company was US$116 million ( 2018 – US$115 million ) due mainly to the fair value assessment of assets at the time of acquisition. 2 At December 31, 2019 , the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$40 million ( 2018 – US$41 million ) due mainly to the fair value assessment of the assets at the time of acquisitions. 3 On August 1, 2019, TC Energy completed the sale of certain Columbia midstream assets, including the Company's investment in Pennant Midstream, to a third party. Refer to Note 27, Acquisitions and dispositions, for additional information. 4 TC Energy has a 60 per cent ownership interest in Sur de Texas which, 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. Sur de Texas was placed into service in September 2019. 5 At December 31, 2019 , the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $101 million ( 2018 – $102 million ) due mainly to interest capitalized during construction and the fair value of guarantees. Grand Rapids was placed in service in August 2017. 6 On July 17, 2019, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier, and it now applies 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, 2019 , the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Courier was $62 million due mainly to the fair value of guarantees and the fair value assessment of assets at the time of partial monetization. 7 Includes investments in HoustonLink Pipeline Company LLC and Canaport Energy East Marine Terminal Limited Partnership. At December 31, 2019 and 2018, the Canaport Energy East Marine Terminal Limited Partnership investment was nil . 8 At December 31, 2019 , the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $829 million ( 2018 – $870 million ) due mainly to capitalized interest and the fair value assessment of assets at the time of acquisitions. 9 Investment in Portlands Energy Centre was reclassed to Assets held for sale following an agreement effective July 30, 2019 to sell the investment to a third party. Refer to Note 6, Assets held for sale, for additional information. 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 ( 2018 – $73 million ) due mainly to capitalized interest. TransGas de Occidente S.A. Impairment In August 2017, TC Energy recognized an impairment charge of $12 million on its 46.5 per cent equity investment in TransGas de Occidente S.A. (TransGas). TransGas constructed and operated a natural gas pipeline in Colombia for a 20 -year contract term. As per the terms of the agreement, upon completion of the 20 -year contract in August 2017, TransGas transferred its pipeline assets to Transportadora de Gas Internacional S.A. The non-cash impairment charge represented the write-down of the remaining carrying value of the equity investment which was recognized in Income from equity investments in the Consolidated statement of income in the Mexico Natural Gas Pipelines segment. Canaport Energy East Marine Terminal Limited Partnership Impairment In October 2017, the Company informed the NEB that it would not be proceeding with the Energy East, Eastern Mainline and Upland projects. As a result, in October 2017, the Company recognized a non-cash impairment charge of $20 million in Income from equity investments in its Liquids Pipelines segment which represented the total carrying value of the equity investment in the Canaport Energy East Marine Terminal Limited Partnership. Distributions and Contributions Distributions received from equity investments for the year ended December 31, 2019 were $1,399 million ( 2018 – $1,106 million ; 2017 – $1,332 million ), of which $186 million ( 2018 – $121 million ; 2017 – $362 million ) was included in Investing activities in the Consolidated statement of cash flows with respect 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, 2019 were $602 million ( 2018 – $1,015 million ; 2017 – $1,681 million ) and are included in Investing activities in the Consolidated statement of cash flows. For 2019 , contributions include $32 million ( 2018 – $179 million ; 2017 – $977 million ) related to TC Energy's proportionate share of the Sur de Texas debt financing requirements. Summarized Financial Information of Equity Investments year ended December 31 2019 2018 2017 (millions of Canadian $) Income Revenues 5,693 4,836 4,913 Operating and other expenses (3,408 ) (3,545 ) (2,993 ) Net income 1,990 1,515 1,636 Net income attributable to TC Energy 920 714 773 at December 31 2019 2018 (millions of Canadian $) Balance Sheet Current assets 2,305 2,209 Non-current assets 21,865 20,647 Current liabilities (2,060 ) (2,049 ) Non-current liabilities (11,461 ) (9,042 ) Loan receivable from affiliate TC Energy holds a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. 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, 2019 , the Company’s Consolidated balance sheet included a MXN 20.9 billion or $1.4 billion ( 2018 – MXN 18.9 billion or $1.3 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. Interest income and other included interest income of $147 million in 2019 ( 2018 – $120 million ; 2017 – $34 million ) from this joint venture with a corresponding proportionate share of interest expense recorded in Income from equity investments in the Mexico Natural Gas Pipelines segment. Interest income and other also included foreign exchange gains of $53 million in 2019 ( 2018 – losses of $5 million ; 2017 – losses of $63 million ) from this joint venture with a corresponding proportionate share of Sur de Texas foreign exchange gains and losses recorded in Income from equity investments in the Corporate segment.

RATE-REGULATED BUSINESSES

RATE-REGULATED BUSINESSES	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
RATE-REGULATED BUSINESSES	RATE-REGULATED BUSINESSES TC Energy's businesses that apply RRA currently include almost all of the Canadian, U.S. and Mexico natural gas pipelines and regulated 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 expenses and credits 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 were regulated by the NEB under the National Energy Board Act (NEB Act) up to August 28, 2019 when the Canadian Energy Regulator Act (CER Act) came into effect, replacing the NEB Act, and the NEB was replaced by the CER. The impact assessment and decision-making for designated major transboundary pipeline projects also changed with the implementation of the new Impact Assessment Act (IA Act) on August 28, 2019, which requires designated projects to be assessed by the Impact Assessment Agency of Canada, formerly the Canadian Environmental Assessment Agency. All 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 NEB or CER. Rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenue requirement for the upcoming year or multiple years. To the extent actual costs and revenues are more or less than forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur. The Company's most significant regulated Canadian natural gas pipelines, based on total operated pipe length, are described below. NGTL System NGTL System's 2019 results reflect the terms of the 2018-2019 Revenue Requirement Settlement (the 2018-2019 Settlement) which includes 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 of the settlement include an ROE of 10.1 per cent on deemed common equity of 40 per cent , an incentive mechanism that has both upside and downside risk and a $20 million after-tax annual TC Energy contribution to reduce the revenue requirement. Toll stabilization is 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 . U.S. Regulated Operations TC Energy's U.S. regulated natural gas pipelines operate under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the 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. 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 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 the 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. ANR Pipeline ANR Pipeline operates under rates established through a FERC-approved rate settlement in 2016. Under terms of the 2016 settlement, neither ANR Pipeline nor the settling parties could file for new rates to become effective earlier than August 1, 2019. However, ANR Pipeline is required to file for new rates to be effective no later than August 1, 2022. 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 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. Mexico Regulated Operations TC Energy's Mexico natural gas pipelines are regulated by the 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 2019 2018 Remaining (millions of Canadian $) Regulatory Assets Deferred income taxes 1 1,088 1,051 n/a Operating and debt-service regulatory assets 2 2 12 1 Pensions and other post-retirement benefits 1,3 417 379 n/a Foreign exchange on long-term debt 1,4 16 46 1-10 Other 107 143 n/a 1,630 1,631 Less: Current portion included in Other current assets (Note 7) 43 83 1,587 1,548 Regulatory Liabilities Operating and debt-service regulatory liabilities 2 139 96 1 Pensions and other post-retirement benefits 3 35 53 n/a ANR related post-employment and retirement benefits other than pension 5 41 54 n/a Long-term adjustment account 6 660 1,015 1-47 Bridging amortization account 6 428 305 11 Pipeline abandonment trust balance 7 1,462 1,113 n/a Cost of removal 8 253 261 n/a Deferred income taxes 1 151 165 n/a Deferred income taxes – U.S. Tax Reform 9 1,239 1,394 n/a Other 60 65 n/a 4,468 4,521 Less: Current portion included in Accounts payable and other (Note 15) 696 591 3,772 3,930 1 These regulatory assets or liabilities are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets or liabilities are not included in rate base and do not yield a return on investment during the recovery period. 2 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances to be included in determination of tolls in the following year. 3 These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from or refunded to customers in future rates. 4 Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. 5 This balance represents the amount ANR estimates it 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, $11 million ( US$8 million ) of the regulatory liability balance at December 31, 2018 (which accumulated between January 2007 and July 2016) was fully amortized at July 31, 2019. The remaining $41 million ( US$32 million ) balance at December 31, 2019 which was accumulated prior to 2007 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period cannot be determined at this time. 6 These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization adjustments during the 2015-2030 settlement term. The 2019 LTAA balance of $ 660 million consists of $ 488 million to be amortized in 2020 with the remaining balance to be amortized over 47 years . 7 This balance represents the amounts collected in tolls from shippers, and are included in the LMCI restricted investments, to fund future abandonment of the Company's CER-regulated pipeline facilities. 8 This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated operations for future costs to be incurred. 9

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL The Company has recorded the following Goodwill on its acquisitions: (millions of Canadian $) U.S. Natural Gas Pipelines Balance at January 1, 2018 13,084 Tuscarora impairment charge (79 ) Foreign exchange rate changes 1,173 Balance at December 31, 2018 14,178 Sale of Columbia midstream assets (595 ) Foreign exchange rate changes (696 ) Balance at December 31, 2019 12,887 As part of the annual goodwill impairment assessment, 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, and therefore, goodwill was not impaired. Sale of Columbia Midstream Assets On August 1, 2019, TC Energy completed the sale of certain Columbia midstream assets to a third party. As these assets constitute a business, and there is 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 finalized its regulatory filing for Tuscarora in response to the 2018 FERC Actions and Form 501-G requirements. Subsequently, Tuscarora reached a new rates settlement-in-principle with its customers and FERC approved these new rates on May 2, 2019. This, combined with changes to other valuation assumptions responsive to Tuscarora’s commercial environment, resulted in a determination that the fair value of Tuscarora did not exceed its carrying value, including goodwill. The fair value of the reporting unit was determined using a discounted cash flow analysis. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. As a result, the Company recorded a goodwill impairment charge of $79 million pre-tax within the U.S. Natural Gas Pipelines segment. 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, at December 31, 2019 and December 31, 2018

INTANGIBLE AND OTHER ASSETS

INTANGIBLE AND OTHER ASSETS	12 Months Ended
	Dec. 31, 2019
Intangible Assets, Net (Excluding Goodwill) [Abstract]
INTANGIBLE AND OTHER ASSETS	INTANGIBLE AND OTHER ASSETS at December 31 2019 2018 (millions of Canadian $) Capital projects in development 1,715 1,051 Employee post-retirement benefits (Note 24) 162 192 Deferred income tax assets (Note 17) 37 322 Fair value of derivative contracts (Note 25) 7 61 Other 247 295 2,168 1,921 Capital projects in development Keystone XL In January 2018, the Company recommenced capitalizing development costs related to Keystone XL. At December 31, 2019, the amount included in Capital projects in development for this project was $1.5 billion (2018 – $0.8 billion ). A portion of the carrying value is recoverable from shippers under certain conditions. Reimbursement of Coastal GasLink pipeline costs In accordance with provisions in the agreements with the LNG Canada joint venture participants, all five parties elected to reimburse TC Energy for their share of costs incurred prior to receiving the Final Investment Decision on the Coastal GasLink pipeline project. In November 2018, the Company received payments totaling $470 million which were recorded as a reduction of the carrying value of Coastal GasLink. Prince Rupert Gas Transmission In July 2017 , the Company was notified that Pacific Northwest LNG would not be proceeding with its proposed LNG project and that Progress Energy (Progress) would be terminating its agreement with TC Energy for the development of the PRGT project. In accordance with the terms of the agreement, all project costs incurred to advance the project, including carrying charges, were fully recoverable upon termination and in October 2017 the Company received the $634 million reimbursement from Progress. Energy East and Related Projects Impairment In October 2017, the Company informed the NEB that it would not proceed with the Energy East, Eastern Mainline and Upland projects. Based on this decision, the Company evaluated its Capital projects in development balance related to the Energy East and Upland projects including AFUDC. As a result, the Company recognized a non-cash impairment charge of $1,153 million ( $870 million

NOTES PAYABLE

NOTES PAYABLE	12 Months Ended
	Dec. 31, 2019
Short-term Debt [Abstract]
NOTES PAYABLE	NOTES PAYABLE 2019 2018 (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 Canada 1 4,034 2.1 % 2,117 2.5 % U.S. (2019 – nil; 2018 – US$448) — — 611 3.1 % Mexico (2019 – US$205; 2018 – US$25) 2 266 2.7 % 34 3.3 % 4,300 2,762 1 At December 31, 2019, Notes payable consisted of Canadian dollar denominated notes of $1,353 million (2018 - $961 million ) and U.S. dollar denominated notes of US$2,068 million (2018 - US$847 million ). 2 The demand senior unsecured revolving credit facility for the Company's Mexico subsidiary can be drawn in either Mexican pesos or U.S. dollars, up to the total facility amount of MXN 5.0 billion or the equivalent in U.S. dollars. At December 31, 2019 , Notes payable consists of short-term borrowings in Canada by TransCanada PipeLines Limited (TCPL) and in Mexico by a wholly-owned Mexican subsidiary. At December 31, 2019 , total committed revolving and demand credit facilities were $12.6 billion ( 2018 – $12.9 billion ). When drawn, interest on these lines of credit is charged at negotiated floating rates of Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following: at December 31 (billions of Canadian $, unless otherwise noted) 2019 2018 Borrower Description Matures Total Facilities Unused Capacity Total Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities 1 : TCPL Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes December 2024 3.0 3.0 3.0 TCPL/TCPL USA/Columbia/TAIL 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 2020 US 4.5 US 4.5 US 4.5 TCPL/TCPL USA/Columbia/TAIL For general corporate purposes of the borrowers, guaranteed by TCPL December 2022 US 1.0 US 1.0 US 1.0 Demand senior unsecured revolving credit facilities 1 : 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 2 For Mexico general corporate purposes, guaranteed by TCPL Demand MXN 5.0 MXN 1.1 MXN 5.0 1 Provisions of various credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and preferred shares. These credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2019, the Company was in compliance with all debt covenants. 2 The demand senior unsecured revolving credit facility for the Company's Mexico subsidiary can be drawn in either Mexican pesos or U.S. dollars, up to the total facility amount of MXN 5.0 billion or the equivalent in U.S. dollars. For the year ended December 31, 2019 , the cost to maintain the above facilities was $11 million ( 2018 – $12 million ; 2017 – $7 million ). At December 31, 2019 , the Company's operated affiliates had an additional $0.8 billion ( 2018 – $0.8 billion

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER at December 31 2019 2018 (millions of Canadian $) Trade payables 3,314 3,224 Regulatory liabilities (Note 11) 696 591 Fair value of derivative contracts (Note 25) 115 922 Unredeemed shares of Columbia Pipeline Group, Inc. — 357 Other 419 314 4,544 5,408 On October 22, 2019, TC Energy made a payment to dissenting Columbia Pipeline Group, Inc. 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 Pipeline Group, Inc. share purchase price of US$25.50 per share.

OTHER LONG-TERM LIABILITIES

OTHER LONG-TERM LIABILITIES	12 Months Ended
	Dec. 31, 2019
Deferred Costs, Noncurrent [Abstract]
OTHER LONG-TERM LIABILITIES	OTHER LONG-TERM LIABILITIES at December 31 2019 2018 (millions of Canadian $) Employee post-retirement benefits (Note 24) 540 569 Operating lease obligations (Note 9) 476 — Long-term contract liabilities (Note 5) 226 121 Fair value of derivative contracts (Note 25) 81 42 Asset retirement obligations 62 90 Guarantees 32 12 Other 197 174 1,614 1,008

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES U.S. Tax Reform As part of U.S. Tax Reform, the enacted U.S. federal corporate income tax rate was reduced from 35 per cent to 21 per cent effective January 1, 2018 and 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. For the Company’s U.S. businesses not subject to RRA, the reduction in enacted income tax rates resulted in a decrease in net deferred income tax liabilities and a deferred income tax recovery of $816 million in 2017. For the Company’s U.S. businesses subject to RRA, the reduction in income tax rates resulted in a reduction in net deferred income tax liabilities and the recognition of a net regulatory liability of $1,686 million on the Consolidated balance sheet at December 31, 2017. Net deferred income tax liabilities related to the cumulative remeasurements of employee post-retirement benefits included in AOCI were also adjusted with a corresponding increase in deferred income tax expense of $12 million in 2017. Given the significance of the legislation, the U.S. Securities and Exchange Commission (SEC) staff issued guidance which allowed registrants to record provisional amounts at December 31, 2017 which could be adjusted as additional information became available, prepared or analyzed during a measurement period not to exceed one year. At December 31, 2017, the Company considered amounts recorded related to U.S. Tax Reform to be reasonable estimates, however, certain amounts were provisional as the Company’s interpretation, assessment and presentation of the impact of the tax law change were further clarified with additional guidance from regulatory, tax and accounting authorities received in 2018. With additional guidance provided during the permitted one-year measurement period, and u pon finalizing its 2017 annual tax returns for its U.S. businesses, the Company recognized further adjustments to its deferred income tax liability and net regulatory liability balances as well as an additional deferred income tax recovery of $52 million 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 proposed regulations in late 2018 which provided administrative guidance and clarified certain aspects of new laws with respect to interest deductibility, base erosion and anti-abuse tax (BEAT), the new dividend received deduction and anti-hybrid rules. In 2019, the U.S. Treasury and the U.S. Internal Revenue Service issued final BEAT regulations which did not have a material impact on the Company. The remaining proposed regulations are complex and comprehensive, and considerable uncertainty continues to exist pending release of the final regulations which is expected to occur in early 2020. If the proposed regulations are enacted as currently drafted, they are not expected to have a material impact on the Company's consolidated financial statements as at December 31, 2019. Mexico Tax Reform In late 2019, Mexico passed tax reform legislation related to, among other things, interest deductibility and tax reporting. These changes did not have an impact on the 2019 consolidated financial statements. The Company is currently assessing the impact for 2020 and future years. Alberta Tax Rate Reduction In June 2019, a reduction to the Alberta corporate tax rate was enacted. For the Company's Canadian businesses not subject to RRA, this resulted in a decrease in net deferred income tax liabilities and a deferred income tax recovery of $32 million . For the Company's Canadian businesses subject to RRA, this rate change resulted in the reduction of both net deferred income tax liabilities and long-term regulatory assets of $83 million on the Consolidated balance sheet at December 31, 2019. Provision for Income Taxes year ended December 31 2019 2018 2017 (millions of Canadian $) Current Canada 84 65 113 Foreign 1 615 250 36 699 315 149 Deferred Canada (29 ) 49 (185 ) Foreign 84 235 751 Foreign – U.S. Tax Reform and 2018 FERC Actions — (167 ) (804 ) 55 117 (238 ) Income Tax Expense/(Recovery) 754 432 (89 ) 1 The December 31, 2019 current foreign Income tax expense mainly relates to the Columbian midstream sale that closed on August 1, 2019. Refer to Note 27, Acquisitions and dispositions, for additional information. Geographic Components of Income before Income Taxes year ended December 31 2019 2018 2017 (millions of Canadian $) Canada 1,144 433 (339 ) Foreign 4,043 3,516 3,645 Income before Income Taxes 5,187 3,949 3,306 Reconciliation of Income Tax Expense/(Recovery) year ended December 31 2019 2018 2017 (millions of Canadian $) Income before income taxes 5,187 3,949 3,306 Federal and provincial statutory tax rate 26.5 % 27.0 % 27.0 % Expected income tax expense 1,375 1,066 893 Valuation allowance release (259 ) — — Foreign income tax rate differentials (206 ) (432 ) (81 ) Income tax differential related to regulated operations (159 ) (54 ) (42 ) (Income)/loss from non-controlling interests (78 ) 50 (64 ) Alberta tax rate reduction (32 ) — — Non-taxable portion of capital gains (28 ) (11 ) (42 ) Non-deductible goodwill on the Columbia midstream disposition 154 — — U.S. Tax Reform and 2018 FERC Actions — (167 ) (804 ) Asset impairment charges — — 34 Non-deductible amounts — — 4 Other (13 ) (20 ) 13 Income Tax Expense/(Recovery) 754 432 (89 ) Deferred Income Tax Assets and Liabilities at December 31 2019 2018 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,046 1,238 Regulatory and other deferred amounts 692 858 Difference in accounting and tax bases of impaired assets and assets held for sale 538 574 Unrealized foreign exchange losses on long-term debt 260 491 Financial instruments 23 — Other 70 292 2,629 3,453 Less: Valuation allowance 673 1,159 1,956 2,294 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 6,197 6,449 Equity investments 1,087 1,069 Taxes on future revenue requirement 232 300 Other 106 180 7,622 7,998 Net Deferred Income Tax Liabilities 5,666 5,704 The above deferred tax amounts have been classified on the Consolidated balance sheet as follows: at December 31 2019 2018 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 13) 37 322 Deferred Income Tax Liabilities Deferred income tax liabilities 5,703 6,026 Net Deferred Income Tax Liabilities 5,666 5,704 At December 31, 2019 , the Company has recognized the benefit of non-capital loss carryforwards of $1,929 million ( 2018 – $1,867 million ) for federal and provincial purposes in Canada, which expire from 2030 to 2039. In addition, the Company has not yet recognized the benefit of capital loss carryforwards of $598 million ( 2018 – $821 million ) for federal and provincial purposes in Canada. The Company also has Ontario minimum tax credits of $102 million ( 2018 – $91 million ), which expire from 2026 to 2039. At December 31, 2019 , the Company has fully recognized the benefit of net operating loss carryforwards of US$1,098 million ( 2018 – US$889 million ) for federal purposes in the U.S., which expire from 2029 to 2037. At December 31, 2019 , the Company has recognized the benefit of net operating loss carryforwards of US$4 million ( 2018 – US$3 million ) in Mexico, which expire from 2024 to 2029. The Company recorded a valuation allowance of $673 million and $1,159 million against the deferred income tax asset balances as at December 31, 2019 and December 31, 2018, respectively. The decrease in the valuation allowance is primarily a result of the foreign exchange movement on unrecognized capital losses, realized capital gains and the rationalization of legal entities. These changes resulted in a deferred income tax recovery of $259 million being recognized in 2019. As of 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, 2019, the Company determined there was sufficient positive evidence to conclude that it is more likely than not that the net deferred tax assets will be realized. Unremitted Earnings of Foreign Investments Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2019 by approximately $648 million ( 2018 – $619 million ) if there had been a provision for these taxes. Income Tax Payments Income tax payments of $713 million , net of refunds, were made in 2019 ( 2018 – payments, net of refunds, of $338 million ; 2017 – payments, net of refunds, of $247 million ). Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit: at December 31 2019 2018 2017 (millions of Canadian $) Unrecognized tax benefit at beginning of year 19 15 18 Gross increases – tax positions in prior years 13 13 — Gross decreases – tax positions in prior years (1 ) (5 ) (1 ) Gross increases – tax positions in current year — — 2 Lapse of statutes of limitations (2 ) (4 ) (4 ) Unrecognized Tax Benefit at End of Year 29 19 15 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 2011. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2013. 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, 2019 reflects $4 million of interest expense ( 2018 – $1 million of interest recovery; 2017 – nil of interest expense). At December 31, 2019 , the Company accrued $ 7 million in interest expense ( December 31, 2018 – $ 3 million ). The Company incurred no penalties associated with income tax uncertainties related to Income tax expense for the years ended December 31, 2019, 2018 and 2017 and no

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT 2019 2018 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Debentures Canadian 2020 250 11.8 % 350 11.4 % U.S. (2019 and 2018 – US$400) 2021 518 9.9 % 546 9.9 % Medium Term Notes Canadian 2021 to 2049 9,491 4.6 % 7,504 4.8 % Senior Unsecured Notes U.S. (2019 – US$14,792; 2018 – US$17,192) 2020 to 2049 19,174 5.2 % 23,456 5.1 % 29,433 31,856 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2019 and 2018 – US$200) 2023 259 7.9 % 273 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2019 and 2018 – US$33) 2026 42 7.5 % 44 7.5 % 905 921 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2019 and 2018 – US$2,250) 2 2020 to 2045 2,916 4.4 % 3,070 4.4 % TC PIPELINES, LP Unsecured Loan Facility U.S. (2019 – nil; 2018 – US$40) — — 55 3.8 % Unsecured Term Loan U.S. (2019 – US$450; 2018 – US$500) 2022 583 2.9 % 682 3.6 % Senior Unsecured Notes U.S. (2019 and 2018 – US$1,200) 2021 to 2027 1,556 4.4 % 1,637 4.4 % 2,139 2,374 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2019 and 2018 – US$672) 2021 to 2026 872 7.2 % 918 7.2 % 2019 2018 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2019 – nil; 2018 – US$35) — — 48 3.3 % Senior Unsecured Notes U.S. (2019 and 2018 – US$250) 2020 to 2035 324 5.6 % 341 5.6 % 324 389 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2019 – US$219; 2018 – US$240) 2021 to 2030 284 7.7 % 327 7.7 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM Unsecured Loan Facility U.S. (2019 – US$39; 2018 – US$19) 2023 51 3.0 % 26 3.6 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2019 – US$23; 2018 – US$24) 2020 30 2.8 % 33 3.5 % NORTH BAJA PIPELINE, LLC Unsecured Term Loan U.S. (2019 and 2018 – US$50) 2021 65 2.8 % 68 3.5 % 37,019 39,982 Current portion of long-term debt (2,705 ) (3,462 ) Unamortized debt discount and issue costs (228 ) (241 ) Fair value adjustments 3 194 230 34,280 36,509 1 Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. The effective interest rate is calculated by discounting the expected future interest payments, adjusted for loan fees, premiums and discounts. Weighted average and effective interest rates are stated as at the respective outstanding dates. 2 Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia’s obligations is required to comply with covenants under the debt indenture and in the event of default, the guarantors would be obligated to pay the principal and related interest. 3 The fair value adjustments include $ 193 million (2018 – $ 232 million) related to the acquisition of Columbia. These adjustments also include an increase of $ 1 million (2018 – decrease of $ 2 million) related to hedged interest rate risk. Refer to Note 25, Risk management and financial instruments, for additional information. Principal Repayments At December 31, 2019 , principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2020 2021 2022 2023 2024 Principal repayments on long-term debt 2,705 1,966 1,932 1,897 289 Long-Term Debt Issued The Company issued long-term debt over the three years ended December 31, 2019 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED September 2019 Medium Term Notes September 2029 700 3.00 % September 2019 Medium Term Notes July 2048 300 4.18 % 1 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 % 2 July 2018 Medium Term Notes July 2048 800 4.18 % July 2018 Medium Term Notes March 2028 200 3.39 % 3 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 % November 2017 Senior Unsecured Notes November 2019 US 550 Floating November 2017 Senior Unsecured Notes November 2019 US 700 2.125 % September 2017 Medium Term Notes March 2028 300 3.39 % September 2017 Medium Term Notes September 2047 700 4.33 % NORTHERN COURIER PIPELINE LIMITED PARTNERSHIP 4,5 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 PORTLAND NATURAL GAS TRANSMISSION SYSTEM April 2018 Unsecured Loan Facility April 2023 US 19 Floating TUSCARORA GAS TRANSMISSION COMPANY August 2017 Unsecured Term Loan August 2020 US 25 Floating TC PIPELINES, LP May 2017 Senior Unsecured Notes May 2027 US 500 3.90 % 1 Reflects coupon rate on re-opening of a pre-existing medium-term notes (MTN) issue. The MTNs were issued at a premium to par, resulting in a re-issuance yield of 3.991 per cent . 2 Reflects 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 . 3 Reflects 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 . 4 Principal and interest payments are made semi-annually over the life of the senior secured notes. 5 Subsequent to the debt issuance, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier. The Company's remaining 15 per cent interest is accounted for 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, 2019 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED November 2019 Senior Unsecured Notes US 700 2.125 % November 2019 Senior Unsecured Notes US 550 Floating May 2019 Medium Term Notes 13 9.35 % March 2019 Debentures 100 10.50 % January 2019 Senior Unsecured Notes US 750 7.125 % January 2019 Senior Unsecured Notes US 400 3.125 % 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 December 2017 Debentures 100 9.80 % November 2017 Senior Unsecured Notes US 1,000 1.625 % June 2017 Acquisition Bridge Facility 1 US 1,513 Floating February 2017 Acquisition Bridge Facility 1 US 500 Floating January 2017 Medium Term Notes 300 5.10 % TC PIPELINES, LP June 2019 Unsecured Term Loan US 50 Floating December 2018 Unsecured Term Loan US 170 Floating GAS TRANSMISSION NORTHWEST LLC May 2019 Unsecured Term Loan US 35 Floating COLUMBIA PIPELINE GROUP, INC. June 2018 Senior Unsecured Notes US 500 2.45 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM May 2018 Senior Secured Notes US 18 5.90 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP March 2018 Senior Unsecured Notes US 9 6.73 % TUSCARORA GAS TRANSMISSION COMPANY August 2017 Senior Secured Notes US 12 3.82 % TRANSCANADA PIPELINE USA LTD. June 2017 Acquisition Bridge Facility 1 US 630 Floating April 2017 Acquisition Bridge Facility 1 US 1,070 Floating 1 These facilities were put in place to finance a portion of the Columbia acquisition and were fully retired in 2017. Interest Expense year ended December 31 2019 2018 2017 (millions of Canadian $) Interest on long-term debt 1,931 1,877 1,794 Interest on junior subordinated notes 427 391 348 Interest on short-term debt 106 73 33 Capitalized interest (186 ) (124 ) (173 ) Amortization and other financial charges 1 55 48 67 2,333 2,265 2,069 1 Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and losses on derivatives used to manage the Company's exposure to changes in interest rates. The Company made interest payments of $ 2,295 million in 2019 ( 2018 – $ 2,156 million ; 2017 – $ 1,987 million ) on long-term debt, junior subordinated notes and short-term debt, net of interest capitalized.

JUNIOR SUBORDINATED NOTES

JUNIOR SUBORDINATED NOTES	12 Months Ended
	Dec. 31, 2019
Junior Subordinated Notes [Abstract]
JUNIOR SUBORDINATED NOTES	JUNIOR SUBORDINATED NOTES 2019 2018 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate 1 Outstanding at December 31 Effective Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED 2 US$1,000 notes issued 2007 at 6.35% 3 2067 1,296 5.1 % 1,364 5.6 % US$750 notes issued 2015 at 5.875% 4,5 2075 972 6.0 % 1,024 6.5 % US$1,200 notes issued 2016 at 6.125% 4,5 2076 1,556 6.7 % 1,637 7.2 % US$1,500 notes issued 2017 at 5.55% 4,5 2077 1,944 5.7 % 2,047 6.2 % $1,500 notes issued 2017 at 4.90% 4,5 2077 1,500 5.4 % 1,500 5.5 % US$1,100 notes issued 2019 at 5.75% 4,5 2079 1,426 6.3 % — — 8,694 7,572 Unamortized debt discount and issue costs (80 ) (64 ) 8,614 7,508 1 The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for issue costs and discounts. 2 The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. 3 In May 2017, Junior subordinated notes of US $1 billion converted from a fixed rate of 6.35 per cent to a floating rate that is reset quarterly to the three-month LIBOR plus 2.21 per cent . 4 The Junior subordinated notes were issued to TransCanada Trust, a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TC Energy's financial statements since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. 5 The coupon rate is initially a fixed interest rate for the first 10 years and converts to a floating rate thereafter. In September 2019, TransCanada Trust (the Trust) issued US$ 1.1 billion of Trust Notes – Series 2019-A to third party 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 the cessation of the LIBOR at the end of 2021. 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. In May 2017, the Trust issued $ 1.5 billion of Trust Notes – Series 2017-B to third-party investors with a fixed interest rate of 4.65 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for $ 1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 4.90 per cent , including a 0.25 per cent administration charge. The rate will reset commencing May 2027 until May 2047 to the then three -month Bankers' Acceptance rate plus 3.33 per cent per annum; from May 2047 until May 2077, the interest rate will reset to the then three -month Bankers' Acceptance rate plus 4.08 per cent per annum. The junior subordinated notes are redeemable at TCPL's option at any time on or after May 18, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. In March 2017, the Trust issued US$ 1.5 billion of Trust Notes – Series 2017-A to third party investors with a fixed interest rate of 5.30 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$ 1.5 billion of junior subordinated notes of TCPL at an initial fixed rate of 5.55 per cent , including a 0.25 per cent administration charge. The rate will reset commencing March 2027 until March 2047 to the then three -month LIBOR plus 3.458 per cent per annum; from March 2047 until March 2077, the interest rate will reset to the then three -month LIBOR plus 4.208 per cent per annum. The junior subordinated notes are redeemable at TCPL's option at any time on or after March 15, 2027 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. Pursuant to the terms of the notes issued between the Trust and TCPL (the Trust Notes) and related agreements, in certain circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TC Energy and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with any other outstanding first preferred shares of TCPL.

NON-CONTROLLING INTERESTS

NON-CONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2019
Noncontrolling Interest [Abstract]
NON-CONTROLLING INTERESTS	NON-CONTROLLING INTERESTS The Company's Non-controlling interests included on the Consolidated balance sheet are as follows: at December 31 2019 2018 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 1,634 1,655 The Company's Net income/(loss) attributable to non-controlling interests included in the Consolidated statement of income are as follows: year ended December 31 2019 2018 2017 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 293 (185 ) 220 Non-controlling interest in Portland Natural Gas Transmission System 1 — — 9 Non-controlling interest in Columbia Pipeline Partners LP 2 — — 9 293 (185 ) 238 1 Non-controlling interest in 2017 for the period January to May when TC Energy sold its remaining interest in Portland to TC PipeLines, LP. 2 Non-controlling interest up to the February 17, 2017 acquisition of all publicly held common units of Columbia Pipeline Partners LP. TC PipeLines, LP During 2019 , the non-controlling interest in TC PipeLines, LP remained at 74.5 per cent . In 2018 , the non-controlling interest in TC PipeLines, LP ranged between 74.3 per cent and 74.5 per cent , and in 2017 , between 73.2 per cent and 74.3 per cent, due to periodic issuances of common units in TC PipeLines, LP to third parties under an at-the-market issuance program. Portland Natural Gas Transmission System In June 2017, TC Energy sold its remaining 11.81 per cent directly held interest in Portland Natural Gas Transmission System (Portland) to TC PipeLines, LP and, as a result, since that date, non-controlling interest in Portland has been nil . Refer to Note 27, Acquisitions and dispositions, for additional information. Columbia Pipeline Partners LP In February 2017, TC Energy acquired all outstanding publicly held common units of Columbia Pipeline Partners LP at a price of US $17.00 and a stub period distribution payment of US $0.10 per common unit for an aggregate transaction value of US $921 million . As this was a transaction between entities under common control, it was recognized in equity. Common Units of TC PipeLines, LP Subject to Rescission At December 31, 2016, $106 million ( US$82 million ) of TC PipeLines, LP common units were recorded as Common units subject to rescission or redemption and classified outside equity on the Consolidated balance sheet. The Company classified these 1.6 million

COMMON SHARES

COMMON SHARES	12 Months Ended
	Dec. 31, 2019
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
COMMON SHARES	COMMON SHARES Number of Shares Amount (thousands) (millions of Canadian $) Outstanding at January 1, 2017 863,759 20,099 Dividend reinvestment and share purchase plan 12,824 790 At-the-market equity issuance program 1 3,462 216 Exercise of options 1,331 62 Outstanding at December 31, 2017 881,376 21,167 At-the-market equity issuance program 1 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 1 Net 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. 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. Commencing with the dividends declared October 31, 2019, common shares purchased with reinvested cash dividends under the Company's DRP will be acquired on the open market at 100 per cent of the weighted average purchase price. 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 (TSX), the New York Stock Exchange (NYSE) or any other existing trading market for TC Energy common shares in Canada or the United States. The ATM program was effective for a 25 -month period and was utilized as appropriate to assist in managing the Company's capital structure. Under the original ATM program, the Company could issue up to $1.0 billion in common shares or the U.S. dollar equivalent. I n June 2018, the Company replenished the capacity available under the program which allowed for the issuance of additional common shares from treasury for an aggregate issuance limit of up to $1.0 billion in common shares for a revised total of $2.0 billion or the U.S. dollar equivalent. In 2017, 3.5 million common shares were issued under the ATM program at an average price of $63.03 per share for proceeds of $216 million , net of approximately $2 million of related commissions and fees. In 2018, 20 million common shares were issued under the 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, the ATM program expired with no common shares issued under it in 2019. 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 higher weighted average number of shares for the diluted earnings per share calculation is due to options exercisable under TC Energy's Stock Option Plan and shares issuable under the DRP. Weighted Average Common Shares Outstanding (millions) 2019 2018 2017 Basic 929 902 872 Diluted 931 903 874 Stock Options Number of (thousands) Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (years) Options outstanding at January 1, 2019 12,404 $52.83 Options granted 2,004 $56.90 Options exercised (5,138 ) $49.08 Options forfeited/expired (176 ) $56.69 Options Outstanding at December 31, 2019 9,094 $55.77 4.1 Options Exercisable at December 31, 2019 5,110 $54.28 3.0 At December 31, 2019 , an additional 7,962,761 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 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 2019 2018 2017 Weighted average fair value $6.37 $5.80 $7.22 Expected life (years) 1 5.7 5.7 5.7 Interest rate 1.9 % 2.1 % 1.2 % Volatility 2 19 % 16 % 18 % Dividend yield 5.0 % 4.2 % 3.6 % 1 Expected life is based on historical exercise activity. 2 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares. The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $13 million in 2019 ( 2018 – $13 million ; 2017 – $12 million ). At December 31, 2019 , unrecognized compensation costs related to non-vested stock options was $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 2019 2018 2017 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 75 10 28 Total fair value of options that have vested 143 101 140 Total options vested 2.1 million 2.1 million 2.3 million As at December 31, 2019 , the aggregate intrinsic value of the total options exercisable was $76 million and the aggregate intrinsic value of options outstanding was $122 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

PREFERRED SHARES	12 Months Ended
	Dec. 31, 2019
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
PREFERRED SHARES	PREFERRED SHARES at December 31, 2019 Number of Shares Outstanding Current Yield Annual Dividend Per Share 1,2 Redemption Price Per Share Redemption and Conversion Option Date Right to Convert Into Carrying Value December 31 2019 2018 2017 (thousands) (millions of Canadian $) 3 Cumulative First Preferred Shares Series 1 14,577 3.479 % $0.86975 $25.00 December 31, 2024 Series 2 360 233 233 Series 2 7,423 Floating 4 Floating $25.00 December 31, 2024 Series 1 179 306 306 Series 3 8,533 2.152 % $0.538 $25.00 June 30, 2020 Series 4 209 209 209 Series 4 5,467 Floating 4 Floating $25.00 June 30, 2020 Series 3 134 134 134 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 % 5 $0.975752 $25.00 April 30, 2024 Series 8 589 589 589 Series 9 18,000 3.762 % 5 $0.9405 $25.00 October 30, 2024 Series 10 442 442 442 Series 11 10,000 3.80 % $0.95 $25.00 November 30, 2020 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 1 Each of the even-numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90 -day Government of Canada Treasury bill rate (T-bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10), 2.96 per cent (Series 12), 4.69 per cent (Series 14) and 3.85 per cent (Series 16). These rates reset quarterly with the then current T-Bill rate. 2 The odd-numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then five -year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), 2.96 per cent (Series 11), 4.69 per cent , subject to a minimum of 5.50 per cent (Series 13) and 3.85 per cent , subject to a minimum of 4.90 per cent (Series 15). 3 Net of underwriting commissions and deferred income taxes. 4 The floating quarterly dividend rate for the Series 2 preferred shares is 3.572 per cent for the period starting December 31, 2019 to, but excluding, March 30, 2020. The floating quarterly dividend rate for the Series 4 preferred shares is 2.932 per cent for the period starting December 31, 2019 to, but excluding, March 30, 2020. The floating quarterly dividend rate for the Series 6 preferred shares is 3.164 per cent for the period starting October 30, 2019 to, but excluding, January 30, 2020. These rates will reset each quarter going forward. 5 No Series 7 or 9 preferred shares were converted on the April 30, 2019 or October 30, 2019 conversion option dates, respectively. As a result, 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. 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 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)_INCO

OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS	OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS Components of OCI, including the portion attributable to non-controlling interests and related tax effects, are as follows: 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 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 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 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 year ended December 31, 2017 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation losses on net investment in foreign operations (746 ) (3 ) (749 ) Reclassification of foreign currency translation gains on disposal of foreign operations (77 ) — (77 ) Change in fair value of cash flow hedges 3 — 3 Reclassification to net income of gains and losses on cash flow hedges (3 ) 1 (2 ) Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (14 ) 3 (11 ) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 21 (5 ) 16 Other comprehensive loss on equity investments (141 ) 35 (106 ) Other Comprehensive Loss (957 ) 31 (926 ) The changes in AOCI by component are as follows: Currency Translation Adjustments Cash Flow Hedges Pension and Other Post-Retirement Benefit Plan Adjustments Equity Investments Total 1 AOCI balance at January 1, 2017 (376 ) (28 ) (208 ) (348 ) (960 ) Other comprehensive loss before reclassifications 2,3 (590 ) (1 ) (11 ) (117 ) (719 ) Amounts reclassified from AOCI (77 ) (2 ) 16 11 (52 ) Net current period other comprehensive (loss)/income (667 ) (3 ) 5 (106 ) (771 ) AOCI balance at December 31, 2017 (1,043 ) (31 ) (203 ) (454 ) (1,731 ) Other comprehensive income/(loss) before reclassifications 2 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 reclassifications 2 (824 ) (49 ) (10 ) (86 ) (969 ) Amounts reclassified from AOCI 4,5 (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 ) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 In 2019 , other comprehensive loss before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling interest losses of $85 million ( 2018 – $166 million gains; 2017 – $159 million losses), $13 million ( 2018 – $1 million losses; 2017 – $4 million gains) and $1 million ( 2018 and 2017 – nil ), respectively. 3 Other comprehensive loss before reclassification on pension and other post-retirement benefit plan adjustments includes a $27 million reduction on settlements and curtailments. 4 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $18 million ( $13 million , net of tax) at December 31, 2019 . 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. 5 In 2019, non-controlling interest gains related to amounts reclassified from AOCI on cash flow hedges and equity investments was nil . Details about reclassifications out of AOCI into the Consolidated statement of income are as follows: Amounts Reclassified 1 Affected Line Item year ended December 31 2019 2018 2017 (millions of Canadian $) Cash flow hedges Commodities (7 ) (4 ) 20 Revenues (Power and Storage) Interest (12 ) (18 ) (17 ) Interest expense (19 ) (22 ) 3 Total before tax 5 6 (1 ) Income tax expense (14 ) (16 ) 2 Net of tax 1,3 Pension and other post-retirement benefit plan adjustments Amortization of actuarial gains and losses (14 ) (16 ) (15 ) Plant operating costs and other 2 Settlement charge — (4 ) (2 ) Plant operating costs and other 2 (14 ) (20 ) (17 ) Total before tax 4 5 5 Income tax expense (10 ) (15 ) (12 ) Net of tax 1 Equity investments Equity income (8 ) (16 ) (15 ) Income from equity investments 3 4 4 Income tax expense (5 ) (12 ) (11 ) Net of tax 1,3 Currency translation adjustments Realization of foreign currency translation gains on disposal of foreign operations 13 — 77 (Loss)/gain on assets held for sale/sold — — — Income tax expense 13 — 77 Net of tax 1 1 Amounts in parentheses indicate expenses to the Consolidated statement of income. 2 These AOCI components are included in the computation of net benefit cost. Refer to Note 24, Employee post-retirement benefits, for additional information. 3 Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of nil ( 2018 – $5 million ; 2017 – nil ) and nil ( 2018 – $2 million ; 2017 – nil ), respectively.

EMPLOYEE POST-RETIREMENT BENEFI

EMPLOYEE POST-RETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
EMPLOYEE POST-RETIREMENT BENEFITS	EMPLOYEE POST-RETIREMENT BENEFITS The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are 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. Net actuarial gains or losses are amortized out of AOCI over the EARSL of employees, which is approximately nine years at December 31, 2019 ( 2018 and 2017 – nine years ). On December 31, 2017 , the Columbia DB Plan merged with TC Energy's U.S. DB Plan. Members accruing benefits in the Columbia DB Plan as of December 31, 2017 were provided an option to either continue receiving benefits in the Columbia DB Plan or instead participate in the existing U.S. DC Plan. In addition, on January 1, 2018, the Columbia other post-retirement benefit plan merged with TC Energy's U.S. other post-retirement benefit plan. The Company also provides its employees with a savings plan in Canada, DC Plans consisting of 401(k) Plans 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, 2019 ( 2018 and 2017 – 12 years ). In 2019 , the Company expensed $61 million ( 2018 – $59 million ; 2017 – $42 million ) for the savings and DC Plans. In April 2017, the Company U.S. DB Plan was closed to non-union new entrants. All non-union hires now participate in the DC Plan. Total cash contributions by the Company for employee post-retirement benefits were as follows: year ended December 31 2019 2018 2017 (millions of Canadian $) DB Plans 122 103 163 Other post-retirement benefit plans 22 23 7 Savings and DC Plans 61 59 42 205 185 212 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 $12 million letter of credit to the Canadian DB Plan in 2019 ( 2018 – $17 million ; 2017 – $27 million ), resulting in a total of $289 million provided to the Canadian DB Plan under letters of credit at December 31, 2019 . The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2019 and the next required valuation will be as at January 1, 2020. 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. In 2017, as a result of settlements and curtailments that occurred upon the completion of the U.S. Northeast power generation asset sales, interim remeasurements were performed on TC Energy’s U.S. DB Plan and other post-retirement benefit plans. The impact of these remeasurements reduced the U.S. DB Plan's unrealized actuarial losses by $3 million , which was included in OCI, and resulted in a settlement charge of $2 million which was recorded in net benefit cost in 2017. These remeasurements had no impact on the other post-retirement benefit plan's unrealized actuarial losses. The Company's funded status at December 31 is comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2019 2018 2019 2018 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,653 3,646 430 375 Service cost 126 121 5 4 Interest cost 142 134 17 14 Employee contributions 5 5 — — Benefits paid (213 ) (177 ) (24 ) (23 ) Actuarial loss/(gain) 394 (92 ) 13 43 Settlement — (71 ) — — Foreign exchange rate changes (49 ) 87 (14 ) 17 Benefit obligation – end of year 4,058 3,653 427 430 Change in Plan Assets Plan assets at fair value – beginning of year 3,321 3,451 376 365 Actual return on plan assets 505 (73 ) 52 (15 ) Employer contributions 2 122 103 22 23 Employee contributions 5 5 — — Benefits paid (212 ) (176 ) (24 ) (27 ) Settlement — (71 ) — — Foreign exchange rate changes (48 ) 82 (20 ) 30 Plan assets at fair value – end of year 3,693 3,321 406 376 Funded Status – Plan Deficit (365 ) (332 ) (21 ) (54 ) 1 The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation. 2 Excludes a $12 million letter of credit provided to the Canadian DB Plan for funding purposes ( 2018 – $17 million ). The amounts recognized on the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans are as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2019 2018 2019 2018 Intangible and other assets (Note 13) — — 162 192 Accounts payable and other — (1 ) (8 ) (8 ) Other long-term liabilities (Note 16) (365 ) (331 ) (175 ) (238 ) (365 ) (332 ) (21 ) (54 ) Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that are not fully funded: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2019 2018 2019 2018 Projected benefit obligation 1 (4,058 ) (3,653 ) (182 ) (246 ) Plan assets at fair value 3,693 3,321 — — Funded Status – Plan Deficit (365 ) (332 ) (182 ) (246 ) 1 The projected benefit obligation for the pension benefit plans differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels. The funded status based on the accumulated benefit obligation for all DB Plans is as follows: at December 31 2019 2018 (millions of Canadian $) Accumulated benefit obligation (3,719 ) (3,347 ) Plan assets at fair value 3,693 3,321 Funded Status – Plan Deficit (26 ) (26 ) Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of plans that are not fully funded. at December 31 2019 2018 (millions of Canadian $) Accumulated benefit obligation (2,397 ) (3,347 ) Plan assets at fair value 2,351 3,321 Funded Status – Plan Deficit (46 ) (26 ) The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows: Percentage of Target Allocations at December 31 2019 2018 2019 Debt securities 32 % 33 % 25% to 45% Equity securities 58 % 56 % 40% to 70% Alternatives 10 % 11 % 5% to 15% 100 % 100 % Debt and equity securities include the Company's debt and common shares as follows: at December 31 Percentage of (millions of Canadian $) 2019 2018 2019 2018 Debt securities 9 8 0.2 % 0.3 % Equity securities 15 7 0.4 % 0.2 % 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 Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 Asset Category Cash and Cash Equivalents 58 48 — — — — 58 48 1 1 Equity Securities: Canadian 402 355 189 138 — — 591 493 14 13 U.S. 523 460 156 116 — — 679 576 17 16 International 46 40 320 281 — — 366 321 9 9 Global 136 116 297 268 — — 433 384 11 10 Emerging 8 8 126 138 — — 134 146 3 4 Fixed Income Securities: Canadian Bonds: Federal — — 198 186 — — 198 186 5 5 Provincial — — 246 198 — — 246 198 6 5 Municipal — — 12 8 — — 12 8 — 1 Corporate — — 125 112 — — 125 112 3 3 U.S. Bonds: Federal 421 350 7 — — — 428 350 11 9 State — — — — — — — — — — Municipal — — 1 — — — 1 — — — Corporate 67 145 120 51 — — 187 196 5 5 International: Government 7 6 4 4 — — 11 10 — 1 Corporate — 19 52 18 — — 52 37 1 1 Mortgage backed 46 128 7 — — — 53 128 1 3 Other Investments: Real estate — — — — 196 196 196 196 5 5 Infrastructure — — — — 181 163 181 163 4 4 Private equity funds — — — — 2 3 2 3 — 1 Funds held on deposit 146 142 — — — — 146 142 4 4 1,860 1,817 1,860 1,518 379 362 4,099 3,697 100 100 The following table presents the net change in the Level III fair value category: (millions of Canadian $, pre-tax) Balance at December 31, 2017 216 Purchases and sales 127 Realized and unrealized gains 19 Balance at December 31, 2018 362 Purchases and sales 35 Realized and unrealized losses (18 ) Balance at December 31, 2019 379 The Company's expected funding contributions in 2020 are approximately $116 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $62 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $12 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 2020 195 25 2021 199 25 2022 203 24 2023 207 24 2024 209 24 2025 to 2029 1,084 117 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, 2019 . 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 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 Other Post-Retirement at December 31 2019 2018 2019 2018 Discount rate 3.20 % 3.90 % 3.35 % 4.10 % Rate of compensation increase 3.00 % 3.00 % — — The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows: Pension Other Post-Retirement year ended December 31 2019 2018 2017 2019 2018 2017 Discount rate 3.90 % 3.60 % 3.95 % 4.10 % 3.70 % 4.15 % Expected long-term rate of return on plan assets 6.60 % 6.70 % 6.50 % 4.30 % 4.00 % 6.05 % Rate of compensation increase 3.00 % 3.00 % 1.20 % — — — 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 2020 measurement purposes. The rate was assumed to decrease gradually to 4.50 % by 2029 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects: (millions of Canadian $) Increase Decrease Effect on total of service and interest cost components 2 (2 ) Effect on post-retirement benefit obligation 31 (25 ) The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans is as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2019 2018 2017 2019 2018 2017 Service cost 1 126 121 108 5 4 4 Other components of net benefit cost 1 Interest cost 142 134 122 17 14 14 Expected return on plan assets (222 ) (221 ) (178 ) (15 ) (16 ) (21 ) Amortization of actuarial loss 12 15 14 2 1 1 Amortization of regulatory asset 14 18 37 2 — 1 Settlement charge – regulatory asset — — 2 — — — Settlement charge – AOCI — 4 2 — — — (54 ) (50 ) (1 ) 6 (1 ) (5 ) Net Benefit Cost Recognized 72 71 107 11 3 (1 ) 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: 2019 2018 2017 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 398 20 364 53 273 11 The estimated net loss for the DB Plans and for the other post-retirement benefit plans that will be amortized from AOCI into net periodic benefit cost in 2020 is $21 million and $2 million , respectively. Pre-tax amounts recognized in OCI were as follows: 2019 2018 2017 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 (12 ) (2 ) (15 ) (1 ) (18 ) (1 ) Curtailment — — — — (14 ) (2 ) Settlement — — (4 ) — (11 ) — Funded status adjustment 52 (37 ) 110 43 46 (7 ) 40 (39 ) 91 42 3 (10 )

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2019
Risk Management and Financial Instruments [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Risk Management Overview TC Energy has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and 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 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 the financial instruments it holds. 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 the exposure to market risk may consist of 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 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 the Company's liquids marketing business, TC Energy enters into pipeline and storage terminal capacity contracts, as well as crude purchase and sale agreements. TC Energy fixes a portion of its exposure on these contracts by entering into derivative instruments to manage its variable price fluctuations that arise from physical liquids transactions. 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 is at floating interest rates. In addition, the Company is exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. The Company manages its interest rate risk using interest rate swaps. Many of TC Energy's financial instruments and contractual obligations with variable rate components reference the London Interbank Offered Rate (LIBOR). This rate will cease to be published at the end of 2021 and will likely be replaced by a secured overnight financing rate. The Company will continue to monitor developments and the impact, if any, on the business. 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 portion of TC Energy's businesses generate earnings in U.S. dollars, but since its financial results are reported 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 one-year basis using foreign exchange derivatives, however, the natural exposure beyond that period remains. 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: 2019 2018 at December 31 Fair 1,2 Notional Fair 1,2 Notional (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2023) 3 3 US 100 (43 ) US 300 U.S. dollar foreign exchange options (maturing 2020 to 2021) 10 US 3,000 (47 ) US 2,500 13 US 3,100 (90 ) US 2,800 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2019 , Net income includes net realized gains of nil ( 2018 – gains of $2 million ) related to the interest component of cross-currency swap settlements which are reported within Interest expense. The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2019 2018 (millions of Canadian $, unless otherwise noted) Notional amount 29,300 (US 22,600) 31,000 (US 22,700) Fair value 33,400 (US 25,700) 31,700 (US 23,200) 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 a loan receivable. During the year, continued low natural gas prices presented increased financial challenges for some of our natural gas shippers that resulted in restructuring and bankruptcy for certain shipper entities with no significant negative impact to the Company's 2019 earnings or cash flow. The Company monitors its counterparties and reviews its accounts receivable regularly and, if needed, the Company records allowances for doubtful accounts using the specific identification method. At December 31, 2019 and 2018 , there were no significant amounts past due or impaired, no significant credit risk concentration and no significant credit losses during the year. 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 mitigate 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. TC Energy has significant credit and performance exposures 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, intangible and other assets, notes payable, accounts payable and other, 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. 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: 2019 2018 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Long-term debt, including current portion 1,2 (Note 18) (36,985 ) (43,187 ) (39,971 ) (42,284 ) Junior subordinated notes (Note 19) (8,614 ) (8,777 ) (7,508 ) (6,665 ) (45,599 ) (51,964 ) (47,479 ) (48,949 ) 1 Long-term debt is recorded at amortized cost, except for US$200 million ( 2018 – US$750 million ) that is attributed to hedged risk and recorded at fair value. 2 Net income in 2019 included unrealized losses of $3 million ( 2018 – $2 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 at December 31, 2019 ( 2018 – US$750 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 are classified as available-for-sale assets: 2019 2018 at December 31 LMCI Restricted Investments Other Restricted Investments 1 LMCI Restricted Investments Other Restricted Investments 1 (millions of Canadian $) Fair value of fixed income securities 2 Maturing within 1 year — 6 — 22 Maturing within 1-5 years 26 100 — 110 Maturing within 5-10 years 801 — 140 — Maturing after 10 years 61 — 952 — Fair value of equity securities 2 556 — — — 1,444 106 1,092 132 1 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. 2 Available-for-sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet. 2019 2018 2017 year ended December 31 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized gains/(losses) 32 3 11 — (3 ) 1 Net realized gains/(losses) 3 60 — (4 ) — (1 ) — 1 Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. 2 Gains and losses on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income. 3 Realized gains and losses on the sale of LMCI restricted investments are determined using the average cost basis. 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, 2019 is as follows: at December 31, 2019 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 — — — 118 118 Foreign exchange — — 10 61 71 Interest rate — 1 — — 1 — 1 10 179 190 Intangible and other 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) Commodities 2 (4 ) — — (104 ) (108 ) Foreign exchange — — (1 ) (3 ) (4 ) Interest rate (3 ) — — — (3 ) (7 ) — (1 ) (107 ) (115 ) Other long-term liabilities (Note 16) Commodities 2 (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 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. The balance sheet classification of the fair value of derivative instruments as at December 31, 2018 is as follows: at December 31, 2018 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 1 — — 716 717 Foreign exchange — — 16 1 17 Interest rate 3 — — — 3 4 — 16 717 737 Intangible and other assets (Note 13) Commodities 2 1 — — 50 51 Foreign exchange — — 1 — 1 Interest rate 8 1 — — 9 9 1 1 50 61 Total Derivative Assets 13 1 17 767 798 Accounts payable and other (Note 15) Commodities 2 (4 ) — — (622 ) (626 ) Foreign exchange — — (105 ) (188 ) (293 ) Interest rate — (3 ) — — (3 ) (4 ) (3 ) (105 ) (810 ) (922 ) Other long-term liabilities (Note 16) Commodities 2 — — — (28 ) (28 ) Foreign exchange — — (2 ) — (2 ) Interest rate (11 ) (1 ) — — (12 ) (11 ) (1 ) (2 ) (28 ) (42 ) Total Derivative Liabilities (15 ) (4 ) (107 ) (838 ) (964 ) Total Derivatives (2 ) (3 ) (90 ) (71 ) (166 ) 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the Company's exposures to market risk. Derivatives in fair value hedging relationships The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities: at December 31 Carrying amount Fair value hedging adjustments 1 (millions of Canadian $) 2019 2018 2019 2018 Current portion of long-term debt — (748 ) — 3 Long-term debt (260 ) (273 ) (1 ) — (260 ) (1,021 ) (1 ) 3 1 At December 31, 2019 and 2018 , 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 is as follows: at December 31, 2019 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 492 14 39 — — Sales 1 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 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. at December 31, 2018 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 23,865 44 59 — — Sales 1 17,689 56 79 — — Millions of U.S. dollars — — — 3,862 1,650 Maturity dates 2019-2023 2019-2027 2019 2019 2019-2030 1 Volumes 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 2019 2018 2017 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized (losses)/gains in the year Commodities 2 (111 ) 28 62 Foreign exchange 245 (248 ) 88 Interest rate — — (1 ) Amount of realized gains/(losses) in the year Commodities 378 351 (107 ) Foreign exchange (70 ) (24 ) 18 Interest rate — — 1 Derivative instruments in hedging relationships Amount of realized (losses)/gains in the year Commodities (6 ) (1 ) 23 Foreign exchange — — 5 Interest rate 2 (1 ) 1 1 Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively. 2 In 2019 , 2018 and 2017 , 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 derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: year ended December 31 2019 2018 2017 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI 1 Commodities (15 ) (1 ) (1 ) Interest rate (63 ) (13 ) 4 (78 ) (14 ) 3 1 No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI. Effect of fair value and cash flow hedging relationships The following table details amounts presented in the Consolidated statement of income in which the effects of fair value or cash flow hedging relationships are recorded. year ended December 31 2019 2018 2017 (millions of Canadian $) Fair Value Hedges Interest rate contracts 1 Hedged items (19 ) (71 ) (74 ) Derivatives designated as hedging instruments 1 (4 ) 1 Cash Flow Hedges Reclassification of (losses)/gains on derivative instruments from AOCI to net income 2,3 Interest rate contracts 1 (12 ) (22 ) (17 ) Commodity contracts 4 (7 ) (5 ) 20 1 Presented within Interest expense in the Consolidated statement of income. 2 Refer 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. 3 There are no amounts recognized in earnings that were excluded from effectiveness testing. 4 Presented within Revenues (Power and Storage) in the Consolidated statement of income. Offsetting of derivative instruments The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TC Energy has no master netting agreements, however, similar contracts are entered into containing rights to offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis on the Consolidated balance sheet. The following tables show the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: at December 31, 2019 Gross Derivative Instruments Amounts Available for Offset 1 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 ) 1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2018 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative instrument assets Commodities 768 (626 ) 142 Foreign exchange 18 (18 ) — Interest rate 12 (4 ) 8 798 (648 ) 150 Derivative instrument liabilities Commodities (654 ) 626 (28 ) Foreign exchange (295 ) 18 (277 ) Interest rate (15 ) 4 (11 ) (964 ) 648 (316 ) 1 Amounts available for offset do not include cash collateral pledged or received. With respect to the derivative instruments presented above, the Company provided cash collateral of $58 million and letters of credit of $25 million at December 31, 2019 ( 2018 – $143 million and $22 million , respectively) to its counterparties. At December 31, 2019 , the Company held no cash collateral and no letters of credit ( 2018 – nil and $1 million , respectively) from counterparties on asset exposures. Credit-risk-related contingent features of derivative instruments Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. The Company may also need to provide collateral if the fair value of its derivative financial instruments exceeds pre-defined exposure limits. Based on contracts in place and market prices at December 31, 2019 , the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $4 million ( 2018 – $6 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, 2019 , the Company would have been required to provide collateral of $4 million ( 2018 – $6 million ) to its counterparties. 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 bank lines 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, are categorized as follows: at December 31, 2019 Quoted Prices in Active Markets Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 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 1 There were no transfers from Level II to Level III for the year ended December 31, 2019 . at December 31, 2018 Quoted Prices in Active Markets Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets Commodities 581 187 — 768 Foreign exchange — 18 — 18 Interest rate — 12 — 12 Derivative Instrument Liabilities Commodities (555 ) (95 ) (4 ) (654 ) Foreign exchange — (295 ) — (295 ) Interest rate — (15 ) — (15 ) 26 (188 ) (4 ) (166 ) 1 There were no transfers from Level II to Level III for the year ended December 31, 2018 . 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) 2019 2018 Balance at beginning of year (4 ) (7 ) Transfers out of Level III 4 5 Total (losses)/gains included in Net income (3 ) 8 Total losses included in OCI (4 ) — Settlements — (9 ) Foreign exchange — (1 ) Balance at end of year 1 (7 ) (4 ) 1 Revenues include unrealized losses of $3 million attributed to derivatives in the Level III category that were still held at December 31, 2019 ( 2018 – unrealized losses of $5 million ).

CHANGES IN OPERATING WORKING CA

CHANGES IN OPERATING WORKING CAPITAL	12 Months Ended
	Dec. 31, 2019
CHANGES IN OPERATING WORKING CAPITAL
CHANGES IN OPERATING WORKING CAPITAL	CHANGES IN OPERATING WORKING CAPITAL year ended December 31 2019 2018 2017 (millions of Canadian $) Decrease/(increase) in Accounts receivable 31 (69 ) (576 ) Increase in Inventories (42 ) (49 ) (38 ) Decrease in Assets held for sale — — 14 (Increase)/decrease in Other current assets (15 ) 45 189 Increase/(decrease) in Accounts payable and other 352 (70 ) 151 (Decrease)/increase in Accrued interest (33 ) 41 12 Decrease in Liabilities related to Assets held for sale — — (25 ) Decrease/(increase) in Operating Working Capital 293 (102 ) (273 )

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS U.S. Natural Gas Pipelines Columbia Midstream Assets On August 1, 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 (Loss)/gain on assets held for sale/sold 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. Iroquois Gas Transmission System and Portland Natural Gas Transmission System In June 2017, the Company closed the sale of 49.34 per cent of its 50 per cent interest in Iroquois, a long with an option to sell the remaining 0.66 per cent at a later date, to TC PipeLines, LP. At the same time, the Company closed the sale of its remaining 11.81 per cent interest in Portland to TC PipeLines, LP. Proceeds from these transactions were US$765 million , before post-closing adjustments, and were comprised of US$597 million in cash and US$168 million representing a proportionate share of Iroquois and Portland debt. Liquids Pipelines Northern Courier On July 17, 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 (Loss)/gain on assets held for sale/sold 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 is using the equity method to account for its remaining 15 per cent interest in the Company’s consolidated financial statements. Power and Storage 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. On May 21, 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 (Loss)/gain on assets held for sale/sold 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 (Loss)/gain on assets held for sale/sold in the Consolidated statement of income. Ontario Solar Assets In December 2017, the Company completed the sale of its Ontario solar assets to a third party for proceeds of $541 million before post-closing adjustments. As a result, the Company recorded a gain on sale of $127 million ( $136 million after tax) which is included in (Loss)/gain on assets held for sale/sold in the Consolidated statement of income. U.S. Northeast Power Assets In 2018, u pon finalizing its 2017 annual tax returns for its U.S. operations, the Company recorded a $27 million income tax recovery related to the sale of its U.S. Northeast power generation assets. In April 2017 , the Company completed the sale of TC Hydro for proceeds of approximately US$1.07 billion before post-closing adjustments and recorded a gain on sale of $715 million ( $440 million after tax), including the impact of $5 million of foreign currency translation gains which were reclassified from AOCI to net income. In June 2017 , the Company completed the sale of Ravenswood, Ironwood, Kibby Wind and Ocean State Power for proceeds of approximately US$2.029 billion before post-closing adjustments. In 2016, the Company recorded a loss of $829 million ( $863 million after tax) which included the impact of $70 million of foreign currency translation gains that were reclassified from AOCI to net income on close. The Company recorded an additional loss on sale of $211 million ( $167 million after tax) in 2017 which included $2 million in foreign currency translation gains. This additional loss primarily related to adjustments to the purchase price and repair costs for an unplanned outage at Ravenswood prior to close of the sale.

COMMITMENTS, CONTINGENCIES AND

COMMITMENTS, CONTINGENCIES AND GUARANTEES	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, CONTINGENCIES AND GUARANTEES	COMMITMENTS, CONTINGENCIES AND GUARANTEES Commitments TC Energy and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business. Purchases under these contracts in 2019 were $236 million (2018 – $207 million ; 2017 – $214 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, 2019 , TC Energy had the following capital expenditure commitments: • approximately $4.5 billion for its Canadian natural gas pipelines, primarily related to construction costs associated with the Coastal GasLink pipeline and NGTL System expansion projects. Upon close of the sale of a 65 per cent interest in Coastal GasLink and establishment of a secured construction credit facility, project commitments will be predominantly funded by project-level financing and equity partners. Refer to Note 8, Plant, property and equipment, for additional information • approximately $0.1 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with Columbia Gas and ANR pipeline projects • approximately $0.2 billion for its Mexico natural gas pipelines, primarily related to construction of the Villa de Reyes and Tula pipeline projects • approximately $0.2 billion for its Liquids pipelines, primarily related to the development of Keystone XL • approximately $0.7 billion for its Power and Storage business, primarily related to the Company's proportionate share of commitments for Bruce Power's life extension program. Contingencies TC Energy is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2019 , the Company had accrued approximately $39 million ( 2018 – $40 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 construction services and 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, (iii) severally or (iv) exclusively guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit which are primarily related to delivery of natural gas, 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 is as follows: 2019 2018 at December 31 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Northern Courier pipeline to 2055 300 27 — — Sur de Texas to 2020 109 — 183 1 Bruce Power to 2021 88 — 88 — Other jointly-owned entities to 2059 100 10 104 11 597 37 375 12 1 TC Energy's share of the potential estimated current or contingent exposure.

CORPORATE RESTRUCTURING COSTS

CORPORATE RESTRUCTURING COSTS	12 Months Ended
	Dec. 31, 2019
Restructuring and Related Activities [Abstract]
CORPORATE RESTRUCTURING COSTS	CORPORATE RESTRUCTURING COSTS In mid-2015, the Company commenced a business restructuring and transformation initiative to reduce overall costs and maximize the effectiveness and efficiency of its existing operations. The Company incurred corporate restructuring costs and recorded a provision to allow for planned severance costs in future years, as well as expected future losses under lease commitments. Cumulatively to December 31, 2019, the Company has incurred costs of $ 86 million for employee severance and $ 61 million for lease commitments, net of $ 158 million related to costs that were recoverable through regulatory and tolling structures. The remaining lease commitments provision at December 31, 2019 is expected to be fully realized by 2027. Changes in the restructuring liability were as follows: (millions of Canadian $) Employee Severance Lease Commitments Total Restructuring liability as at December 31, 2017 9 53 62 Restructuring charges 1 — 42 42 Accretion expense — 1 1 Cash payments (9 ) (15 ) (24 ) Restructuring liability as at December 31, 2018 — 81 81 Accretion expense — 2 2 Cash payments — (14 ) (14 ) Restructuring liability as at December 31, 2019 — 69 69 1 At December 31, 2018 , the Company recorded an additional $21 million in Plant operating costs and other in the Consolidated statement of income and $21 million as a regulatory asset on the Consolidated balance sheet related to costs that are recoverable through regulatory and tolling structures in future periods.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are considered non-consolidated VIEs and are accounted for as equity investments. Consolidated VIEs The Company's consolidated VIEs consist of legal entities where the Company is the primary beneficiary. As the primary beneficiary, the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly impact economic performance including purchasing or selling significant assets; maintenance and operations of assets; incurring additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the VIE. A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest, the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The consolidated VIEs whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations, or are not considered a business, are as follows: at December 31 (millions of Canadian $) 2019 2018 ASSETS Current Assets Cash and cash equivalents 106 45 Accounts receivable 88 79 Inventories 27 24 Other 8 13 229 161 Plant, Property and Equipment 3,050 3,026 Equity Investments 785 965 Goodwill 431 453 Intangible and Other Assets — 8 4,495 4,613 LIABILITIES Current Liabilities Accounts payable and other 70 88 Accrued interest 21 24 Current portion of long-term debt 187 79 278 191 Regulatory Liabilities 45 43 Other Long-Term Liabilities 9 3 Deferred Income Tax Liabilities 9 13 Long-Term Debt 2,694 3,125 3,035 3,375 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 are as follows: at December 31 (millions of Canadian $) 2019 2018 Balance sheet Equity investments 1 4,720 4,575 Off-balance sheet Potential exposure to guarantees 466 170 Maximum exposure to loss 5,186 4,745 1 Includes equity investment in Portlands Energy Centre classified as Assets held for sale as at December 31, 2019. Refer to Note 6, Assets held for sale, for additional information.

ACCOUNTING POLICIES (Policies)

ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These consolidated financial statements include the accounts of TC Energy and its subsidiaries. The Company consolidates variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which it has a controlling financial interest. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. TC Energy uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. 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: • fair value of equity investments (Note 10) and the recoverability of plant, property and equipment (Note 8) • fair value of reporting units that contain goodwill (Notes 12 and 27) • recoverability of capitalized project costs (Note 13) and • fair value of assets and liabilities acquired in a business combination. Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial statements, but they 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 8) • carrying value of regulatory assets and liabilities (Note 11) • carrying value of asset retirement obligations (Note 16) • provisions for income taxes, including U.S. Tax Reform (Note 17) • assumptions used to measure retirement and other post-retirement obligations (Note 24) • fair value of financial instruments (Note 25) and • provisions for commitments, contingencies, guarantees (Note 28) and restructuring costs (Note 29). 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 CER, formerly the National Energy Board (NEB), the Alberta Energy Regulator (AER) or the OGC. 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 appropriately 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 asset 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. Once in operation, the Coastal GasLink pipeline is not expected to apply RRA.
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. 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 risks related to variances in revenues and most costs. These variances 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. 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. 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 midstream assets. Mexico Natural Gas Pipelines Capacity Arrangements and Transportation Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for customers. 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, crude oil in transit and 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	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 one 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. Regulated natural gas storage base gas, which is valued at cost, represents gas volumes that are maintained to ensure adequate reservoir pressure exists to deliver natural gas held in storage. Base gas is not depreciated. When 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. Costs incurred to remove plant, property and equipment from service, net of any salvage proceeds, are also recorded in accumulated depreciation. Midstream and 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 their sale in 2019, plant, property and equipment for midstream assets 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. 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. 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. 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. Non-regulated 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 . Capitalized Project Costs 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 Intangible and other 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.
Impairment of Long-Lived 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.
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, 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 for the reporting unit that will be retained.
Loans and Receivables	Loans and Receivables Loans receivable from affiliates and accounts receivable are measured at cost.
Power Purchase Arrangements	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	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 all 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 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. D eferred 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 Operating and other expenses. For those AROs that the Company records, the following assumptions are used: • when the asset is expected to be retired • the scope and cost of abandonment and reclamation activities that are required, and • appropriate inflation and discount rates. The Company has recorded AROs related to its non-regulated natural gas storage operations, mineral rights and power generation facilities. The scope and timing of asset retirements related to most of the Company's natural gas pipelines and liquids pipelines is 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, with the exception of certain abandoned facilities and certain other facilities on its Columbia Gas pipeline.
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 upon the generation or sale of power using the best estimate of the amount required to settle the 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), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service, and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs. The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five -year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life (EARSL) of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the EARSL of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance sheet and recognizes changes in that funded status through Other comprehensive income (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 (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 of the 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 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. 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. The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines 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 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 years 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 for all costs 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 2019 Leases In February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the Consolidated statement of income. The new guidance does not make extensive changes to lessor accounting. The new guidance was effective January 1, 2019 and was applied using optional transition relief which allowed entities to initially apply the new lease standard at adoption (January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This transition option allowed the Company to not apply the new guidance, including disclosure requirements, to the comparative periods presented. The Company elected available practical expedients and exemptions upon adoption which allowed the Company: • to not reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard • to carry forward the historical lease classification and its accounting treatment for land easements on existing agreements • to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption • to not separate lease and non-lease components for all leases for which the Company is the lessee and for facility and liquids tank terminals for which the Company is the lessor • to use hindsight in determining the lease term and assessing ROU assets for impairment. The new guidance had a significant impact on the Company's Consolidated balance sheet, but did not have an impact in the Company's Consolidated statements of income and cash flows. The most impactful change was the recognition of ROU assets and lease liabilities for operating leases and providing additional new disclosures about the Company's leasing activities. Refer to Note 9, Leases, for additional information related to the impact of adopting the new guidance. In the application of the new guidance, significant assumptions and judgments are used to determine the following: • whether a contract contains a lease • the duration of the lease term including exercising lease renewal options. The lease term for all of the Company’s leases includes the noncancellable period of the lease plus any additional periods covered by either a Company option to extend (or not to terminate) the lease that the Company is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor • the discount rate for the lease. Lessee Accounting Policy The Company determines if an arrangement is a lease at inception of the contract. Operating leases are recognized as 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. 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. The operating lease ROU asset also includes any prepaid lease payments and initial direct costs incurred and excludes lease incentives. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. 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. 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 the changes in facts and circumstances on which these payments are based occur. Fair value measurement In August 2018, the FASB issued new guidance that amends certain disclosure requirements for fair value measurements. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Company elected to adopt this guidance effective first quarter 2019. The guidance was applied retrospectively and did not have a material impact on the Company's consolidated financial statements. Future Accounting Changes 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 is effective January 1, 2020 and will be applied using a modified retrospective approach. The adoption of this new guidance will 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 is effective January 1, 2020 and will be applied prospectively to all implementation costs incurred after the date of adoption. The adoption of this new guidance will 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 is effective January 1, 2020 and will be applied on a retrospective basis. The adoption of this new guidance will not have a material 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 is effective for annual disclosure requirements at December 31, 2020 and is expected to be applied on a retrospective basis. The Company does not expect the adoption of this new guidance to have a material impact on its consolidated financial statements. 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, however, early adoption is permitted. The Company is currently evaluating the timing and impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	year ended December 31, 2019 Canadian Natural Gas Pipelines U.S. Mexico Natural Gas Pipelines Liquids Power and Storage Corporate 1 Total (millions of Canadian $) Revenues 4,010 4,978 603 2,879 785 — 13,255 Intersegment revenues — 164 — — 19 (183 ) 2 — 4,010 5,142 603 2,879 804 (183 ) 13,255 Income/(loss) from equity investments 12 264 56 70 571 (53 ) 3 920 Plant operating costs and other (1,473 ) (1,581 ) (54 ) (728 ) (239 ) 166 2 (3,909 ) Commodity purchases resold — — — — (369 ) — (369 ) Property taxes (275 ) (345 ) — (101 ) (6 ) — (727 ) Depreciation and amortization (1,159 ) (754 ) (115 ) (341 ) (95 ) — (2,464 ) Gain/(loss) on assets held for sale/sold — 21 — 69 (211 ) — (121 ) Segmented earnings/(losses) 1,115 2,747 490 1,848 455 (70 ) 6,585 Interest expense (2,333 ) Allowance for funds used during construction 475 Interest income and other 3 460 Income before income taxes 5,187 Income tax expense (754 ) Net income 4,433 Net income attributable to non-controlling interests (293 ) Net income attributable to controlling interests 4,140 Preferred share dividends (164 ) Net income attributable to common shares 3,976 Capital spending Capital expenditures 3,900 2,500 323 239 481 32 7,475 Capital projects in development 6 — — 701 — — 707 Contributions to equity investments — 16 34 14 538 — 602 3,906 2,516 357 954 1,019 32 8,784 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income/(loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange losses on the peso-denominated loans from affiliates which are fully offset in Interest income and other. Refer to Note 10, Equity investments, for additional information. year ended December 31, 2018 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Power and Storage Corporate 1 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 ) (313 ) 159 2 (3,591 ) Commodity purchases resold — — — — (1,488 ) — (1,488 ) 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 ) 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 other 3 (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 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains on the peso-denominated loans from affiliates which are fully offset in Interest income and other. Refer to Note 10, Equity investments, for additional information. year ended December 31, 2017 Canadian Natural Gas Pipelines U.S. Natural Gas Pipelines Mexico Natural Gas Pipelines Liquids Power and Storage Corporate 1 Total (millions of Canadian $) Revenues 3,693 3,584 570 2,009 3,593 — 13,449 Intersegment revenues — 51 — — — (51 ) 2 — 3,693 3,635 570 2,009 3,593 (51 ) 13,449 Income/(loss) from equity investments 11 240 (9 ) (3 ) 471 63 3 773 Plant operating costs and other (1,300 ) (1,340 ) (42 ) (623 ) (550 ) (51 ) 2 (3,906 ) Commodity purchases resold — — — — (2,382 ) — (2,382 ) Property taxes (260 ) (181 ) — (89 ) (39 ) — (569 ) Depreciation and amortization (908 ) (594 ) (93 ) (309 ) (151 ) — (2,055 ) Goodwill and other asset impairment charges — — — (1,236 ) (21 ) — (1,257 ) Gain on sale of assets — — — — 631 — 631 Segmented earnings/(losses) 1,236 1,760 426 (251 ) 1,552 (39 ) 4,684 Interest expense (2,069 ) Allowance for funds used during construction 507 Interest income and other 3 184 Income before income taxes 3,306 Income tax recovery 89 Net income 3,395 Net income attributable to non-controlling interests (238 ) Net income attributable to controlling interests 3,157 Preferred share dividends (160 ) Net income attributable to common shares 2,997 Capital spending Capital expenditures 2,106 3,712 833 341 350 41 7,383 Capital projects in development 75 — — 71 — — 146 Contributions to equity investments — 118 1,121 117 325 — 1,681 2,181 3,830 1,954 529 675 41 9,210 1 Includes intersegment eliminations. 2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. 3 Income/(loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains on the peso-denominated loans from affiliates which are fully offset in Interest income and other. Refer to Note 10, Equity investments, for additional information. at December 31 2019 2018 (millions of Canadian $) Total Assets by segment Canadian Natural Gas Pipelines 21,983 18,407 U.S. Natural Gas Pipelines 41,627 44,115 Mexico Natural Gas Pipelines 7,207 7,058 Liquids Pipelines 15,931 17,352 Power and Storage 7,788 8,475 Corporate 4,743 3,513 99,279 98,920
Revenue from External Customers by Geographic Areas	year ended December 31 2019 2018 2017 (millions of Canadian $) Revenues Canada – domestic 4,059 4,187 3,618 Canada – export 1,035 1,075 1,255 United States 7,558 7,798 8,006 Mexico 603 619 570 13,255 13,679 13,449
Schedule of Long-Lived Assets by Country	at December 31 2019 2018 (millions of Canadian $) Plant, Property and Equipment Canada 23,362 23,226 United States 36,184 37,385 Mexico 5,943 5,892 65,489 66,503

REVENUES (Tables)

REVENUES (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenues	Disaggregation of Revenues year ended December 31, 2019 Canadian U.S. Mexico Liquids Pipelines Power and Storage Total (millions of Canadian $) Revenues from contracts with customers Capacity arrangements and transportation 4,010 4,245 601 2,423 — 11,279 Power generation — — — — 662 662 Natural gas storage and other — 650 2 4 73 729 4,010 4,895 603 2,427 735 12,670 Other revenues 1,2 — 83 — 452 50 585 4,010 4,978 603 2,879 785 13,255 1 Other revenues include income from the Company's marketing activities, financial instruments and lease contracts. These arrangements are not in the scope of the revenue guidance. Refer to Note 9, Leases, and Note 25, Risk management and financial instruments, for additional information on income from lease arrangements and financial instruments, respectively. 2 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income taxes, for additional information. year ended December 31, 2018 Canadian U.S. Mexico 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 revenues 1,2 — 111 — 502 272 885 4,038 4,314 619 2,584 2,124 13,679 1 Other revenues include income from the Company's marketing activities, financial instruments and lease contracts. These arrangements are not in the scope of the revenue guidance. Refer to Note 25, Risk management and financial instruments, for additional information on income from financial instruments. 2 Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income taxes, for additional information.
Contract Balances	Contract Balances at December 31 2019 2018 (millions of Canadian $) Receivables from contracts with customers 1,458 1,684 Contract assets (Note 7) 153 159 Long-term contract assets 1 102 21 Contract liabilities 2 61 11 Long-term contract liabilities (Note 16) 226 121 1 Recorded as part of Intangibles and other assets on the Consolidated balance sheet. 2 Comprised of deferred revenue recorded in Accounts payable and other on the Consolidated balance sheet. During the year ended December 31, 2019 , $6 million ( 2018 – $17 million ) of revenue was recognized that was included in the contract liability at the beginning of the year.

ASSETS HELD FOR SALE (Tables)

ASSETS HELD FOR SALE (Tables)	12 Months Ended
	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
Assets and Liabilities Classified as Held for Sale	At December 31, 2019 , the related assets and liabilities in the Power and Storage segment were classified as held for sale as follows: (millions of Canadian $) Assets held for sale Inventories 11 Other current assets 3 Plant, property and equipment 2,502 Equity investments 276 Intangible and other assets 15 Total assets held for sale 2,807 Liabilities related to assets held for sale Other long-term liabilities 8 Total liabilities related to assets held for sale 1 8 1 Included in Accounts payable and other on the Consolidated balance sheet.

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2019
Other Assets [Abstract]
Schedule of Other Current Assets	at December 31 2019 2018 (millions of Canadian $) Fair value of derivative contracts (Note 25) 190 737 Contract assets (Note 5) 153 159 Prepaid expenses 60 41 Cash provided as collateral 52 55 Regulatory assets (Note 11) 43 83 Other 129 105 627 1,180

PLANT, PROPERTY AND EQUIPMENT (

PLANT, PROPERTY AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of Plant, Property and Equipment	2019 2018 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Canadian Natural Gas Pipelines NGTL System Pipeline 11,556 4,846 6,710 10,764 4,500 6,264 Compression 4,205 1,771 2,434 3,289 1,677 1,612 Metering and other 1,296 609 687 1,247 613 634 17,057 7,226 9,831 15,300 6,790 8,510 Under construction 3,181 — 3,181 2,111 — 2,111 20,238 7,226 13,012 17,411 6,790 10,621 Canadian Mainline Pipeline 10,145 7,109 3,036 10,077 6,777 3,300 Compression 3,867 2,823 1,044 3,642 2,656 986 Metering and other 643 219 424 652 241 411 14,655 10,151 4,504 14,371 9,674 4,697 Under construction 60 — 60 149 — 149 14,715 10,151 4,564 14,520 9,674 4,846 Other Canadian Natural Gas Pipelines 1 Other 1,861 1,455 406 1,842 1,420 422 Under construction 1,276 — 1,276 124 — 124 3,137 1,455 1,682 1,966 1,420 546 38,090 18,832 19,258 33,897 17,884 16,013 U.S. Natural Gas Pipelines Columbia Gas Pipeline 9,708 389 9,319 6,711 251 6,460 Compression 4,094 206 3,888 2,932 132 2,800 Metering and other 3,244 125 3,119 2,884 75 2,809 17,046 720 16,326 12,527 458 12,069 Under construction 425 — 425 4,347 — 4,347 17,471 720 16,751 16,874 458 16,416 ANR Pipeline 1,594 472 1,122 1,600 443 1,157 Compression 2,050 436 1,614 1,978 388 1,590 Metering and other 1,245 355 890 1,217 324 893 4,889 1,263 3,626 4,795 1,155 3,640 Under construction 252 — 252 272 — 272 5,141 1,263 3,878 5,067 1,155 3,912 2019 2018 at December 31 Cost Accumulated Depreciation Net Cost Accumulated Depreciation Net (millions of Canadian $) Other U.S. Natural Gas Pipelines GTN 2,257 969 1,288 2,322 951 1,371 Great Lakes 2,090 1,208 882 2,180 1,251 929 Columbia Gulf 2,597 114 2,483 1,753 74 1,679 Midstream 2 302 42 260 1,212 91 1,121 Other 3 1,228 574 654 1,190 474 716 8,474 2,907 5,567 8,657 2,841 5,816 Under construction 164 — 164 846 — 846 8,638 2,907 5,731 9,503 2,841 6,662 31,250 4,890 26,360 31,444 4,454 26,990 Mexico Natural Gas Pipelines Pipeline 2,988 340 2,648 3,172 301 2,871 Compression 486 54 432 506 41 465 Metering and other 643 124 519 640 91 549 4,117 518 3,599 4,318 433 3,885 Under construction 2,321 — 2,321 1,990 — 1,990 6,438 518 5,920 6,308 433 5,875 Liquids Pipelines Keystone Pipeline System Pipeline 9,378 1,403 7,975 9,780 1,271 8,509 Pumping equipment 1,035 204 831 1,065 184 881 Tanks and other 3,488 556 2,932 3,598 488 3,110 13,901 2,163 11,738 14,443 1,943 12,500 Under construction 47 — 47 18 — 18 13,948 2,163 11,785 14,461 1,943 12,518 Intra-Alberta Pipelines 4 Pipeline 138 2 136 762 22 740 Pumping equipment — — — 104 3 101 Tanks and other 56 2 54 291 8 283 194 4 190 1,157 33 1,124 Under construction — — — 84 — 84 194 4 190 1,241 33 1,208 14,142 2,167 11,975 15,702 1,976 13,726 Power and Storage Natural Gas 5,6 1,256 522 734 2,062 708 1,354 Natural Gas Storage and Other 742 181 561 741 169 572 1,998 703 1,295 2,803 877 1,926 Under construction 6 6 — 6 1,735 — 1,735 2,004 703 1,301 4,538 877 3,661 Corporate 883 208 675 448 210 238 92,807 27,318 65,489 92,337 25,834 66,503 1 Includes Foothills, Ventures LP, Great Lakes Canada and Coastal GasLink . 2 The Company completed the sale of certain Columbia midstream assets on August 1, 2019. Refer to Note 27, Acquisitions and dispositions, for additional information. 3 Includes Portland, North Baja, Tuscarora and Crossroads. 4 The Company completed the sale of an 85 per cent equity interest in Northern Courier on July 17, 2019 and recorded its remaining 15 per cent interest as an equity investment. Refer to Note 10, Equity Investments, and Note 27, Acquisitions and dispositions, for additional information. 5 Includes Grandview, Bécancour and the Alberta cogeneration natural gas-fired facilities at December 31, 2019. 6 The Company completed the sale of the Coolidge generating station on May 21, 2019. Refer to Note 27, Acquisition and dispositions, for additional information. At July 30, 2019, the cost and accumulated depreciation of the Halton Hills and Napanee power plants were reclassified as Assets held for sale. Refer to Note 6, Assets held for sale, for additional information.

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Impact of New Lease Guidance on Date of Adoption	The following table illustrates the impact of the adoption of the new lease guidance on the Company's previously reported Consolidated balance sheet line items: (millions of Canadian $) As reported December 31, 2018 Adjustment January 1, 2019 Plant, property and equipment 66,503 585 67,088 Accounts payable and other 5,408 57 5,465 Other long-term liabilities 1,008 528 1,536
Operating Lease Cost and Other Information	Operating lease cost is as follows: year ended December 31 (millions of Canadian $) 2019 Operating lease cost 1 117 Sublease income (11 ) Net operating lease cost 106 1 Includes short-term leases and variable lease costs. Other information related to operating leases is noted in the following tables: year ended December 31 (millions of Canadian $) 2019 Cash paid for amounts included in the measurement of operating lease liabilities 76 ROU assets obtained in exchange for new operating lease liabilities 9 at December 31 2019 Weighted average remaining lease term 10 years Weighted average discount rate 3.5 %
Schedule of Future Annual Payments	Future payments reported under previous lease guidance for the Company’s operating leases as at December 31, 2018 were as follows: (millions of Canadian $) Minimum operating lease payments 2019 81 2020 78 2021 76 2022 69 2023 67 Thereafter 390 761
Maturities of Operating Lease Liabilities	Maturities of operating lease liabilities and where they are disclosed on the Consolidated balance sheet as at December 31, 2019 are as follows: (millions of Canadian $) 2020 73 2021 69 2022 59 2023 58 2024 57 Thereafter 323 Total operating lease payments 639 Imputed interest (107 ) Operating lease liabilities 532
Future Lease Payments to be Received Under Operating Leases	Future lease payments to be received under operating leases as at December 31, 2019 are as follows: (millions of Canadian $) Future lease payments 2020 123 2021 116 2022 111 2023 109 2024 109 Thereafter 164 732

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Investments	(millions of Canadian $) Ownership Income/(Loss) from Equity Investments Equity Investments year ended December 31 at December 31 2019 2018 2017 2019 2018 Canadian Natural Gas Pipelines TQM 50.0 % 12 12 11 79 71 U.S. Natural Gas Pipelines Northern Border 1 50.0 % 91 87 87 549 677 Millennium 47.5 % 92 75 66 496 511 Iroquois 2 50.0 % 54 60 59 241 291 Pennant Midstream 3 nil 12 17 11 — 256 Other Various 15 17 17 112 113 Mexico Natural Gas Pipelines Sur de Texas 4 60.0 % 3 27 66 600 627 TransGas nil — — (12 ) — — Liquids Pipelines Grand Rapids 5 50.0 % 56 65 17 1,028 1,028 Northern Courier 6 15.0 % 14 — — 62 — Other 7 Various — (1 ) (20 ) 19 21 Power and Storage Bruce Power 8 48.4 % 527 311 434 3,256 3,166 Portlands Energy Centre 9 50.0 % 35 36 31 — 289 TransCanada Turbines 50.0 % 9 8 6 64 63 920 714 773 6,506 7,113 1 At December 31, 2019 , the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company was US$116 million ( 2018 – US$115 million ) due mainly to the fair value assessment of assets at the time of acquisition. 2 At December 31, 2019 , the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$40 million ( 2018 – US$41 million ) due mainly to the fair value assessment of the assets at the time of acquisitions. 3 On August 1, 2019, TC Energy completed the sale of certain Columbia midstream assets, including the Company's investment in Pennant Midstream, to a third party. Refer to Note 27, Acquisitions and dispositions, for additional information. 4 TC Energy has a 60 per cent ownership interest in Sur de Texas which, 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. Sur de Texas was placed into service in September 2019. 5 At December 31, 2019 , the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $101 million ( 2018 – $102 million ) due mainly to interest capitalized during construction and the fair value of guarantees. Grand Rapids was placed in service in August 2017. 6 On July 17, 2019, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier, and it now applies 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, 2019 , the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Courier was $62 million due mainly to the fair value of guarantees and the fair value assessment of assets at the time of partial monetization. 7 Includes investments in HoustonLink Pipeline Company LLC and Canaport Energy East Marine Terminal Limited Partnership. At December 31, 2019 and 2018, the Canaport Energy East Marine Terminal Limited Partnership investment was nil . 8 At December 31, 2019 , the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $829 million ( 2018 – $870 million ) due mainly to capitalized interest and the fair value assessment of assets at the time of acquisitions. 9 Investment in Portlands Energy Centre was reclassed to Assets held for sale following an agreement effective July 30, 2019 to sell the investment to a third party. Refer to Note 6, Assets held for sale, for additional information. 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 ( 2018 – $73 million ) due mainly to capitalized interest.
Summarized Financial Information of Equity Investments	Summarized Financial Information of Equity Investments year ended December 31 2019 2018 2017 (millions of Canadian $) Income Revenues 5,693 4,836 4,913 Operating and other expenses (3,408 ) (3,545 ) (2,993 ) Net income 1,990 1,515 1,636 Net income attributable to TC Energy 920 714 773 at December 31 2019 2018 (millions of Canadian $) Balance Sheet Current assets 2,305 2,209 Non-current assets 21,865 20,647 Current liabilities (2,060 ) (2,049 ) Non-current liabilities (11,461 ) (9,042 )

RATE-REGULATED BUSINESSES (Tabl

RATE-REGULATED BUSINESSES (Tables)	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	at December 31 2019 2018 Remaining (millions of Canadian $) Regulatory Assets Deferred income taxes 1 1,088 1,051 n/a Operating and debt-service regulatory assets 2 2 12 1 Pensions and other post-retirement benefits 1,3 417 379 n/a Foreign exchange on long-term debt 1,4 16 46 1-10 Other 107 143 n/a 1,630 1,631 Less: Current portion included in Other current assets (Note 7) 43 83 1,587 1,548 Regulatory Liabilities Operating and debt-service regulatory liabilities 2 139 96 1 Pensions and other post-retirement benefits 3 35 53 n/a ANR related post-employment and retirement benefits other than pension 5 41 54 n/a Long-term adjustment account 6 660 1,015 1-47 Bridging amortization account 6 428 305 11 Pipeline abandonment trust balance 7 1,462 1,113 n/a Cost of removal 8 253 261 n/a Deferred income taxes 1 151 165 n/a Deferred income taxes – U.S. Tax Reform 9 1,239 1,394 n/a Other 60 65 n/a 4,468 4,521 Less: Current portion included in Accounts payable and other (Note 15) 696 591 3,772 3,930 1 These regulatory assets or liabilities are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets or liabilities are not included in rate base and do not yield a return on investment during the recovery period. 2 Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances to be included in determination of tolls in the following year. 3 These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from or refunded to customers in future rates. 4 Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. 5 This balance represents the amount ANR estimates it 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, $11 million ( US$8 million ) of the regulatory liability balance at December 31, 2018 (which accumulated between January 2007 and July 2016) was fully amortized at July 31, 2019. The remaining $41 million ( US$32 million ) balance at December 31, 2019 which was accumulated prior to 2007 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period cannot be determined at this time. 6 These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll stabilization adjustments during the 2015-2030 settlement term. The 2019 LTAA balance of $ 660 million consists of $ 488 million to be amortized in 2020 with the remaining balance to be amortized over 47 years . 7 This balance represents the amounts collected in tolls from shippers, and are included in the LMCI restricted investments, to fund future abandonment of the Company's CER-regulated pipeline facilities. 8 This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated operations for future costs to be incurred. 9 These 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. Refer to Note 17, Income taxes, for additional information on U.S. Tax Reform.

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2018 13,084 Tuscarora impairment charge (79 ) Foreign exchange rate changes 1,173 Balance at December 31, 2018 14,178 Sale of Columbia midstream assets (595 ) Foreign exchange rate changes (696 ) Balance at December 31, 2019 12,887

INTANGIBLE AND OTHER ASSETS (Ta

INTANGIBLE AND OTHER ASSETS (Tables)	12 Months Ended
	Dec. 31, 2019
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Schedule of Other Assets	at December 31 2019 2018 (millions of Canadian $) Capital projects in development 1,715 1,051 Employee post-retirement benefits (Note 24) 162 192 Deferred income tax assets (Note 17) 37 322 Fair value of derivative contracts (Note 25) 7 61 Other 247 295 2,168 1,921

NOTES PAYABLE (Tables)

NOTES PAYABLE (Tables)	12 Months Ended
	Dec. 31, 2019
Short-term Debt [Abstract]
Schedule of Notes Payable	2019 2018 (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 Canada 1 4,034 2.1 % 2,117 2.5 % U.S. (2019 – nil; 2018 – US$448) — — 611 3.1 % Mexico (2019 – US$205; 2018 – US$25) 2 266 2.7 % 34 3.3 % 4,300 2,762 1 At December 31, 2019, Notes payable consisted of Canadian dollar denominated notes of $1,353 million (2018 - $961 million ) and U.S. dollar denominated notes of US$2,068 million (2018 - US$847 million ). 2 The demand senior unsecured revolving credit facility for the Company's Mexico subsidiary can be drawn in either Mexican pesos or U.S. dollars, up to the total facility amount of MXN 5.0 billion or the equivalent in U.S. dollars.
Schedule of Credit Facilities	These unsecured credit facilities included the following: at December 31 (billions of Canadian $, unless otherwise noted) 2019 2018 Borrower Description Matures Total Facilities Unused Capacity Total Facilities Committed, syndicated, revolving, extendible, senior unsecured credit facilities 1 : TCPL Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes December 2024 3.0 3.0 3.0 TCPL/TCPL USA/Columbia/TAIL 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 2020 US 4.5 US 4.5 US 4.5 TCPL/TCPL USA/Columbia/TAIL For general corporate purposes of the borrowers, guaranteed by TCPL December 2022 US 1.0 US 1.0 US 1.0 Demand senior unsecured revolving credit facilities 1 : 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 2 For Mexico general corporate purposes, guaranteed by TCPL Demand MXN 5.0 MXN 1.1 MXN 5.0 1 Provisions of various credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and preferred shares. These credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial ratios. At December 31, 2019, the Company was in compliance with all debt covenants. 2 The demand senior unsecured revolving credit facility for the Company's Mexico subsidiary can be drawn in either Mexican pesos or U.S. dollars, up to the total facility amount of MXN 5.0 billion or the equivalent in U.S. dollars.

ACCOUNTS PAYABLE AND OTHER (Tab

ACCOUNTS PAYABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
Schedule of Accounts Payable and Other	at December 31 2019 2018 (millions of Canadian $) Trade payables 3,314 3,224 Regulatory liabilities (Note 11) 696 591 Fair value of derivative contracts (Note 25) 115 922 Unredeemed shares of Columbia Pipeline Group, Inc. — 357 Other 419 314 4,544 5,408

OTHER LONG-TERM LIABILITIES (Ta

OTHER LONG-TERM LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2019
Deferred Costs, Noncurrent [Abstract]
Schedule of Other Long-Term Liabilities	at December 31 2019 2018 (millions of Canadian $) Employee post-retirement benefits (Note 24) 540 569 Operating lease obligations (Note 9) 476 — Long-term contract liabilities (Note 5) 226 121 Fair value of derivative contracts (Note 25) 81 42 Asset retirement obligations 62 90 Guarantees 32 12 Other 197 174 1,614 1,008

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	year ended December 31 2019 2018 2017 (millions of Canadian $) Current Canada 84 65 113 Foreign 1 615 250 36 699 315 149 Deferred Canada (29 ) 49 (185 ) Foreign 84 235 751 Foreign – U.S. Tax Reform and 2018 FERC Actions — (167 ) (804 ) 55 117 (238 ) Income Tax Expense/(Recovery) 754 432 (89 ) 1 The December 31, 2019 current foreign Income tax expense mainly relates to the Columbian midstream sale that closed on August 1, 2019. Refer to Note 27, Acquisitions and dispositions, for additional information.
Schedule of Geographic Components of Income	year ended December 31 2019 2018 2017 (millions of Canadian $) Canada 1,144 433 (339 ) Foreign 4,043 3,516 3,645 Income before Income Taxes 5,187 3,949 3,306
Reconciliation of Income Tax Expense	year ended December 31 2019 2018 2017 (millions of Canadian $) Income before income taxes 5,187 3,949 3,306 Federal and provincial statutory tax rate 26.5 % 27.0 % 27.0 % Expected income tax expense 1,375 1,066 893 Valuation allowance release (259 ) — — Foreign income tax rate differentials (206 ) (432 ) (81 ) Income tax differential related to regulated operations (159 ) (54 ) (42 ) (Income)/loss from non-controlling interests (78 ) 50 (64 ) Alberta tax rate reduction (32 ) — — Non-taxable portion of capital gains (28 ) (11 ) (42 ) Non-deductible goodwill on the Columbia midstream disposition 154 — — U.S. Tax Reform and 2018 FERC Actions — (167 ) (804 ) Asset impairment charges — — 34 Non-deductible amounts — — 4 Other (13 ) (20 ) 13 Income Tax Expense/(Recovery) 754 432 (89 )
Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet	at December 31 2019 2018 (millions of Canadian $) Deferred Income Tax Assets Tax loss and credit carryforwards 1,046 1,238 Regulatory and other deferred amounts 692 858 Difference in accounting and tax bases of impaired assets and assets held for sale 538 574 Unrealized foreign exchange losses on long-term debt 260 491 Financial instruments 23 — Other 70 292 2,629 3,453 Less: Valuation allowance 673 1,159 1,956 2,294 Deferred Income Tax Liabilities Difference in accounting and tax bases of plant, property and equipment and PPAs 6,197 6,449 Equity investments 1,087 1,069 Taxes on future revenue requirement 232 300 Other 106 180 7,622 7,998 Net Deferred Income Tax Liabilities 5,666 5,704 The above deferred tax amounts have been classified on the Consolidated balance sheet as follows: at December 31 2019 2018 (millions of Canadian $) Deferred Income Tax Assets Intangible and other assets (Note 13) 37 322 Deferred Income Tax Liabilities Deferred income tax liabilities 5,703 6,026 Net Deferred Income Tax Liabilities 5,666 5,704
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 2019 2018 2017 (millions of Canadian $) Unrecognized tax benefit at beginning of year 19 15 18 Gross increases – tax positions in prior years 13 13 — Gross decreases – tax positions in prior years (1 ) (5 ) (1 ) Gross increases – tax positions in current year — — 2 Lapse of statutes of limitations (2 ) (4 ) (4 ) Unrecognized Tax Benefit at End of Year 29 19 15

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	The Company issued long-term debt over the three years ended December 31, 2019 as follows: (millions of Canadian $, unless otherwise noted) Company Issue Date Type Maturity Date Amount Interest Rate TRANSCANADA PIPELINES LIMITED September 2019 Medium Term Notes September 2029 700 3.00 % September 2019 Medium Term Notes July 2048 300 4.18 % 1 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 % 2 July 2018 Medium Term Notes July 2048 800 4.18 % July 2018 Medium Term Notes March 2028 200 3.39 % 3 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 % November 2017 Senior Unsecured Notes November 2019 US 550 Floating November 2017 Senior Unsecured Notes November 2019 US 700 2.125 % September 2017 Medium Term Notes March 2028 300 3.39 % September 2017 Medium Term Notes September 2047 700 4.33 % NORTHERN COURIER PIPELINE LIMITED PARTNERSHIP 4,5 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 PORTLAND NATURAL GAS TRANSMISSION SYSTEM April 2018 Unsecured Loan Facility April 2023 US 19 Floating TUSCARORA GAS TRANSMISSION COMPANY August 2017 Unsecured Term Loan August 2020 US 25 Floating TC PIPELINES, LP May 2017 Senior Unsecured Notes May 2027 US 500 3.90 % 1 Reflects coupon rate on re-opening of a pre-existing medium-term notes (MTN) issue. The MTNs were issued at a premium to par, resulting in a re-issuance yield of 3.991 per cent . 2 Reflects 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 . 3 Reflects 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 . 4 Principal and interest payments are made semi-annually over the life of the senior secured notes. 5 Subsequent to the debt issuance, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier. The Company's remaining 15 per cent interest is accounted for using the equity method. Refer to Note 27, Acquisitions and dispositions, for additional information. 2019 2018 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED Debentures Canadian 2020 250 11.8 % 350 11.4 % U.S. (2019 and 2018 – US$400) 2021 518 9.9 % 546 9.9 % Medium Term Notes Canadian 2021 to 2049 9,491 4.6 % 7,504 4.8 % Senior Unsecured Notes U.S. (2019 – US$14,792; 2018 – US$17,192) 2020 to 2049 19,174 5.2 % 23,456 5.1 % 29,433 31,856 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian 2024 100 9.9 % 100 9.9 % U.S. (2019 and 2018 – US$200) 2023 259 7.9 % 273 7.9 % Medium Term Notes Canadian 2025 to 2030 504 7.4 % 504 7.4 % U.S. (2019 and 2018 – US$33) 2026 42 7.5 % 44 7.5 % 905 921 COLUMBIA PIPELINE GROUP, INC. Senior Unsecured Notes U.S. (2019 and 2018 – US$2,250) 2 2020 to 2045 2,916 4.4 % 3,070 4.4 % TC PIPELINES, LP Unsecured Loan Facility U.S. (2019 – nil; 2018 – US$40) — — 55 3.8 % Unsecured Term Loan U.S. (2019 – US$450; 2018 – US$500) 2022 583 2.9 % 682 3.6 % Senior Unsecured Notes U.S. (2019 and 2018 – US$1,200) 2021 to 2027 1,556 4.4 % 1,637 4.4 % 2,139 2,374 ANR PIPELINE COMPANY Senior Unsecured Notes U.S. (2019 and 2018 – US$672) 2021 to 2026 872 7.2 % 918 7.2 % 2019 2018 Outstanding amounts Maturity Dates Outstanding at December 31 Interest Rate 1 Outstanding at December 31 Interest Rate 1 (millions of Canadian $, unless otherwise noted) GAS TRANSMISSION NORTHWEST LLC Unsecured Term Loan U.S. (2019 – nil; 2018 – US$35) — — 48 3.3 % Senior Unsecured Notes U.S. (2019 and 2018 – US$250) 2020 to 2035 324 5.6 % 341 5.6 % 324 389 GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP Senior Unsecured Notes U.S. (2019 – US$219; 2018 – US$240) 2021 to 2030 284 7.7 % 327 7.7 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM Unsecured Loan Facility U.S. (2019 – US$39; 2018 – US$19) 2023 51 3.0 % 26 3.6 % TUSCARORA GAS TRANSMISSION COMPANY Unsecured Term Loan U.S. (2019 – US$23; 2018 – US$24) 2020 30 2.8 % 33 3.5 % NORTH BAJA PIPELINE, LLC Unsecured Term Loan U.S. (2019 and 2018 – US$50) 2021 65 2.8 % 68 3.5 % 37,019 39,982 Current portion of long-term debt (2,705 ) (3,462 ) Unamortized debt discount and issue costs (228 ) (241 ) Fair value adjustments 3 194 230 34,280 36,509 1 Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. The effective interest rate is calculated by discounting the expected future interest payments, adjusted for loan fees, premiums and discounts. Weighted average and effective interest rates are stated as at the respective outstanding dates. 2 Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia’s obligations is required to comply with covenants under the debt indenture and in the event of default, the guarantors would be obligated to pay the principal and related interest. 3 The fair value adjustments include $ 193 million (2018 – $ 232 million) related to the acquisition of Columbia. These adjustments also include an increase of $ 1 million (2018 – decrease of $ 2 million) related to hedged interest rate risk. Refer to Note 25, Risk management and financial instruments, for additional information.
Schedule of Repayments of Long-Term Debt	At December 31, 2019 , principal repayments for the next five years on the Company's long-term debt are approximately as follows: (millions of Canadian $) 2020 2021 2022 2023 2024 Principal repayments on long-term debt 2,705 1,966 1,932 1,897 289
Schedule of Retired Long-Term Debt	The Company retired/repaid long-term debt over the three years ended December 31, 2019 as follows: (millions of Canadian $, unless otherwise noted) Company Retirement/Repayment Date Type Amount Interest Rate TRANSCANADA PIPELINES LIMITED November 2019 Senior Unsecured Notes US 700 2.125 % November 2019 Senior Unsecured Notes US 550 Floating May 2019 Medium Term Notes 13 9.35 % March 2019 Debentures 100 10.50 % January 2019 Senior Unsecured Notes US 750 7.125 % January 2019 Senior Unsecured Notes US 400 3.125 % 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 December 2017 Debentures 100 9.80 % November 2017 Senior Unsecured Notes US 1,000 1.625 % June 2017 Acquisition Bridge Facility 1 US 1,513 Floating February 2017 Acquisition Bridge Facility 1 US 500 Floating January 2017 Medium Term Notes 300 5.10 % TC PIPELINES, LP June 2019 Unsecured Term Loan US 50 Floating December 2018 Unsecured Term Loan US 170 Floating GAS TRANSMISSION NORTHWEST LLC May 2019 Unsecured Term Loan US 35 Floating COLUMBIA PIPELINE GROUP, INC. June 2018 Senior Unsecured Notes US 500 2.45 % PORTLAND NATURAL GAS TRANSMISSION SYSTEM May 2018 Senior Secured Notes US 18 5.90 % GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP March 2018 Senior Unsecured Notes US 9 6.73 % TUSCARORA GAS TRANSMISSION COMPANY August 2017 Senior Secured Notes US 12 3.82 % TRANSCANADA PIPELINE USA LTD. June 2017 Acquisition Bridge Facility 1 US 630 Floating April 2017 Acquisition Bridge Facility 1 US 1,070 Floating 1 These facilities were put in place to finance a portion of the Columbia acquisition and were fully retired in 2017.
Schedule of Interest Expense	year ended December 31 2019 2018 2017 (millions of Canadian $) Interest on long-term debt 1,931 1,877 1,794 Interest on junior subordinated notes 427 391 348 Interest on short-term debt 106 73 33 Capitalized interest (186 ) (124 ) (173 ) Amortization and other financial charges 1 55 48 67 2,333 2,265 2,069 1 Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and losses on derivatives used to manage the Company's exposure to changes in interest rates.

JUNIOR SUBORDINATED NOTES (Tabl

JUNIOR SUBORDINATED NOTES (Tables)	12 Months Ended
	Dec. 31, 2019
Junior Subordinated Notes [Abstract]
Schedule of Junior Subordinated Notes	2019 2018 Outstanding loan amount Maturity Outstanding at December 31 Effective Interest Rate 1 Outstanding at December 31 Effective Interest Rate 1 (millions of Canadian $, unless otherwise noted) TRANSCANADA PIPELINES LIMITED 2 US$1,000 notes issued 2007 at 6.35% 3 2067 1,296 5.1 % 1,364 5.6 % US$750 notes issued 2015 at 5.875% 4,5 2075 972 6.0 % 1,024 6.5 % US$1,200 notes issued 2016 at 6.125% 4,5 2076 1,556 6.7 % 1,637 7.2 % US$1,500 notes issued 2017 at 5.55% 4,5 2077 1,944 5.7 % 2,047 6.2 % $1,500 notes issued 2017 at 4.90% 4,5 2077 1,500 5.4 % 1,500 5.5 % US$1,100 notes issued 2019 at 5.75% 4,5 2079 1,426 6.3 % — — 8,694 7,572 Unamortized debt discount and issue costs (80 ) (64 ) 8,614 7,508 1 The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets, adjusted for issue costs and discounts. 2 The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL. 3 In May 2017, Junior subordinated notes of US $1 billion converted from a fixed rate of 6.35 per cent to a floating rate that is reset quarterly to the three-month LIBOR plus 2.21 per cent . 4 The Junior subordinated notes were issued to TransCanada Trust, a financing trust subsidiary wholly-owned by TCPL. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TC Energy's financial statements since TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL. 5 The coupon rate is initially a fixed interest rate for the first 10 years and converts to a floating rate thereafter.

NON-CONTROLLING INTERESTS (Tabl

NON-CONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2019
Noncontrolling Interest [Abstract]
Schedule of Non-Controlling Interests	The Company's Non-controlling interests included on the Consolidated balance sheet are as follows: at December 31 2019 2018 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 1,634 1,655 The Company's Net income/(loss) attributable to non-controlling interests included in the Consolidated statement of income are as follows: year ended December 31 2019 2018 2017 (millions of Canadian $) Non-controlling interest in TC PipeLines, LP 293 (185 ) 220 Non-controlling interest in Portland Natural Gas Transmission System 1 — — 9 Non-controlling interest in Columbia Pipeline Partners LP 2 — — 9 293 (185 ) 238 1 Non-controlling interest in 2017 for the period January to May when TC Energy sold its remaining interest in Portland to TC PipeLines, LP. 2 Non-controlling interest up to the February 17, 2017 acquisition of all publicly held common units of Columbia Pipeline Partners LP.

COMMON SHARES (Tables)

COMMON SHARES (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2017 863,759 20,099 Dividend reinvestment and share purchase plan 12,824 790 At-the-market equity issuance program 1 3,462 216 Exercise of options 1,331 62 Outstanding at December 31, 2017 881,376 21,167 At-the-market equity issuance program 1 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 1 Net of issue costs and deferred income taxes.
Schedule of Weighted Average Shares	Weighted Average Common Shares Outstanding (millions) 2019 2018 2017 Basic 929 902 872 Diluted 931 903 874
Schedule of Stock Options Activity	Number of (thousands) Weighted Average Exercise Prices Weighted Average Remaining Contractual Life (years) Options outstanding at January 1, 2019 12,404 $52.83 Options granted 2,004 $56.90 Options exercised (5,138 ) $49.08 Options forfeited/expired (176 ) $56.69 Options Outstanding at December 31, 2019 9,094 $55.77 4.1 Options Exercisable at December 31, 2019 5,110 $54.28 3.0
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 2019 2018 2017 Weighted average fair value $6.37 $5.80 $7.22 Expected life (years) 1 5.7 5.7 5.7 Interest rate 1.9 % 2.1 % 1.2 % Volatility 2 19 % 16 % 18 % Dividend yield 5.0 % 4.2 % 3.6 % 1 Expected life is based on historical exercise activity. 2 Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.
Schedule of Additional Option Information	The following table summarizes additional stock option information: year ended December 31 2019 2018 2017 (millions of Canadian $, unless otherwise noted) Total intrinsic value of options exercised 75 10 28 Total fair value of options that have vested 143 101 140 Total options vested 2.1 million 2.1 million 2.3 million

PREFERRED SHARES (Tables)

PREFERRED SHARES (Tables)	12 Months Ended
	Dec. 31, 2019
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Schedule of Preferred Shares	at December 31, 2019 Number of Shares Outstanding Current Yield Annual Dividend Per Share 1,2 Redemption Price Per Share Redemption and Conversion Option Date Right to Convert Into Carrying Value December 31 2019 2018 2017 (thousands) (millions of Canadian $) 3 Cumulative First Preferred Shares Series 1 14,577 3.479 % $0.86975 $25.00 December 31, 2024 Series 2 360 233 233 Series 2 7,423 Floating 4 Floating $25.00 December 31, 2024 Series 1 179 306 306 Series 3 8,533 2.152 % $0.538 $25.00 June 30, 2020 Series 4 209 209 209 Series 4 5,467 Floating 4 Floating $25.00 June 30, 2020 Series 3 134 134 134 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 % 5 $0.975752 $25.00 April 30, 2024 Series 8 589 589 589 Series 9 18,000 3.762 % 5 $0.9405 $25.00 October 30, 2024 Series 10 442 442 442 Series 11 10,000 3.80 % $0.95 $25.00 November 30, 2020 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 1 Each of the even-numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per share at an annualized rate equal to the 90 -day Government of Canada Treasury bill rate (T-bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4), 1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10), 2.96 per cent (Series 12), 4.69 per cent (Series 14) and 3.85 per cent (Series 16). These rates reset quarterly with the then current T-Bill rate. 2 The odd-numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then five -year Government of Canada bond yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), 2.96 per cent (Series 11), 4.69 per cent , subject to a minimum of 5.50 per cent (Series 13) and 3.85 per cent , subject to a minimum of 4.90 per cent (Series 15). 3 Net of underwriting commissions and deferred income taxes. 4 The floating quarterly dividend rate for the Series 2 preferred shares is 3.572 per cent for the period starting December 31, 2019 to, but excluding, March 30, 2020. The floating quarterly dividend rate for the Series 4 preferred shares is 2.932 per cent for the period starting December 31, 2019 to, but excluding, March 30, 2020. The floating quarterly dividend rate for the Series 6 preferred shares is 3.164 per cent for the period starting October 30, 2019 to, but excluding, January 30, 2020. These rates will reset each quarter going forward. 5 No Series 7 or 9 preferred shares were converted on the April 30, 2019 or October 30, 2019 conversion option dates, respectively. As a result, 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.

OTHER COMPREHENSIVE (LOSS)_IN_2

OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Components of Other Comprehensive (Loss)/Income	Components of OCI, including the portion attributable to non-controlling interests and related tax effects, are as follows: 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 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 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 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 year ended December 31, 2017 Before Tax Amount Income Tax Recovery/(Expense) Net of Tax Amount (millions of Canadian $) Foreign currency translation losses on net investment in foreign operations (746 ) (3 ) (749 ) Reclassification of foreign currency translation gains on disposal of foreign operations (77 ) — (77 ) Change in fair value of cash flow hedges 3 — 3 Reclassification to net income of gains and losses on cash flow hedges (3 ) 1 (2 ) Unrealized actuarial gains and losses on pension and other post-retirement benefit plans (14 ) 3 (11 ) Reclassification of actuarial gains and losses on pension and other post-retirement benefit plans 21 (5 ) 16 Other comprehensive loss on equity investments (141 ) 35 (106 ) Other Comprehensive Loss (957 ) 31 (926 )
Schedule of Changes in Accumulated Other Comprehensive Income	The changes in AOCI by component are as follows: Currency Translation Adjustments Cash Flow Hedges Pension and Other Post-Retirement Benefit Plan Adjustments Equity Investments Total 1 AOCI balance at January 1, 2017 (376 ) (28 ) (208 ) (348 ) (960 ) Other comprehensive loss before reclassifications 2,3 (590 ) (1 ) (11 ) (117 ) (719 ) Amounts reclassified from AOCI (77 ) (2 ) 16 11 (52 ) Net current period other comprehensive (loss)/income (667 ) (3 ) 5 (106 ) (771 ) AOCI balance at December 31, 2017 (1,043 ) (31 ) (203 ) (454 ) (1,731 ) Other comprehensive income/(loss) before reclassifications 2 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 reclassifications 2 (824 ) (49 ) (10 ) (86 ) (969 ) Amounts reclassified from AOCI 4,5 (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 ) 1 All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI. 2 In 2019 , other comprehensive loss before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of non-controlling interest losses of $85 million ( 2018 – $166 million gains; 2017 – $159 million losses), $13 million ( 2018 – $1 million losses; 2017 – $4 million gains) and $1 million ( 2018 and 2017 – nil ), respectively. 3 Other comprehensive loss before reclassification on pension and other post-retirement benefit plan adjustments includes a $27 million reduction on settlements and curtailments. 4 Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $18 million ( $13 million , net of tax) at December 31, 2019 . 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. 5 In 2019, non-controlling interest gains related to amounts reclassified from AOCI on cash flow hedges and equity investments was nil .
Schedule of Reclassifications out of Accumulated Other Comprehensive Income	Details about reclassifications out of AOCI into the Consolidated statement of income are as follows: Amounts Reclassified 1 Affected Line Item year ended December 31 2019 2018 2017 (millions of Canadian $) Cash flow hedges Commodities (7 ) (4 ) 20 Revenues (Power and Storage) Interest (12 ) (18 ) (17 ) Interest expense (19 ) (22 ) 3 Total before tax 5 6 (1 ) Income tax expense (14 ) (16 ) 2 Net of tax 1,3 Pension and other post-retirement benefit plan adjustments Amortization of actuarial gains and losses (14 ) (16 ) (15 ) Plant operating costs and other 2 Settlement charge — (4 ) (2 ) Plant operating costs and other 2 (14 ) (20 ) (17 ) Total before tax 4 5 5 Income tax expense (10 ) (15 ) (12 ) Net of tax 1 Equity investments Equity income (8 ) (16 ) (15 ) Income from equity investments 3 4 4 Income tax expense (5 ) (12 ) (11 ) Net of tax 1,3 Currency translation adjustments Realization of foreign currency translation gains on disposal of foreign operations 13 — 77 (Loss)/gain on assets held for sale/sold — — — Income tax expense 13 — 77 Net of tax 1 1 Amounts in parentheses indicate expenses to the Consolidated statement of income. 2 These AOCI components are included in the computation of net benefit cost. Refer to Note 24, Employee post-retirement benefits, for additional information. 3 Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of nil ( 2018 – $5 million ; 2017 – nil ) and nil ( 2018 – $2 million ; 2017 – nil ), respectively.

EMPLOYEE POST-RETIREMENT BENE_2

EMPLOYEE POST-RETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 2017 (millions of Canadian $) DB Plans 122 103 163 Other post-retirement benefit plans 22 23 7 Savings and DC Plans 61 59 42 205 185 212
Schedule of Change in Benefit Obligations, Change in Plan Assets, and Funded Status	The Company's funded status at December 31 is comprised of the following: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2019 2018 2019 2018 Change in Benefit Obligation 1 Benefit obligation – beginning of year 3,653 3,646 430 375 Service cost 126 121 5 4 Interest cost 142 134 17 14 Employee contributions 5 5 — — Benefits paid (213 ) (177 ) (24 ) (23 ) Actuarial loss/(gain) 394 (92 ) 13 43 Settlement — (71 ) — — Foreign exchange rate changes (49 ) 87 (14 ) 17 Benefit obligation – end of year 4,058 3,653 427 430 Change in Plan Assets Plan assets at fair value – beginning of year 3,321 3,451 376 365 Actual return on plan assets 505 (73 ) 52 (15 ) Employer contributions 2 122 103 22 23 Employee contributions 5 5 — — Benefits paid (212 ) (176 ) (24 ) (27 ) Settlement — (71 ) — — Foreign exchange rate changes (48 ) 82 (20 ) 30 Plan assets at fair value – end of year 3,693 3,321 406 376 Funded Status – Plan Deficit (365 ) (332 ) (21 ) (54 ) 1 The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation. 2 Excludes a $12 million letter of credit provided to the Canadian DB Plan for funding purposes ( 2018 – $17 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 are as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2019 2018 2019 2018 Intangible and other assets (Note 13) — — 162 192 Accounts payable and other — (1 ) (8 ) (8 ) Other long-term liabilities (Note 16) (365 ) (331 ) (175 ) (238 ) (365 ) (332 ) (21 ) (54 )
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 are not fully funded: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2019 2018 2019 2018 Projected benefit obligation 1 (4,058 ) (3,653 ) (182 ) (246 ) Plan assets at fair value 3,693 3,321 — — Funded Status – Plan Deficit (365 ) (332 ) (182 ) (246 ) 1 The projected benefit obligation for the pension benefit plans differs from the accumulated benefit obligation in that it includes an assumption with respect to future compensation levels.
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for All DB Plans	The funded status based on the accumulated benefit obligation for all DB Plans is as follows: at December 31 2019 2018 (millions of Canadian $) Accumulated benefit obligation (3,719 ) (3,347 ) Plan assets at fair value 3,693 3,321 Funded Status – Plan Deficit (26 ) (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 plans that are not fully funded. at December 31 2019 2018 (millions of Canadian $) Accumulated benefit obligation (2,397 ) (3,347 ) Plan assets at fair value 2,351 3,321 Funded Status – Plan Deficit (46 ) (26 )
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 Target Allocations at December 31 2019 2018 2019 Debt securities 32 % 33 % 25% to 45% Equity securities 58 % 56 % 40% to 70% Alternatives 10 % 11 % 5% to 15% 100 % 100 %
Schedule of Allocation of Plan Assets, Employer and Related Party Securities	Debt and equity securities include the Company's debt and common shares as follows: at December 31 Percentage of (millions of Canadian $) 2019 2018 2019 2018 Debt securities 9 8 0.2 % 0.3 % Equity securities 15 7 0.4 % 0.2 %
Schedule of Plan Assets for DB Plans and Other Post-Retirement Benefits Measured at Fair Value	The following table presents plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into the three categories based on a fair value hierarchy. For additional information on the fair value hierarchy, refer to Note 25, Risk management and financial instruments. at December 31 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Total Percentage of (millions of Canadian $) 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 Asset Category Cash and Cash Equivalents 58 48 — — — — 58 48 1 1 Equity Securities: Canadian 402 355 189 138 — — 591 493 14 13 U.S. 523 460 156 116 — — 679 576 17 16 International 46 40 320 281 — — 366 321 9 9 Global 136 116 297 268 — — 433 384 11 10 Emerging 8 8 126 138 — — 134 146 3 4 Fixed Income Securities: Canadian Bonds: Federal — — 198 186 — — 198 186 5 5 Provincial — — 246 198 — — 246 198 6 5 Municipal — — 12 8 — — 12 8 — 1 Corporate — — 125 112 — — 125 112 3 3 U.S. Bonds: Federal 421 350 7 — — — 428 350 11 9 State — — — — — — — — — — Municipal — — 1 — — — 1 — — — Corporate 67 145 120 51 — — 187 196 5 5 International: Government 7 6 4 4 — — 11 10 — 1 Corporate — 19 52 18 — — 52 37 1 1 Mortgage backed 46 128 7 — — — 53 128 1 3 Other Investments: Real estate — — — — 196 196 196 196 5 5 Infrastructure — — — — 181 163 181 163 4 4 Private equity funds — — — — 2 3 2 3 — 1 Funds held on deposit 146 142 — — — — 146 142 4 4 1,860 1,817 1,860 1,518 379 362 4,099 3,697 100 100
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, 2017 216 Purchases and sales 127 Realized and unrealized gains 19 Balance at December 31, 2018 362 Purchases and sales 35 Realized and unrealized losses (18 ) Balance at December 31, 2019 379
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 2020 195 25 2021 199 25 2022 203 24 2023 207 24 2024 209 24 2025 to 2029 1,084 117
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 Other Post-Retirement at December 31 2019 2018 2019 2018 Discount rate 3.20 % 3.90 % 3.35 % 4.10 % Rate of compensation increase 3.00 % 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 Other Post-Retirement year ended December 31 2019 2018 2017 2019 2018 2017 Discount rate 3.90 % 3.60 % 3.95 % 4.10 % 3.70 % 4.15 % Expected long-term rate of return on plan assets 6.60 % 6.70 % 6.50 % 4.30 % 4.00 % 6.05 % Rate of compensation increase 3.00 % 3.00 % 1.20 % — — —
Schedule of Effects of a 1% Change in Assumed Health Care Cost Trend Rates	A one per cent change in assumed health care cost trend rates would have the following effects: (millions of Canadian $) Increase Decrease Effect on total of service and interest cost components 2 (2 ) Effect on post-retirement benefit obligation 31 (25 )
Schedule of Net Benefit Costs	The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans is as follows: at December 31 Pension Other Post-Retirement (millions of Canadian $) 2019 2018 2017 2019 2018 2017 Service cost 1 126 121 108 5 4 4 Other components of net benefit cost 1 Interest cost 142 134 122 17 14 14 Expected return on plan assets (222 ) (221 ) (178 ) (15 ) (16 ) (21 ) Amortization of actuarial loss 12 15 14 2 1 1 Amortization of regulatory asset 14 18 37 2 — 1 Settlement charge – regulatory asset — — 2 — — — Settlement charge – AOCI — 4 2 — — — (54 ) (50 ) (1 ) 6 (1 ) (5 ) Net Benefit Cost Recognized 72 71 107 11 3 (1 ) 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: 2019 2018 2017 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 398 20 364 53 273 11
Schedule of the Pre-Tax Amounts Recognized in OCI	Pre-tax amounts recognized in OCI were as follows: 2019 2018 2017 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 (12 ) (2 ) (15 ) (1 ) (18 ) (1 ) Curtailment — — — — (14 ) (2 ) Settlement — — (4 ) — (11 ) — Funded status adjustment 52 (37 ) 110 43 46 (7 ) 40 (39 ) 91 42 3 (10 )

RISK MANAGEMENT AND FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Risk Management and Financial Instruments [Abstract]
Summary of Derivative Instruments	The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows: at December 31 2019 2018 (millions of Canadian $, unless otherwise noted) Notional amount 29,300 (US 22,600) 31,000 (US 22,700) Fair value 33,400 (US 25,700) 31,700 (US 23,200) The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations is as follows: at December 31, 2019 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 492 14 39 — — Sales 1 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 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively. at December 31, 2018 Power Natural Gas Liquids Foreign Exchange Interest Rate Purchases 1 23,865 44 59 — — Sales 1 17,689 56 79 — — Millions of U.S. dollars — — — 3,862 1,650 Maturity dates 2019-2023 2019-2027 2019 2019 2019-2030 1 Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls respectively . The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows: 2019 2018 at December 31 Fair 1,2 Notional Fair 1,2 Notional (millions of Canadian $, unless otherwise noted) U.S. dollar cross-currency interest rate swaps (maturing 2023) 3 3 US 100 (43 ) US 300 U.S. dollar foreign exchange options (maturing 2020 to 2021) 10 US 3,000 (47 ) US 2,500 13 US 3,100 (90 ) US 2,800 1 Fair value equals carrying value. 2 No amounts have been excluded from the assessment of hedge effectiveness. 3 In 2019 , Net income includes net realized gains of nil ( 2018 – gains of $2 million ) related to the interest component of cross-currency swap settlements which are reported within Interest expense.
Schedule of Financial Instruments	The balance sheet classification of the fair value of derivative instruments as at December 31, 2019 is as follows: at December 31, 2019 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 — — — 118 118 Foreign exchange — — 10 61 71 Interest rate — 1 — — 1 — 1 10 179 190 Intangible and other 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) Commodities 2 (4 ) — — (104 ) (108 ) Foreign exchange — — (1 ) (3 ) (4 ) Interest rate (3 ) — — — (3 ) (7 ) — (1 ) (107 ) (115 ) Other long-term liabilities (Note 16) Commodities 2 (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 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. The balance sheet classification of the fair value of derivative instruments as at December 31, 2018 is as follows: at December 31, 2018 Cash Flow Hedges Fair Value Hedges Net Investment Hedges Held for Trading Total Fair Value of Derivative Instruments 1 (millions of Canadian $) Other current assets (Note 7) Commodities 2 1 — — 716 717 Foreign exchange — — 16 1 17 Interest rate 3 — — — 3 4 — 16 717 737 Intangible and other assets (Note 13) Commodities 2 1 — — 50 51 Foreign exchange — — 1 — 1 Interest rate 8 1 — — 9 9 1 1 50 61 Total Derivative Assets 13 1 17 767 798 Accounts payable and other (Note 15) Commodities 2 (4 ) — — (622 ) (626 ) Foreign exchange — — (105 ) (188 ) (293 ) Interest rate — (3 ) — — (3 ) (4 ) (3 ) (105 ) (810 ) (922 ) Other long-term liabilities (Note 16) Commodities 2 — — — (28 ) (28 ) Foreign exchange — — (2 ) — (2 ) Interest rate (11 ) (1 ) — — (12 ) (11 ) (1 ) (2 ) (28 ) (42 ) Total Derivative Liabilities (15 ) (4 ) (107 ) (838 ) (964 ) Total Derivatives (2 ) (3 ) (90 ) (71 ) (166 ) 1 Fair value equals carrying value. 2 Includes purchases and sales of power, natural gas and liquids. 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: 2019 2018 at December 31 Carrying Fair Carrying Fair (millions of Canadian $) Long-term debt, including current portion 1,2 (Note 18) (36,985 ) (43,187 ) (39,971 ) (42,284 ) Junior subordinated notes (Note 19) (8,614 ) (8,777 ) (7,508 ) (6,665 ) (45,599 ) (51,964 ) (47,479 ) (48,949 ) 1 Long-term debt is recorded at amortized cost, except for US$200 million ( 2018 – US$750 million ) that is attributed to hedged risk and recorded at fair value. 2 Net income in 2019 included unrealized losses of $3 million ( 2018 – $2 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 at December 31, 2019 ( 2018 – US$750 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 are classified as available-for-sale assets: 2019 2018 at December 31 LMCI Restricted Investments Other Restricted Investments 1 LMCI Restricted Investments Other Restricted Investments 1 (millions of Canadian $) Fair value of fixed income securities 2 Maturing within 1 year — 6 — 22 Maturing within 1-5 years 26 100 — 110 Maturing within 5-10 years 801 — 140 — Maturing after 10 years 61 — 952 — Fair value of equity securities 2 556 — — — 1,444 106 1,092 132 1 Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. 2 Available-for-sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance sheet.
Unrealized Gain (Loss) on Investments	2019 2018 2017 year ended December 31 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized gains/(losses) 32 3 11 — (3 ) 1 Net realized gains/(losses) 3 60 — (4 ) — (1 ) — 1 Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. 2 Gains and losses on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income. 3 Realized gains and losses on the sale of LMCI restricted investments are determined using the average cost basis.
Realized Gain (Loss) on Investments	2019 2018 2017 year ended December 31 (millions of Canadian $) LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 LMCI restricted investments 1 Other restricted investments 2 Net unrealized gains/(losses) 32 3 11 — (3 ) 1 Net realized gains/(losses) 3 60 — (4 ) — (1 ) — 1 Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities. 2 Gains and losses on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income. 3 Realized gains and losses on the sale of LMCI restricted investments are determined using the average cost basis.
Derivative Instruments - Balance Sheet and Income Statement Information	Derivatives in fair value hedging relationships The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair value hedges included in the carrying amount of the hedged liabilities: at December 31 Carrying amount Fair value hedging adjustments 1 (millions of Canadian $) 2019 2018 2019 2018 Current portion of long-term debt — (748 ) — 3 Long-term debt (260 ) (273 ) (1 ) — (260 ) (1,021 ) (1 ) 3 1 At December 31, 2019 and 2018 , 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 2019 2018 2017 (millions of Canadian $) Derivative instruments held for trading 1 Amount of unrealized (losses)/gains in the year Commodities 2 (111 ) 28 62 Foreign exchange 245 (248 ) 88 Interest rate — — (1 ) Amount of realized gains/(losses) in the year Commodities 378 351 (107 ) Foreign exchange (70 ) (24 ) 18 Interest rate — — 1 Derivative instruments in hedging relationships Amount of realized (losses)/gains in the year Commodities (6 ) (1 ) 23 Foreign exchange — — 5 Interest rate 2 (1 ) 1 1 Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively. 2 In 2019 , 2018 and 2017 , 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 are recorded. year ended December 31 2019 2018 2017 (millions of Canadian $) Fair Value Hedges Interest rate contracts 1 Hedged items (19 ) (71 ) (74 ) Derivatives designated as hedging instruments 1 (4 ) 1 Cash Flow Hedges Reclassification of (losses)/gains on derivative instruments from AOCI to net income 2,3 Interest rate contracts 1 (12 ) (22 ) (17 ) Commodity contracts 4 (7 ) (5 ) 20 1 Presented within Interest expense in the Consolidated statement of income. 2 Refer 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. 3 There are no amounts recognized in earnings that were excluded from effectiveness testing. 4 Presented within Revenues (Power and Storage) in the Consolidated statement of income.
Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships	The components of OCI (Note 23) related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests are as follows: year ended December 31 2019 2018 2017 (millions of Canadian $, pre-tax) Change in fair value of derivative instruments recognized in OCI 1 Commodities (15 ) (1 ) (1 ) Interest rate (63 ) (13 ) 4 (78 ) (14 ) 3 1 No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI.
Schedule of Offsetting Assets	The following tables show the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: at December 31, 2019 Gross Derivative Instruments Amounts Available for Offset 1 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 ) 1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2018 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative instrument assets Commodities 768 (626 ) 142 Foreign exchange 18 (18 ) — Interest rate 12 (4 ) 8 798 (648 ) 150 Derivative instrument liabilities Commodities (654 ) 626 (28 ) Foreign exchange (295 ) 18 (277 ) Interest rate (15 ) 4 (11 ) (964 ) 648 (316 ) 1 Amounts available for offset do not include cash collateral pledged or received.
Schedule of Offsetting Liabilities	The following tables show the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis: at December 31, 2019 Gross Derivative Instruments Amounts Available for Offset 1 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 ) 1 Amounts available for offset do not include cash collateral pledged or received. at December 31, 2018 Gross Derivative Instruments Amounts Available for Offset 1 Net Amounts (millions of Canadian $) Derivative instrument assets Commodities 768 (626 ) 142 Foreign exchange 18 (18 ) — Interest rate 12 (4 ) 8 798 (648 ) 150 Derivative instrument liabilities Commodities (654 ) 626 (28 ) Foreign exchange (295 ) 18 (277 ) Interest rate (15 ) 4 (11 ) (964 ) 648 (316 ) 1 Amounts available for offset do not include cash collateral pledged or received.
Schedule of Fair Value of Assets and Liabilities Measured on a Recurring Basis	The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions, are categorized as follows: at December 31, 2019 Quoted Prices in Active Markets Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 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 1 There were no transfers from Level II to Level III for the year ended December 31, 2019 . at December 31, 2018 Quoted Prices in Active Markets Significant Other Observable Inputs (Level II) 1 Significant Unobservable Inputs 1 Total (millions of Canadian $) Derivative Instrument Assets Commodities 581 187 — 768 Foreign exchange — 18 — 18 Interest rate — 12 — 12 Derivative Instrument Liabilities Commodities (555 ) (95 ) (4 ) (654 ) Foreign exchange — (295 ) — (295 ) Interest rate — (15 ) — (15 ) 26 (188 ) (4 ) (166 ) 1 There were no transfers from Level II to Level III for the year ended December 31, 2018 .
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) 2019 2018 Balance at beginning of year (4 ) (7 ) Transfers out of Level III 4 5 Total (losses)/gains included in Net income (3 ) 8 Total losses included in OCI (4 ) — Settlements — (9 ) Foreign exchange — (1 ) Balance at end of year 1 (7 ) (4 ) 1 Revenues include unrealized losses of $3 million attributed to derivatives in the Level III category that were still held at December 31, 2019 ( 2018 – unrealized losses of $5 million ).

CHANGES IN OPERATING WORKING _2

CHANGES IN OPERATING WORKING CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2019
CHANGES IN OPERATING WORKING CAPITAL
Schedule of changes in operating working capital	year ended December 31 2019 2018 2017 (millions of Canadian $) Decrease/(increase) in Accounts receivable 31 (69 ) (576 ) Increase in Inventories (42 ) (49 ) (38 ) Decrease in Assets held for sale — — 14 (Increase)/decrease in Other current assets (15 ) 45 189 Increase/(decrease) in Accounts payable and other 352 (70 ) 151 (Decrease)/increase in Accrued interest (33 ) 41 12 Decrease in Liabilities related to Assets held for sale — — (25 ) Decrease/(increase) in Operating Working Capital 293 (102 ) (273 )

COMMITMENTS, CONTINGENCIES AN_2

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of Guarantees	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 is as follows: 2019 2018 at December 31 Term Potential Exposure 1 Carrying Value Potential Exposure 1 Carrying Value (millions of Canadian $) Northern Courier pipeline to 2055 300 27 — — Sur de Texas to 2020 109 — 183 1 Bruce Power to 2021 88 — 88 — Other jointly-owned entities to 2059 100 10 104 11 597 37 375 12 1 TC Energy's share of the potential estimated current or contingent exposure.

CORPORATE RESTRUCTURING COSTS (

CORPORATE RESTRUCTURING COSTS (Tables)	12 Months Ended
	Dec. 31, 2019
Restructuring and Related Activities [Abstract]
Restructuring and Related Costs	Changes in the restructuring liability were as follows: (millions of Canadian $) Employee Severance Lease Commitments Total Restructuring liability as at December 31, 2017 9 53 62 Restructuring charges 1 — 42 42 Accretion expense — 1 1 Cash payments (9 ) (15 ) (24 ) Restructuring liability as at December 31, 2018 — 81 81 Accretion expense — 2 2 Cash payments — (14 ) (14 ) Restructuring liability as at December 31, 2019 — 69 69 1 At December 31, 2018 , the Company recorded an additional $21 million in Plant operating costs and other in the Consolidated statement of income and $21 million

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2019
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
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, are as follows: at December 31 (millions of Canadian $) 2019 2018 ASSETS Current Assets Cash and cash equivalents 106 45 Accounts receivable 88 79 Inventories 27 24 Other 8 13 229 161 Plant, Property and Equipment 3,050 3,026 Equity Investments 785 965 Goodwill 431 453 Intangible and Other Assets — 8 4,495 4,613 LIABILITIES Current Liabilities Accounts payable and other 70 88 Accrued interest 21 24 Current portion of long-term debt 187 79 278 191 Regulatory Liabilities 45 43 Other Long-Term Liabilities 9 3 Deferred Income Tax Liabilities 9 13 Long-Term Debt 2,694 3,125 3,035 3,375
Variable Interest Entity, Not Primary Beneficiary
Variable Interest Entity [Line Items]
Schedule of Variable Interest Entities	The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs are as follows: at December 31 (millions of Canadian $) 2019 2018 Balance sheet Equity investments 1 4,720 4,575 Off-balance sheet Potential exposure to guarantees 466 170 Maximum exposure to loss 5,186 4,745 1 Includes equity investment in Portlands Energy Centre classified as Assets held for sale as at December 31, 2019. Refer to Note 6, Assets held for sale, for additional information.

DESCRIPTION OF TC ENERGY'S BU_2

DESCRIPTION OF TC ENERGY'S BUSINESS (Details)	12 Months Ended
	Dec. 31, 2019plantsegmentmikmBcf
Segment Reporting Information [Line Items]
Number of business segments in which the entity operates | segment	5
Canadian Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) | km	40,658
Investments of regulated natural gas pipelines (in miles) | mi	25,264
U.S. Natural Gas Pipelines
Segment Reporting Information [Line Items]
Investments of regulated natural gas pipelines (in kilometers) | km	50,089
Investments of regulated natural gas pipelines (in miles) | mi	31,124
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 | plant	10
Non-regulated natural gas storage facilities (in billion cubic feet) | Bcf	118

ACCOUNTING POLICIES (Details)

ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2019
Employee Post-Retirement Benefits
Moving average period of basis used to determine expected return on plan assets	5 years
Corporate | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	4.00%
Corporate | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	20.00%
Natural Gas Pipelines | Pipeline | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	1.00%
Natural Gas Pipelines | Pipeline | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	7.00%
Midstream | Pipeline | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	1.70%
Midstream | Pipeline | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.50%
Liquids Pipelines | Pipeline | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.00%
Liquids Pipelines | Pipeline | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.50%
Power and Storage | Power generation and natural gas storage plant, equipment and structures | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.00%
Power and Storage | Power generation and natural gas storage plant, equipment and structures | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	20.00%

SEGMENTED INFORMATION (Details)

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Segmented information
Revenues	$ 13,255	$ 13,679	$ 13,449
Income/(loss) from equity investments	920	714	773
Plant operating costs and other	(3,909)	(3,591)	(3,906)
Commodity purchases resold	(369)	(1,488)	(2,382)
Property taxes	(727)	(569)	(569)
Depreciation and amortization	(2,464)	(2,350)	(2,055)
Goodwill and other asset impairment charges	0	(801)	(1,257)
(Loss)/gain on assets held for sale/sold	(121)	170	631
Segmented earnings/(losses)	6,585	5,764	4,684
Interest expense	(2,333)	(2,265)	(2,069)
Allowance for funds used during construction	475	526	507
Interest income and other	460	(76)	184
Income before Income Taxes	5,187	3,949	3,306
Income tax expense/(recovery)	(754)	(432)	89
Net Income	4,433	3,517	3,395
Net loss attributable to non-controlling interests	(293)	185	(238)
Net Income Attributable to Controlling Interests	4,140	3,702	3,157
Preferred share dividends	(164)	(163)	(160)
Net Income Attributable to Common Shares	3,976	3,539	2,997
Capital spending
Capital expenditures	7,475	9,418	7,383
Capital projects in development	707	496	146
Contributions to equity investments	602	1,015	1,681
Capital spending	8,784	10,929	9,210
Assets	99,279	98,920
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	65,489	66,503		$ 67,088
Canada
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	23,362	23,226
Canada – domestic
Segmented information
Revenues	4,059	4,187	3,618
Canada – export
Segmented information
Revenues	1,035	1,075	1,255
United States
Segmented information
Revenues	7,558	7,798	8,006
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	36,184	37,385
Mexico
Segmented information
Revenues	603	619	570
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	5,943	5,892
Corporate
Segmented information
Revenues	(183)	(218)	(51)
Income/(loss) from equity investments	(53)	5	63
Plant operating costs and other	166	159	(51)
Commodity purchases resold	0	0	0
Property taxes	0	0	0
Depreciation and amortization	0	0	0
Goodwill and other asset impairment charges		0	0
(Loss)/gain on assets held for sale/sold	0	0	0
Segmented earnings/(losses)	(70)	(54)	(39)
Capital spending
Capital expenditures	32	45	41
Capital projects in development	0	0	0
Contributions to equity investments	0	0	0
Capital spending	32	45	41
Assets	4,743	3,513
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	675	238
Canadian Natural Gas Pipelines
Segmented information
Revenues	4,010	4,038	3,693
Canadian Natural Gas Pipelines | Operating segments
Segmented information
Revenues	4,010	4,038	3,693
Income/(loss) from equity investments	12	12	11
Plant operating costs and other	(1,473)	(1,405)	(1,300)
Commodity purchases resold	0	0	0
Property taxes	(275)	(266)	(260)
Depreciation and amortization	(1,159)	(1,129)	(908)
Goodwill and other asset impairment charges		0	0
(Loss)/gain on assets held for sale/sold	0	0	0
Segmented earnings/(losses)	1,115	1,250	1,236
Capital spending
Capital expenditures	3,900	2,442	2,106
Capital projects in development	6	36	75
Contributions to equity investments	0	0	0
Capital spending	3,906	2,478	2,181
Assets	21,983	18,407
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	19,258	16,013
Canadian Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues	0	0	0
U.S. Natural Gas Pipelines
Segmented information
Revenues	4,978	4,314	3,584
U.S. Natural Gas Pipelines | Operating segments
Segmented information
Revenues	5,142	4,476	3,635
Income/(loss) from equity investments	264	256	240
Plant operating costs and other	(1,581)	(1,368)	(1,340)
Commodity purchases resold	0	0	0
Property taxes	(345)	(199)	(181)
Depreciation and amortization	(754)	(664)	(594)
Goodwill and other asset impairment charges		(801)	0
(Loss)/gain on assets held for sale/sold	21	0	0
Segmented earnings/(losses)	2,747	1,700	1,760
Capital spending
Capital expenditures	2,500	5,591	3,712
Capital projects in development	0	1	0
Contributions to equity investments	16	179	118
Capital spending	2,516	5,771	3,830
Assets	41,627	44,115
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	26,360	26,990
U.S. Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues	(164)	(162)	(51)
Mexico Natural Gas Pipelines
Segmented information
Revenues	603	619	570
Mexico Natural Gas Pipelines | Operating segments
Segmented information
Revenues	603	619	570
Income/(loss) from equity investments	56	22	(9)
Plant operating costs and other	(54)	(34)	(42)
Commodity purchases resold	0	0	0
Property taxes	0	0	0
Depreciation and amortization	(115)	(97)	(93)
Goodwill and other asset impairment charges		0	0
(Loss)/gain on assets held for sale/sold	0	0	0
Segmented earnings/(losses)	490	510	426
Capital spending
Capital expenditures	323	463	833
Capital projects in development	0	0	0
Contributions to equity investments	34	334	1,121
Capital spending	357	797	1,954
Assets	7,207	7,058
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	5,920	5,875
Mexico Natural Gas Pipelines | Intersegment eliminations
Segmented information
Revenues	0	0	0
Liquids Pipelines
Segmented information
Revenues	2,879	2,584	2,009
Liquids Pipelines | Operating segments
Segmented information
Revenues	2,879	2,584	2,009
Income/(loss) from equity investments	70	64	(3)
Plant operating costs and other	(728)	(630)	(623)
Commodity purchases resold	0	0	0
Property taxes	(101)	(98)	(89)
Depreciation and amortization	(341)	(341)	(309)
Goodwill and other asset impairment charges		0	(1,236)
(Loss)/gain on assets held for sale/sold	69	0	0
Segmented earnings/(losses)	1,848	1,579	(251)
Capital spending
Capital expenditures	239	110	341
Capital projects in development	701	459	71
Contributions to equity investments	14	12	117
Capital spending	954	581	529
Assets	15,931	17,352
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	11,975	13,726
Liquids Pipelines | Intersegment eliminations
Segmented information
Revenues	0	0	0
Power and Storage
Segmented information
Revenues	785	2,124	3,593
Power and Storage | Operating segments
Segmented information
Revenues	804	2,180	3,593
Income/(loss) from equity investments	571	355	471
Plant operating costs and other	(239)	(313)	(550)
Commodity purchases resold	(369)	(1,488)	(2,382)
Property taxes	(6)	(6)	(39)
Depreciation and amortization	(95)	(119)	(151)
Goodwill and other asset impairment charges		0	(21)
(Loss)/gain on assets held for sale/sold	(211)	170	631
Segmented earnings/(losses)	455	779	1,552
Capital spending
Capital expenditures	481	767	350
Capital projects in development	0	0	0
Contributions to equity investments	538	490	325
Capital spending	1,019	1,257	675
Assets	7,788	8,475
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	1,301	3,661
Power and Storage | Intersegment eliminations
Segmented information
Revenues	$ (19)	$ (56)	$ 0

REVENUES - Disaggregation of Re

REVENUES - Disaggregation of Revenues (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 12,670	$ 12,794
Other revenues	585	885
Revenues	13,255	13,679	$ 13,449
Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	11,279	10,280
Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	662	1,771
Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	729	743
Canadian Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,010	4,038
Other revenues	0	0
Revenues	4,010	4,038	3,693
Canadian Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,010	4,038
Canadian Natural Gas Pipelines | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0
Canadian Natural Gas Pipelines | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0
U.S. Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,895	4,203
Other revenues	83	111
Revenues	4,978	4,314	3,584
U.S. Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4,245	3,549
U.S. Natural Gas Pipelines | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0
U.S. Natural Gas Pipelines | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	650	654
Mexico Natural Gas Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	603	619
Other revenues	0	0
Revenues	603	619	570
Mexico Natural Gas Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	601	614
Mexico Natural Gas Pipelines | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0
Mexico Natural Gas Pipelines | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2	5
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,427	2,082
Other revenues	452	502
Revenues	2,879	2,584	2,009
Liquids Pipelines | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	2,423	2,079
Liquids Pipelines | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0
Liquids Pipelines | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	4	3
Power and Storage
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	735	1,852
Other revenues	50	272
Revenues	785	2,124	$ 3,593
Power and Storage | Capacity arrangements and transportation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0
Power and Storage | Power generation
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	662	1,771
Power and Storage | Natural gas storage and other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 73	$ 81

REVENUES - Contract Balances (D

REVENUES - Contract Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers	$ 1,458	$ 1,684
Contract assets (Note 7)	153	159
Long-term contract assets	102	21
Contract liabilities	61	11
Long-term contract liabilities (Note 16)	226	121
Revenue recognized	$ 6	$ 17

REVENUES - Remaining Performanc

REVENUES - Remaining Performance Obligations - Narrative (Details) $ in Millions	Dec. 31, 2019CAD ($)
Long-term pipeline capacity arrangements and transportation contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 26,600
Long-term pipeline capacity arrangements and transportation contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 3,700
Future revenues, expected timing of satisfaction, period	1 year
Natural gas storage and other
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 800
Natural gas storage and other | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future revenues, remaining performance obligation	$ 414
Future revenues, expected timing of satisfaction, period	1 year

REVENUES - Additional Informati

REVENUES - Additional Information - Narrative (Details) $ in Billions	12 Months Ended
	Dec. 31, 2019CAD ($)
Long-term pipeline capacity arrangements and transportation contracts
Disaggregation of Revenue [Line Items]
Future revenues, remaining performance obligation	$ 26.6
Rate-regulated firm capacity contracts
Disaggregation of Revenue [Line Items]
Future revenues, expected timing of satisfaction, explanation	one to three years
Natural gas storage and other
Disaggregation of Revenue [Line Items]
Future revenues, remaining performance obligation	$ 0.8

ASSETS HELD FOR SALE - Narrativ

ASSETS HELD FOR SALE - Narrative (Details) $ in Millions, $ in Millions	Jul. 30, 2019USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale			$ 121	$ (170)	$ (631)
Portlands Energy | Disposal group, not discontinued operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest sold	50.00%
Sale consideration	$ 2,870
Loss on sale			279
Loss on sale, net of tax			$ 194
Portlands Energy | Disposal group, not discontinued operations | Scenario, Forecast
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale		$ 380
Loss on sale, net of tax		$ 280

ASSETS HELD FOR SALE - Assets a

ASSETS HELD FOR SALE - Assets and Liabilities Classified as Held for Sale (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Assets held for sale
Total assets held for sale	$ 2,807	$ 543
Portlands Energy | Power and Storage | Disposal group, not discontinued operations
Assets held for sale
Inventories	11
Other current assets	3
Plant, property and equipment	2,502
Equity investments	276
Intangible and other assets	15
Total assets held for sale	2,807
Liabilities related to assets held for sale
Other long-term liabilities	8
Total liabilities related to assets held for sale	$ 8

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Other Assets [Abstract]
Fair value of derivative contracts (Note 25)	$ 190	$ 737
Contract assets (Note 5)	153	159
Prepaid expenses	60	41
Cash provided as collateral	52	55
Regulatory assets (Note 11)	43	83
Other	129	105
Other current assets, total	$ 627	$ 1,180

PLANT, PROPERTY AND EQUIPMENT_2

PLANT, PROPERTY AND EQUIPMENT (Details) - CAD ($) $ in Millions	Jul. 17, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 05, 2017	Dec. 31, 2019	Dec. 31, 2019	Jan. 01, 2019
Plant, property and equipment
Cost		$ 92,337			$ 92,807	$ 92,807
Accumulated Depreciation		25,834			27,318	27,318
Net Book Value		66,503			65,489	65,489	$ 67,088
Energy East, Eastern Mainline and Upland projects
Plant, property and equipment
Impairment charge				$ 83
Impairment charge, net of tax				$ 64
Power development project
Plant, property and equipment
Impairment charge			$ 21
Impairment charge, net of tax			$ 16
Bison
Plant, property and equipment
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
Plant, property and equipment
Accumulated Depreciation		0			0	0
Operating segments | Canadian Natural Gas Pipelines
Plant, property and equipment
Cost		33,897			38,090	38,090
Accumulated Depreciation		17,884			18,832	18,832
Net Book Value		16,013			19,258	19,258
Operating segments | Canadian Natural Gas Pipelines | NGTL System
Plant, property and equipment
Cost		17,411			20,238	20,238
Accumulated Depreciation		6,790			7,226	7,226
Net Book Value		10,621			13,012	13,012
Operating segments | Canadian Natural Gas Pipelines | Canadian Mainline
Plant, property and equipment
Cost		14,520			14,715	14,715
Accumulated Depreciation		9,674			10,151	10,151
Net Book Value		4,846			4,564	4,564
Operating segments | Canadian Natural Gas Pipelines | Other
Plant, property and equipment
Cost		1,842			1,861	1,861
Accumulated Depreciation		1,420			1,455	1,455
Net Book Value		422			406	406
Operating segments | Canadian Natural Gas Pipelines | Other Natural Gas Pipelines
Plant, property and equipment
Cost		1,966			3,137	3,137
Accumulated Depreciation		1,420			1,455	1,455
Net Book Value		546			1,682	1,682
Operating segments | Canadian Natural Gas Pipelines | Pipeline | NGTL System
Plant, property and equipment
Cost		10,764			11,556	11,556
Accumulated Depreciation		4,500			4,846	4,846
Net Book Value		6,264			6,710	6,710
Operating segments | Canadian Natural Gas Pipelines | Pipeline | Canadian Mainline
Plant, property and equipment
Cost		10,077			10,145	10,145
Accumulated Depreciation		6,777			7,109	7,109
Net Book Value		3,300			3,036	3,036
Operating segments | Canadian Natural Gas Pipelines | Compression | NGTL System
Plant, property and equipment
Cost		3,289			4,205	4,205
Accumulated Depreciation		1,677			1,771	1,771
Net Book Value		1,612			2,434	2,434
Operating segments | Canadian Natural Gas Pipelines | Compression | Canadian Mainline
Plant, property and equipment
Cost		3,642			3,867	3,867
Accumulated Depreciation		2,656			2,823	2,823
Net Book Value		986			1,044	1,044
Operating segments | Canadian Natural Gas Pipelines | Metering and other | NGTL System
Plant, property and equipment
Cost		1,247			1,296	1,296
Accumulated Depreciation		613			609	609
Net Book Value		634			687	687
Operating segments | Canadian Natural Gas Pipelines | Metering and other | Canadian Mainline
Plant, property and equipment
Cost		652			643	643
Accumulated Depreciation		241			219	219
Net Book Value		411			424	424
Operating segments | Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | NGTL System
Plant, property and equipment
Cost		15,300			17,057	17,057
Accumulated Depreciation		6,790			7,226	7,226
Net Book Value		8,510			9,831	9,831
Operating segments | Canadian Natural Gas Pipelines | Property, plant and equipment excluding under construction | Canadian Mainline
Plant, property and equipment
Cost		14,371			14,655	14,655
Accumulated Depreciation		9,674			10,151	10,151
Net Book Value		4,697			4,504	4,504
Operating segments | Canadian Natural Gas Pipelines | Under construction | NGTL System
Plant, property and equipment
Cost		2,111			3,181	3,181
Net Book Value		2,111			3,181	3,181
Operating segments | Canadian Natural Gas Pipelines | Under construction | Canadian Mainline
Plant, property and equipment
Cost		149			60	60
Accumulated Depreciation		0			0	0
Net Book Value		149			60	60
Operating segments | Canadian Natural Gas Pipelines | Under construction | Other Natural Gas Pipelines
Plant, property and equipment
Cost		124			1,276	1,276
Accumulated Depreciation		0			0	0
Net Book Value		124			1,276	1,276
Operating segments | U.S. Natural Gas Pipelines
Plant, property and equipment
Cost		31,444			31,250	31,250
Accumulated Depreciation		4,454			4,890	4,890
Net Book Value		26,990			26,360	26,360
Operating segments | U.S. Natural Gas Pipelines | Other Natural Gas Pipelines
Plant, property and equipment
Cost		9,503			8,638	8,638
Accumulated Depreciation		2,841			2,907	2,907
Net Book Value		6,662			5,731	5,731
Operating segments | U.S. Natural Gas Pipelines | Columbia Gas
Plant, property and equipment
Cost		16,874			17,471	17,471
Accumulated Depreciation		458			720	720
Net Book Value		16,416			16,751	16,751
Operating segments | U.S. Natural Gas Pipelines | ANR
Plant, property and equipment
Cost		5,067			5,141	5,141
Accumulated Depreciation		1,155			1,263	1,263
Net Book Value		3,912			3,878	3,878
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Other
Plant, property and equipment
Cost		1,190			1,228	1,228
Accumulated Depreciation		474			574	574
Net Book Value		716			654	654
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Columbia Gas
Plant, property and equipment
Cost		6,711			9,708	9,708
Accumulated Depreciation		251			389	389
Net Book Value		6,460			9,319	9,319
Operating segments | U.S. Natural Gas Pipelines | Pipeline | ANR
Plant, property and equipment
Cost		1,600			1,594	1,594
Accumulated Depreciation		443			472	472
Net Book Value		1,157			1,122	1,122
Operating segments | U.S. Natural Gas Pipelines | Pipeline | GTN
Plant, property and equipment
Cost		2,322			2,257	2,257
Accumulated Depreciation		951			969	969
Net Book Value		1,371			1,288	1,288
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Great Lakes
Plant, property and equipment
Cost		2,180			2,090	2,090
Accumulated Depreciation		1,251			1,208	1,208
Net Book Value		929			882	882
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Columbia Gulf
Plant, property and equipment
Cost		1,753			2,597	2,597
Accumulated Depreciation		74			114	114
Net Book Value		1,679			2,483	2,483
Operating segments | U.S. Natural Gas Pipelines | Pipeline | Midstream
Plant, property and equipment
Cost		1,212			302	302
Accumulated Depreciation		91			42	42
Net Book Value		1,121			260	260
Operating segments | U.S. Natural Gas Pipelines | Compression | Columbia Gas
Plant, property and equipment
Cost		2,932			4,094	4,094
Accumulated Depreciation		132			206	206
Net Book Value		2,800			3,888	3,888
Operating segments | U.S. Natural Gas Pipelines | Compression | ANR
Plant, property and equipment
Cost		1,978			2,050	2,050
Accumulated Depreciation		388			436	436
Net Book Value		1,590			1,614	1,614
Operating segments | U.S. Natural Gas Pipelines | Metering and other | Columbia Gas
Plant, property and equipment
Cost		2,884			3,244	3,244
Accumulated Depreciation		75			125	125
Net Book Value		2,809			3,119	3,119
Operating segments | U.S. Natural Gas Pipelines | Metering and other | ANR
Plant, property and equipment
Cost		1,217			1,245	1,245
Accumulated Depreciation		324			355	355
Net Book Value		893			890	890
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | Other Natural Gas Pipelines
Plant, property and equipment
Cost		8,657			8,474	8,474
Accumulated Depreciation		2,841			2,907	2,907
Net Book Value		5,816			5,567	5,567
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | Columbia Gas
Plant, property and equipment
Cost		12,527			17,046	17,046
Accumulated Depreciation		458			720	720
Net Book Value		12,069			16,326	16,326
Operating segments | U.S. Natural Gas Pipelines | Property, plant and equipment excluding under construction | ANR
Plant, property and equipment
Cost		4,795			4,889	4,889
Accumulated Depreciation		1,155			1,263	1,263
Net Book Value		3,640			3,626	3,626
Operating segments | U.S. Natural Gas Pipelines | Under construction
Plant, property and equipment
Accumulated Depreciation		0			0	0
Operating segments | U.S. Natural Gas Pipelines | Under construction | Other Natural Gas Pipelines
Plant, property and equipment
Cost		846			164	164
Accumulated Depreciation		0			0	0
Net Book Value		846			164	164
Operating segments | U.S. Natural Gas Pipelines | Under construction | Columbia Gas
Plant, property and equipment
Cost		4,347			425	425
Accumulated Depreciation		0			0	0
Net Book Value		4,347			425	425
Operating segments | U.S. Natural Gas Pipelines | Under construction | ANR
Plant, property and equipment
Cost		272			252	252
Net Book Value		272			252	252
Operating segments | Mexico Natural Gas Pipelines
Plant, property and equipment
Cost		6,308			6,438	6,438
Accumulated Depreciation		433			518	518
Net Book Value		5,875			5,920	5,920
Operating segments | Mexico Natural Gas Pipelines | Pipeline
Plant, property and equipment
Cost		3,172			2,988	2,988
Accumulated Depreciation		301			340	340
Net Book Value		2,871			2,648	2,648
Operating segments | Mexico Natural Gas Pipelines | Compression
Plant, property and equipment
Cost		506			486	486
Accumulated Depreciation		41			54	54
Net Book Value		465			432	432
Operating segments | Mexico Natural Gas Pipelines | Metering and other
Plant, property and equipment
Cost		640			643	643
Accumulated Depreciation		91			124	124
Net Book Value		549			519	519
Operating segments | Mexico Natural Gas Pipelines | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost		4,318			4,117	4,117
Accumulated Depreciation		433			518	518
Net Book Value		3,885			3,599	3,599
Operating segments | Mexico Natural Gas Pipelines | Under construction
Plant, property and equipment
Cost		1,990			2,321	2,321
Accumulated Depreciation		0			0	0
Net Book Value		1,990			2,321	2,321
Operating segments | Liquids Pipelines
Plant, property and equipment
Cost		15,702			14,142	14,142
Accumulated Depreciation		1,976			2,167	2,167
Net Book Value		13,726			11,975	11,975
Operating segments | Liquids Pipelines | Keystone Pipeline System
Plant, property and equipment
Cost		14,461			13,948	13,948
Accumulated Depreciation		1,943			2,163	2,163
Net Book Value		12,518			11,785	11,785
Operating segments | Liquids Pipelines | Intra-Alberta Pipelines
Plant, property and equipment
Cost		1,241			194	194
Accumulated Depreciation		33			4	4
Net Book Value		1,208			190	190
Operating segments | Liquids Pipelines | Pipeline | Keystone Pipeline System
Plant, property and equipment
Cost		9,780			9,378	9,378
Accumulated Depreciation		1,271			1,403	1,403
Net Book Value		8,509			7,975	7,975
Operating segments | Liquids Pipelines | Pipeline | Intra-Alberta Pipelines
Plant, property and equipment
Cost		762			138	138
Accumulated Depreciation		22			2	2
Net Book Value		740			136	136
Operating segments | Liquids Pipelines | Pumping equipment | Keystone Pipeline System
Plant, property and equipment
Cost		1,065			1,035	1,035
Accumulated Depreciation		184			204	204
Net Book Value		881			831	831
Operating segments | Liquids Pipelines | Pumping equipment | Intra-Alberta Pipelines
Plant, property and equipment
Cost		104			0	0
Accumulated Depreciation		3			0	0
Net Book Value		101			0	0
Operating segments | Liquids Pipelines | Tanks and other | Keystone Pipeline System
Plant, property and equipment
Cost		3,598			3,488	3,488
Accumulated Depreciation		488			556	556
Net Book Value		3,110			2,932	2,932
Operating segments | Liquids Pipelines | Tanks and other | Intra-Alberta Pipelines
Plant, property and equipment
Cost		291			56	56
Accumulated Depreciation		8			2	2
Net Book Value		283			54	54
Operating segments | Liquids Pipelines | Property, plant and equipment excluding under construction | Keystone Pipeline System
Plant, property and equipment
Cost		14,443			13,901	13,901
Accumulated Depreciation		1,943			2,163	2,163
Net Book Value		12,500			11,738	11,738
Operating segments | Liquids Pipelines | Property, plant and equipment excluding under construction | Intra-Alberta Pipelines
Plant, property and equipment
Cost		1,157			194	194
Accumulated Depreciation		33			4	4
Net Book Value		1,124			190	190
Operating segments | Liquids Pipelines | Under construction | Keystone Pipeline System
Plant, property and equipment
Cost		18			47	47
Accumulated Depreciation		0			0	0
Net Book Value		18			47	47
Operating segments | Liquids Pipelines | Under construction | Intra-Alberta Pipelines
Plant, property and equipment
Cost		84			0	0
Accumulated Depreciation		0			0	0
Net Book Value		84			0	0
Operating segments | Power and Storage
Plant, property and equipment
Cost		4,538			2,004	2,004
Accumulated Depreciation		877			703	703
Net Book Value		3,661			1,301	1,301
Operating segments | Power and Storage | Natural Gas
Plant, property and equipment
Cost		2,062			1,256	1,256
Accumulated Depreciation		708			522	522
Net Book Value		1,354			734	734
Operating segments | Power and Storage | Natural Gas Storage and Other
Plant, property and equipment
Cost		741			742	742
Accumulated Depreciation		169			181	181
Net Book Value		572			561	561
Operating segments | Power and Storage | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost		2,803			1,998	1,998
Accumulated Depreciation		877			703	703
Net Book Value		1,926			1,295	1,295
Operating segments | Power and Storage | Under construction
Plant, property and equipment
Cost		1,735			6	6
Accumulated Depreciation		0			0	0
Net Book Value		1,735			6	6
Corporate
Plant, property and equipment
Cost		448			883	883
Accumulated Depreciation		210			208	208
Net Book Value		$ 238			$ 675	$ 675
TC PipeLines, LP
Plant, property and equipment
Noncontrolling interest, ownership interest by parent					25.50%	25.50%
Disposal group, disposed of by sale, not discontinued operations | KKR and AIMCo | Coastal GasLink pipeline project
Plant, property and equipment
Equity interest					65.00%
Disposal group, disposed of by sale, not discontinued operations | 20 First Nations | Coastal GasLink pipeline project
Plant, property and equipment
Equity interest						10.00%
Northern Courier pipeline | Disposal group, disposed of by sale, not discontinued operations
Plant, property and equipment
Ownership interest sold	85.00%
Northern Courier pipeline | Liquids Pipelines
Plant, property and equipment
Ownership interest percentage	15.00%				15.00%	15.00%

LEASES - Impact of New Lease Gu

LEASES - Impact of New Lease Guidance on Date of Adoption (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Plant, Property and Equipment	$ 65,489	$ 67,088	$ 66,503
Accounts payable and other	4,544	5,465	5,408
Other long-term liabilities	$ 1,614	1,536	$ 1,008
Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Plant, Property and Equipment		585
Accounts payable and other		57
Other long-term liabilities		$ 528

LEASES - (Lessee) Narrative (De

LEASES - (Lessee) Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Lessee, Lease, Description [Line Items]
Operating lease termination period	1 year
Right-of-use asset	$ 530
Net rental expense on operating leases		$ 84	$ 93
Minimum
Lessee, Lease, Description [Line Items]
Operating leases optional renewable terms	1 year
Maximum
Lessee, Lease, Description [Line Items]
Operating leases optional renewable terms	25 years

LEASES - (Lessee) Operating Lea

LEASES - (Lessee) Operating Lease Cost and Other Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Operating lease cost
Operating lease cost	$ 117
Sublease Income	(11)
Lease, Cost	106
Cash paid for amounts included in the measurement of operating lease liabilities	76
ROU assets obtained in exchange for new operating lease liabilities	$ 9
Weighted average remaining lease term	10 years
Weighted average discount rate	3.50%

LEASES - (Lessee) Maturities of

LEASES - (Lessee) Maturities of Operating Lease Liabilities (Details) $ in Millions	Dec. 31, 2019CAD ($)
Lessee, Lease, Description [Line Items]
2020	$ 73
2021	69
2022	59
2023	58
2024	57
Thereafter	323
Total operating lease payments	639
Imputed interest	(107)
Operating lease liabilities	532
Operating lease, reported as other long-term liabilities	476
Accounts payable and other
Lessee, Lease, Description [Line Items]
Operating lease, reported as accounts payable and other	56
Other long-term liabilities (Note 16)
Lessee, Lease, Description [Line Items]
Operating lease, reported as other long-term liabilities	$ 476

LEASES - (Lessee) Maturities _2

LEASES - (Lessee) Maturities of Operating Lease Liabilities Under Previous Guidance (Details) $ in Millions	Dec. 31, 2018CAD ($)
Leases [Abstract]
2019	$ 81
2020	78
2021	76
2022	69
2023	67
Thereafter	390
Minimum Lease Payments	$ 761

LEASES - (Lessor) Narrative (De

LEASES - (Lessor) Narrative (Details) - CAD ($) $ in Millions	Jul. 17, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Lessor, Lease, Description [Line Items]
Fixed portion of the operating lease income		$ 180
Operating lease income			$ 373	$ 251
Cost		92,807	92,337
Accumulated Depreciation		27,318	25,834
Cost for facilities accounted for as operating leases			2,007
Accumulated depreciation for facilities accounted for as operating leases			$ 324
Disposal group, disposed of by sale, not discontinued operations | Northern Courier pipeline
Lessor, Lease, Description [Line Items]
Ownership interest sold	85.00%
Assets leased to others
Lessor, Lease, Description [Line Items]
Cost		834
Accumulated Depreciation		$ 301
Northern Courier pipeline | Liquids Pipelines
Lessor, Lease, Description [Line Items]
Ownership interest percentage	15.00%	15.00%

LEASES - (Lessor) Future Lease

LEASES - (Lessor) Future Lease Payments to be Received Under Operating Leases (Details) $ in Millions	Dec. 31, 2019CAD ($)
Leases [Abstract]
2020	$ 123
2021	116
2022	111
2023	109
2024	109
Thereafter	164
Total payments to be received	$ 732

EQUITY INVESTMENTS - Ownership

EQUITY INVESTMENTS - Ownership Information of Equity Investments (Details) $ in Millions	Jul. 17, 2019	Jun. 01, 2017	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Aug. 31, 2017	Jun. 02, 2017
Equity Investments
Income/(Loss) from Equity Investments			$ 920,000,000	$ 714,000,000	$ 773,000,000
Equity Investments			6,506,000,000	7,113,000,000
TransGas
Equity Investments
Ownership interest percentage								46.50%
Grand Rapids
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets			101,000,000	102,000,000
Northern Courier pipeline
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets			$ 62,000,000
Canadian Natural Gas Pipelines | TQM
Equity Investments
Ownership interest percentage			50.00%			50.00%
Income/(Loss) from Equity Investments			$ 12,000,000	12,000,000	11,000,000
Equity Investments			$ 79,000,000	71,000,000
U.S. Natural Gas Pipelines | Northern Border
Equity Investments
Ownership interest percentage			50.00%			50.00%
Income/(Loss) from Equity Investments			$ 91,000,000	87,000,000	87,000,000
Equity Investments			$ 549,000,000	677,000,000
Difference between the carrying value of the investment and the underlying equity in the net assets						$ 116	$ 115
U.S. Natural Gas Pipelines | Millennium
Equity Investments
Ownership interest percentage			47.50%			47.50%
Income/(Loss) from Equity Investments			$ 92,000,000	75,000,000	66,000,000
Equity Investments			$ 496,000,000	511,000,000
U.S. Natural Gas Pipelines | Iroquois
Equity Investments
Ownership interest percentage		50.00%	50.00%			50.00%			0.66%
Income/(Loss) from Equity Investments			$ 54,000,000	60,000,000	59,000,000
Equity Investments			$ 241,000,000	291,000,000
Difference between the carrying value of the investment and the underlying equity in the net assets						$ 40	$ 41
U.S. Natural Gas Pipelines | Pennant Midstream
Equity Investments
Ownership interest percentage			0.00%			0.00%
Income/(Loss) from Equity Investments			$ 12,000,000	17,000,000	11,000,000
Equity Investments			0	256,000,000
U.S. Natural Gas Pipelines | Other
Equity Investments
Income/(Loss) from Equity Investments			15,000,000	17,000,000	17,000,000
Equity Investments			$ 112,000,000	113,000,000
Mexico Natural Gas Pipelines | Sur de Texas
Equity Investments
Ownership interest percentage			60.00%			60.00%
Income/(Loss) from Equity Investments			$ 3,000,000	27,000,000	66,000,000
Equity Investments			600,000,000	627,000,000
Mexico Natural Gas Pipelines | TransGas
Equity Investments
Ownership interest percentage								0.00%
Income/(Loss) from Equity Investments			0	0	(12,000,000)
Equity Investments			$ 0	0
Liquids Pipelines | Grand Rapids
Equity Investments
Ownership interest percentage			50.00%			50.00%
Income/(Loss) from Equity Investments			$ 56,000,000	65,000,000	17,000,000
Equity Investments			$ 1,028,000,000	1,028,000,000
Liquids Pipelines | Northern Courier pipeline
Equity Investments
Ownership interest percentage	15.00%		15.00%			15.00%
Income/(Loss) from Equity Investments			$ 14,000,000	0	0
Equity Investments			62,000,000	0
Liquids Pipelines | Other
Equity Investments
Income/(Loss) from Equity Investments			0	(1,000,000)	(20,000,000)
Equity Investments			19,000,000	21,000,000
Liquids Pipelines | Canaport Energy East Marine Terminal Limited Partnership
Equity Investments
Equity Investments			$ 0
Power and Storage | Bruce Power
Equity Investments
Ownership interest percentage			48.40%			48.40%
Income/(Loss) from Equity Investments			$ 527,000,000	311,000,000	434,000,000
Equity Investments			3,256,000,000	3,166,000,000
Difference between the carrying value of the investment and the underlying equity in the net assets			$ 829,000,000	870,000,000
Power and Storage | Portlands Energy
Equity Investments
Ownership interest percentage			50.00%			50.00%
Income/(Loss) from Equity Investments			$ 35,000,000	36,000,000	31,000,000
Equity Investments			0	289,000,000
Difference between the carrying value of the investment and the underlying equity in the net assets			$ 76,000,000	73,000,000
Power and Storage | TransCanada Turbines
Equity Investments
Ownership interest percentage			50.00%			50.00%
Income/(Loss) from Equity Investments			$ 9,000,000	8,000,000	$ 6,000,000
Equity Investments			$ 64,000,000	$ 63,000,000
Disposal group, disposed of by sale, not discontinued operations | Iroquois
Equity Investments
Ownership interest sold		49.34%
Northern Courier pipeline | Disposal group, disposed of by sale, not discontinued operations
Equity Investments
Ownership interest sold	85.00%

EQUITY INVESTMENTS - Narrative

EQUITY INVESTMENTS - Narrative (Details) $ in Millions	1 Months Ended		12 Months Ended
	Oct. 31, 2017CAD ($)	Aug. 31, 2017CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2019MXN ($)	Dec. 31, 2018MXN ($)	Dec. 31, 2017MXN ($)
Equity Investments
Distributions received from equity investments			$ 1,399	$ 1,106	$ 1,332
Returns of capital			186	121	362
Contributions to equity investments			602	1,015	1,681
Foreign exchange gain (loss)			53	(5)	(63)
Joint Venture | Revolving credit facility | Unsecured Loan Facility
Equity Investments
Credit facility, amount								$ 21,300,000,000
TransGas
Equity Investments
Asset impairment charges		$ 12
Ownership interest percentage		46.50%
Contract term		20 years
TransGas | Mexico Natural Gas Pipelines
Equity Investments
Ownership interest percentage		0.00%
Canaport Energy East Marine Terminal Limited Partnership | Liquids Pipelines | Energy East, Eastern Mainline and Upland projects
Equity Investments
Asset impairment charges	$ 20
Sur de Texas
Equity Investments
Contributions to equity investments			32	179	977
Sur de Texas | Joint Venture
Equity Investments
Loans receivable from affiliates			1,400	1,300		$ 20,900,000,000	$ 18,900,000,000
Interest income, related party			147	120	34
Foreign exchange gain (loss)			$ 53	$ (5)	$ (63)
Sur de Texas | Mexico Natural Gas Pipelines
Equity Investments
Ownership interest percentage			60.00%			60.00%

EQUITY INVESTMENTS - Summarized

EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income
Revenues	$ 5,693	$ 4,836	$ 4,913
Operating and other expenses	(3,408)	(3,545)	(2,993)
Net income	1,990	1,515	1,636
Income/(loss) from equity investments	920	714	$ 773
Balance Sheet
Current assets	2,305	2,209
Non-current assets	21,865	20,647
Current liabilities	(2,060)	(2,049)
Non-current liabilities	$ (11,461)	$ (9,042)

RATE-REGULATED BUSINESSES - Nar

RATE-REGULATED BUSINESSES - Narrative (Details) $ in Millions	Feb. 22, 2018	Feb. 21, 2018	Jun. 30, 2018	Mar. 31, 2016USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2014CAD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2019pipeline
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%
Deemed common equity, percent			40.00%
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Approved ROE on deemed common equity							10.10%
Deemed common equity, percent							40.00%
After-tax annual contribution to reduce revenue requirement							$ 20
Fixed toll term							6 years
Approved composite depreciation rate					3.90%	3.20%
Great Lakes
Public Utilities, General Disclosures [Line Items]
Maximum transportation rate decrease	27.00%	2.00%
TC Pipe Lines LP
Public Utilities, General Disclosures [Line Items]
Noncontrolling interest, ownership interest by parent									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 - Ass

RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) $ in Millions, $ in Millions	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2006CAD ($)	Dec. 31, 2006USD ($)
Regulatory Assets
Regulatory Assets	$ 1,631		$ 1,630
Less: Current portion included in Other current assets (Note 7)	83		43
Regulatory Assets, noncurrent	1,548		1,587
Regulatory Liabilities
Regulatory Liabilities	4,521		4,468
Less: Current portion included in Accounts payable and other (Note 15)	591		696
Regulatory Liabilities, noncurrent	3,930		3,772
Operating and debt-service regulatory liabilities
Regulatory Liabilities
Regulatory Liabilities	96		$ 139
Remaining Recovery/ Settlement Period (years)			1 year
Pensions and other post retirement benefits | ANR PIPELINE COMPANY
Regulatory Liabilities
Regulatory Liabilities	54		$ 41
Long term adjustment account
Regulatory Liabilities
Regulatory Liabilities	1,015		$ 660
Long term adjustment account | Minimum
Regulatory Liabilities
Remaining Recovery/ Settlement Period (years)			1 year
Long term adjustment account | Maximum
Regulatory Liabilities
Remaining Recovery/ Settlement Period (years)			47 years
Long term adjustment account, amount to be amortized over one year
Regulatory Liabilities
Regulatory Liabilities			$ 488
Remaining Recovery/ Settlement Period (years)			47 years
Bridging amortization account
Regulatory Liabilities
Regulatory Liabilities	305		$ 428
Remaining Recovery/ Settlement Period (years)			11 years
Pipeline abandonment trust balance
Regulatory Liabilities
Regulatory Liabilities	1,113		$ 1,462
Cost of removal
Regulatory Liabilities
Regulatory Liabilities	261		253
Deferred income taxes
Regulatory Liabilities
Regulatory Liabilities	165		151
Deferred income taxes - U.S. Tax Reform
Regulatory Liabilities
Regulatory Liabilities	1,394		1,239
Other
Regulatory Liabilities
Regulatory Liabilities	65		60
Postretirement benefit costs | ANR PIPELINE COMPANY
Other disclosures pertaining to regulated assets and liabilities
Regulatory liability settlement	11	$ 8
Amount to be addressed In next settlement				$ 41	$ 32
Deferred income taxes
Regulatory Assets
Regulatory Assets	1,051		1,088
Operating and debt-service regulatory assets
Regulatory Assets
Regulatory Assets	12		$ 2
Remaining Recovery/ Settlement Period (years)			1 year
Pensions and other post retirement benefits
Regulatory Assets
Regulatory Assets	379		$ 417
Regulatory Liabilities
Regulatory Liabilities	53		35
Foreign exchange on long-term debt
Regulatory Assets
Regulatory Assets	46		$ 16
Foreign exchange on long-term debt | Minimum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)			1 year
Foreign exchange on long-term debt | Maximum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)			10 years
Other
Regulatory Assets
Regulatory Assets	$ 143		$ 107

GOODWILL (Details)

GOODWILL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Goodwill
Balance at the beginning of the period	$ 14,178
Balance at the end of the period	12,887	$ 14,178
U.S. Natural Gas Pipelines
Goodwill
Balance at the beginning of the period	14,178	13,084
Tuscarora impairment charge		(79)
Sale of Columbia midstream assets	(595)
Foreign exchange rate changes	(696)	1,173
Balance at the end of the period	$ 12,887	$ 14,178

GOODWILL - Narrative (Details)

GOODWILL - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Aug. 01, 2019USD ($)	Dec. 31, 2018USD ($)
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	$ 14,178	$ 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

INTANGIBLE AND OTHER ASSETS (De

INTANGIBLE AND OTHER ASSETS (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Capital projects in development	$ 1,715	$ 1,051
Employee post-retirement benefits (Note 24)	162	192
Deferred income tax assets (Note 17)	37	322
Fair value of derivative contracts (Note 25)	7	61
Other	247	295
Intangible and other assets	$ 2,168	$ 1,921

INTANGIBLE AND OTHER ASSETS - N

INTANGIBLE AND OTHER ASSETS - Narrative (Details) - CAD ($) $ in Millions	Oct. 05, 2017	Nov. 30, 2018	Oct. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Capital projects in development				$ 1,715	$ 1,051
Reimbursement of costs related to capital projects in development				0	470	$ 634
Asset impairment charges				0	801	$ 1,257
Keystone XL
Finite-Lived Intangible Assets [Line Items]
Capital projects in development				$ 1,500	$ 800
Coastal GasLink pipeline project
Finite-Lived Intangible Assets [Line Items]
Reimbursement of costs related to capital projects in development		$ 470
Pacific Northwest LNG project
Finite-Lived Intangible Assets [Line Items]
Reimbursement of costs related to capital projects in development			$ 634
Energy East, Eastern Mainline and Upland projects
Finite-Lived Intangible Assets [Line Items]
Asset impairment charges	$ 1,153
Asset impairment charge, after tax	$ 870

NOTES PAYABLE (Details)

NOTES PAYABLE (Details)	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2019MXN ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018MXN ($)	Dec. 31, 2018USD ($)
Notes payable
Outstanding	$ 4,300,000,000	$ 2,762,000,000
Operated affiliates
Notes payable
Unused Capacity	800,000,000	800,000,000
Revolving credit facility
Notes payable
Cost to maintain	11,000,000	12,000,000	$ 7,000,000
Notes payable
Notes payable
Denominated value	1,353,000,000	961,000,000			$ 2,068,000,000		$ 847,000,000
Revolving and demand credit facility
Notes payable
Total Facilities	12,600,000,000	12,900,000,000
TCPL | Revolving credit facility | Maturing December 2024
Notes payable
Total Facilities	3,000,000,000	3,000,000,000
Unused Capacity	3,000,000,000
TCPL | Notes payable
Notes payable
Outstanding	$ 4,034,000,000	$ 2,117,000,000
Weighted average interest rate per annum	2.10%	2.50%		2.10%	2.10%	2.50%	2.50%
USA | Notes payable
Notes payable
Outstanding	$ 0	$ 611,000,000			$ 0		$ 448,000,000
Weighted average interest rate per annum	0.00%	3.10%		0.00%	0.00%	3.10%	3.10%
Mexico subsidiary | Revolving credit facility
Notes payable
Total Facilities				$ 5,000,000,000		$ 5,000,000,000
Unused Capacity				$ 1,100,000,000
Mexico subsidiary | Notes payable
Notes payable
Outstanding	$ 266,000,000	$ 34,000,000			$ 205,000,000		$ 25,000,000
Weighted average interest rate per annum	2.70%	3.30%		2.70%	2.70%	3.30%	3.30%
TCPL/TCPL USA/Columbia/TAIL | Revolving credit facility | Maturing December 2020
Notes payable
Total Facilities					$ 4,500,000,000		$ 4,500,000,000
Unused Capacity					4,500,000,000
TCPL/TCPL USA/Columbia/TAIL | Revolving credit facility | Maturing December 2022
Notes payable
Total Facilities					1,000,000,000		$ 1,000,000,000
Unused Capacity					$ 1,000,000,000
TCPL/TCPL USA | Revolving credit facility
Notes payable
Total Facilities	$ 2,100,000,000	$ 2,100,000,000
Unused Capacity	$ 1,100,000,000

ACCOUNTS PAYABLE AND OTHER (Det

ACCOUNTS PAYABLE AND OTHER (Details) $ / shares in Units, $ / shares in Units, $ in Millions, $ in Millions	Oct. 22, 2019CAD ($)$ / shares	Oct. 22, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Jan. 01, 2019CAD ($)	Feb. 17, 2017$ / shares
Non-controlling interests
Trade payables			$ 3,314	$ 3,224
Regulatory liabilities (Note 11)			696	591
Fair value of derivative contracts (Note 25)			115	922
Unredeemed shares of Columbia Pipeline Group, Inc.			0	357
Other			419	314
Accounts payable and other			4,544	5,408		$ 5,465
Payment for unredeemed shares of Columbia Pipeline Group Inc.	$ 373	$ 284	$ 373	$ 0	$ 0
Columbia Pipeline Partners LP | Equity Attributable to Non-Controlling Interests
Non-controlling interests
Share price (in dollars per share) | (per share)	$ 25.50						$ 17

OTHER LONG-TERM LIABILITIES (De

OTHER LONG-TERM LIABILITIES (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Deferred Costs, Noncurrent [Abstract]
Employee post-retirement benefits (Note 24)	$ 540		$ 569
Operating lease obligations (Note 9)	476
Long-term contract liabilities (Note 5)	226		121
Fair value of derivative contracts (Note 25)	81		42
Asset retirement obligations	62		90
Guarantees	32		12
Other	197		174
Other long-term liabilities	$ 1,614	$ 1,536	$ 1,008

INCOME TAXES - U.S. Tax Reform

INCOME TAXES - U.S. Tax Reform and Alberta Tax Rate Reduction (Details) - CAD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2017
Income Tax Contingency [Line Items]
Provisional deferred income tax recovery (expense)				$ 816
Increase in regulatory liabilities for businesses subject to RRA				1,686
U.S. Tax Reform, additional deferred income tax recovery		$ 52
U.S. Tax Reform, additional deferred income tax recovery subject to RRA		$ 115
Alberta Tax Rate Reform, additional deferred income tax recovery	$ 32
Alberta Tax Rate Reform, additional deferred income tax recovery, subject to RRA			$ 83
Other Post-Retirement Benefit Plans
Income Tax Contingency [Line Items]
Provisional deferred income tax recovery (expense)				$ (12)

INCOME TAXES - Provision (Detai

INCOME TAXES - Provision (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current
Canada	$ 84	$ 65	$ 113
Foreign	615	250	36
Total	699	315	149
Deferred
Canada	(29)	49	(185)
Foreign	84	235	751
Deferred – U.S. Tax Reform and 2018 FERC Actions	0	(167)	(804)
Total	55	117	(238)
Income Tax (Recovery)/Expense	$ 754	$ 432	$ (89)

INCOME TAXES - Geographic Compo

INCOME TAXES - Geographic Components of Income/(Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Canada	$ 1,144	$ 433	$ (339)
Foreign	4,043	3,516	3,645
Income before Income Taxes	$ 5,187	$ 3,949	$ 3,306

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Income Tax (Recovery)/Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income before income taxes	$ 5,187	$ 3,949	$ 3,306
Federal and provincial statutory tax rate	26.50%	27.00%	27.00%
Expected income tax expense	$ 1,375	$ 1,066	$ 893
Valuation allowance release	(259)	0
Foreign income tax rate differentials	(206)	(432)	(81)
Income tax differential related to regulated operations	(159)	(54)	(42)
(Income)/loss from non-controlling interests	(78)	50	(64)
Alberta tax rate reduction	(32)	0	0
Non-taxable portion of capital gains	(28)	(11)	(42)
Non-deductible goodwill on the Columbia midstream disposition	154	0	0
U.S. Tax Reform and 2018 FERC Actions	0	(167)	(804)
Asset impairment charges	0	0	34
Non-deductible amounts	0	0	4
Other	(13)	(20)	13
Income Tax (Recovery)/Expense	$ 754	$ 432	$ (89)

INCOME TAXES - Deferred Assets

INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred Income Tax Assets
Tax loss and credit carryforwards	$ 1,046	$ 1,238
Regulatory and other deferred amounts	692	858
Difference in accounting and tax bases of impaired assets and assets held for sale	538	574
Unrealized foreign exchange losses on long-term debt	260	491
Financial instruments	23	0
Other	70	292
Deferred tax assets, gross	2,629	3,453
Less: Valuation allowance	673	1,159
Deferred tax assets, net of Valuation allowance	1,956	2,294
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,197	6,449
Equity investments	1,087	1,069
Taxes on future revenue requirement	232	300
Other	106	180
Deferred tax liabilities, gross	7,622	7,998
Net Deferred Income Tax Liabilities	5,666	5,704
Deferred Income Tax Assets
Intangible and other assets (Note 13)	37	322
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities (Note 17)	$ 5,703	$ 6,026

INCOME TAXES - Additional Narra

INCOME TAXES - Additional Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Net operating loss carryforwards
Tax loss and credit carryforwards	$ 1,046,000,000	$ 1,238,000,000
Valuation allowance	673,000,000	1,159,000,000
Valuation allowance release	259,000,000	0
Deferred income tax liabilities on the unremitted earnings of foreign investments	648,000,000	619,000,000
Income tax payments, net of refunds	713,000,000	338,000,000	$ 247,000,000
Interest expense (recover) reflected within net tax expense	4,000,000	(1,000,000)	0
Accrued interest expense	7,000,000	3,000,000
Income tax penalties expense	0	0	$ 0
Income tax penalties accrued	0	0
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards	1,929,000,000	1,867,000,000
Capital loss carryforwards unrecognized	598,000,000	821,000,000
Canada federal and provincial | Alternative minimum tax
Net operating loss carryforwards
Minimum tax credits	$ 102,000,000	$ 91,000,000
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards				$ 1,098	$ 889
Mexican Tax Authority
Net operating loss carryforwards
Tax loss and credit carryforwards				$ 4	$ 3

INCOME TAXES - Reconciliation_2

INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefit at beginning of year	$ 19	$ 15	$ 18
Gross increases – tax positions in prior years	13	13	0
Gross decreases – tax positions in prior years	(1)	(5)	(1)
Gross increases – tax positions in current year	0	0	2
Lapse of statutes of limitations	(2)	(4)	(4)
Unrecognized Tax Benefit at End of Year	$ 29	$ 19	$ 15

LONG-TERM DEBT - Amounts Outsta

LONG-TERM DEBT - Amounts Outstanding and Principal Repayments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Debt Instrument [Line Items]
Outstanding	$ 37,019	$ 39,982
Current portion of long-term debt	(2,705)	(3,462)
Unamortized debt discount and issue costs	(228)	(241)
Fair value adjustments	194	230
Noncurrent portion of long-term debt	34,280	36,509
Increase (decrease) in fair value of interest rate hedge	1	(2)
Repayments of Long-term Debt [Abstract]
2020	2,705
2021	1,966
2022	1,932
2023	1,897
2024	289
Columbian Pipeline
Debt Instrument [Line Items]
Increase (decrease) in fair value of acquired liabilities, long-term debt	193	232
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding	29,433	31,856
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Dates Between 2020
Debt Instrument [Line Items]
Outstanding	$ 250	$ 350
Interest Rate	11.80%	11.40%	11.80%	11.40%
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Date of 2021
Debt Instrument [Line Items]
Outstanding	$ 518	$ 546	$ 400	$ 400
Interest Rate	9.90%	9.90%	9.90%	9.90%
TRANSCANADA PIPELINES LIMITED | Medium Term Notes
Debt Instrument [Line Items]
Outstanding	$ 9,491	$ 7,504
Interest Rate	4.60%	4.80%	4.60%	4.80%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 19,174	$ 23,456	$ 14,792	$ 17,192
Interest Rate	5.20%	5.10%	5.20%	5.10%
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Outstanding	$ 905	$ 921
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	$ 259	$ 273	$ 200	$ 200
Interest Rate	7.90%	7.90%	7.90%	7.90%
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity between 2025 and 2030
Debt Instrument [Line Items]
Outstanding	$ 504	$ 504
Interest Rate	7.40%	7.40%	7.40%	7.40%
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity Date of 2026
Debt Instrument [Line Items]
Outstanding	$ 42	$ 44	$ 33	$ 33
Interest Rate	7.50%	7.50%	7.50%	7.50%
Columbian Pipeline | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 2,916	$ 3,070	$ 2,250	$ 2,250
Interest Rate	4.40%	4.40%	4.40%	4.40%
TC PIPELINES, LP
Debt Instrument [Line Items]
Outstanding	$ 2,139	$ 2,374
TC PIPELINES, LP | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 1,556	$ 1,637	$ 1,200	$ 1,200
Interest Rate	4.40%	4.40%	4.40%	4.40%
TC PIPELINES, LP | Unsecured Loan Facility
Debt Instrument [Line Items]
Outstanding	$ 0	$ 55	$ 0	$ 40
Interest Rate	0.00%	3.80%	0.00%	3.80%
TC PIPELINES, LP | Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding	$ 583	$ 682	$ 450	$ 500
Interest Rate	2.90%	3.60%	2.90%	3.60%
ANR PIPELINE COMPANY | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 872	$ 918	$ 672	$ 672
Interest Rate	7.20%	7.20%	7.20%	7.20%
GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Outstanding	$ 324	$ 389
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 324	$ 341	$ 250	$ 250
Interest Rate	5.60%	5.60%	5.60%	5.60%
GAS TRANSMISSION NORTHWEST LLC | Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding	$ 0	$ 48	$ 0	$ 35
Interest Rate	0.00%	3.30%	0.00%	3.30%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | Senior Unsecured Notes
Debt Instrument [Line Items]
Outstanding	$ 284	$ 327	$ 219	$ 240
Interest Rate	7.70%	7.70%	7.70%	7.70%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Unsecured Loan Facility
Debt Instrument [Line Items]
Outstanding	$ 51	$ 26	$ 39	$ 19
Interest Rate	3.00%	3.60%	3.00%	3.60%
TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding	$ 30	$ 33	$ 23	$ 24
Interest Rate	2.80%	3.50%	2.80%	3.50%
NORTH BAJA PIPELINE, LLC | Unsecured Term Loan
Debt Instrument [Line Items]
Outstanding	$ 65	$ 68	$ 50	$ 50
Interest Rate	2.80%	3.50%	2.80%	3.50%

LONG-TERM DEBT - Issued (Detail

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

Jul. 17, 2019

Jul. 16, 2019USD ($)

Sep. 30, 2019CAD ($)

Jul. 31, 2019CAD ($)

Apr. 30, 2019CAD ($)

Dec. 31, 2018USD ($)

Oct. 31, 2018USD ($)

Jul. 31, 2018CAD ($)

May 31, 2018USD ($)

Apr. 30, 2018USD ($)

Nov. 30, 2017USD ($)

Sep. 30, 2017CAD ($)

Aug. 31, 2017USD ($)

May 31, 2017USD ($)

Dec. 31, 2019

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 | Senior Unsecured Notes Due May 2028 [Member]

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 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 | 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%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due November 2019, floating interest rate

Debt Instrument [Line Items]

Amount

$ 550

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due November 2019, fixed interest rate

Debt Instrument [Line Items]

Amount

$ 700

Interest Rate

2.125%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due March 2028

Debt Instrument [Line Items]

Amount

$ 300

Interest Rate

3.39%

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due September 2047

Debt Instrument [Line Items]

Amount

$ 700

Interest Rate

4.33%

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 | Unsecured Loan Facility due April 2023

Debt Instrument [Line Items]

Amount

$ 19

TUSCARORA GAS TRANSMISSION COMPANY | Unsecured Term Loan due August 2020

Debt Instrument [Line Items]

Amount

$ 25

TC PIPELINES, LP | Senior Unsecured Notes due May 2027

Debt Instrument [Line Items]

Amount

$ 500

Interest Rate

3.90%

Disposal group, disposed of by sale, not discontinued operations | NOURTHERN COURIER PIPELINE LIMTED PARTNERSHIP

Debt Instrument [Line Items]

Ownership interest sold

85.00%

Liquids Pipelines | NOURTHERN COURIER PIPELINE LIMTED PARTNERSHIP

Debt Instrument [Line Items]

Ownership interest percentage

15.00%

15.00%

LONG-TERM DEBT - Retired_Repaid

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

1 Months Ended

Nov. 30, 2019USD ($)

Jun. 30, 2019USD ($)

May 31, 2019CAD ($)

May 31, 2019USD ($)

Mar. 31, 2019CAD ($)

Jan. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Aug. 31, 2018USD ($)

Jun. 30, 2018USD ($)

May 31, 2018USD ($)

Mar. 31, 2018CAD ($)

Mar. 31, 2018USD ($)

Jan. 31, 2018USD ($)

Dec. 31, 2017CAD ($)

Nov. 30, 2017USD ($)

Aug. 31, 2017USD ($)

Jun. 30, 2017USD ($)

Apr. 30, 2017USD ($)

Feb. 28, 2017USD ($)

Jan. 31, 2017CAD ($)

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

TRANSCANADA PIPELINES LIMITED | Debentures due December 2017

Debt Instrument [Line Items]

Amount

$ 100

Interest Rate

9.80%

TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes due November 2017

Debt Instrument [Line Items]

Amount

$ 1,000

Interest Rate

1.625%

TRANSCANADA PIPELINES LIMITED | Acquisition Bridge Facility

Debt Instrument [Line Items]

Amount

$ 1,513

$ 500

TRANSCANADA PIPELINES LIMITED | Medium Term Notes due January 2017

Debt Instrument [Line Items]

Amount

$ 300

Interest Rate

5.10%

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

GAS TRANSMISSION NORTHWEST LLC | Unsecured Term Loan due May 2019

Debt Instrument [Line Items]

Amount

$ 35

COLUMBIA PIPELINE GROUP, INC. | Senior Unsecured Notes due June 2018

Debt Instrument [Line Items]

Amount

$ 500

Interest Rate

2.45%

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%

TUSCARORA GAS TRANSMISSION COMPANY | Senior Secured Notes due August 2017

Debt Instrument [Line Items]

Amount

$ 12

Interest Rate

3.82%

TRANSCANADA PIPELINE USA LTD. | Acquisition Bridge Facility

Debt Instrument [Line Items]

Amount

$ 630

$ 1,070

LONG-TERM DEBT - Interest Expen

LONG-TERM DEBT - Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest Expense [Abstract]
Capitalized interest	$ (186)	$ (124)	$ (173)
Amortization and other financial charges	55	48	67
Interest expense	2,333	2,265	2,069
Interest payments, net of interest capitalized	2,295	2,156	1,987
Short-term debt
Interest Expense [Abstract]
Interest on debt	106	73	33
Long-term debt (excluding junior subordinated notes)
Interest Expense [Abstract]
Interest on debt	1,931	1,877	1,794
Junior subordinated notes
Interest Expense [Abstract]
Interest on debt	$ 427	$ 391	$ 348

JUNIOR SUBORDINATED NOTES (Deta

JUNIOR SUBORDINATED NOTES (Details)	1 Months Ended			3 Months Ended	12 Months Ended
	Sep. 30, 2019USD ($)	May 31, 2017USD ($)	Mar. 31, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)	May 31, 2017CAD ($)
Debt Instrument [Line Items]
Outstanding					$ 37,019,000,000		$ 39,982,000,000
Unamortized debt discount and issue costs					(228,000,000)		(241,000,000)
Long-term Debt						$ 200,000,000		$ 750,000,000
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding					29,433,000,000		31,856,000,000
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					8,694,000,000		7,572,000,000
Unamortized debt discount and issue costs					(80,000,000)		(64,000,000)
Long-term Debt					8,614,000,000		7,508,000,000
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067 | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 1,296,000,000		$ 1,364,000,000
Effective Interest Rate					5.10%	5.10%	5.60%	5.60%
Debt converted		$ 1,000,000,000
Stated interest rate					6.35%	6.35%			6.35%
Stated interest rate, period of time					10 years
Debt instrument, face amount						$ 1,000,000,000
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067 | Junior subordinated notes | LIBOR
Debt Instrument [Line Items]
Basis points (percent)		2.21%
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2075 | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 972,000,000		$ 1,024,000,000
Effective Interest Rate					6.00%	6.00%	6.50%	6.50%
Stated interest rate					5.875%	5.875%
Stated interest rate, period of time					10 years
Debt instrument, face amount						$ 750,000,000
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2076 | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 1,556,000,000		$ 1,637,000,000
Effective Interest Rate					6.70%	6.70%	7.20%	7.20%
Stated interest rate					6.125%	6.125%
Stated interest rate, period of time					10 years
Debt instrument, face amount						$ 1,200,000,000
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2077 | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 1,944,000,000		$ 2,047,000,000
Effective Interest Rate					5.70%	5.70%	6.20%	6.20%
Stated interest rate					5.55%	5.55%
Stated interest rate, period of time					10 years
Debt instrument, face amount						$ 1,500,000,000
TRANSCANADA PIPELINES LIMITED | Canadian junior subordinated debt, due 2077 | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 1,500,000,000		$ 1,500,000,000
Effective Interest Rate					5.40%	5.40%	5.50%	5.50%
Stated interest rate					4.90%	4.90%
Stated interest rate, period of time					10 years
Debt instrument, face amount					$ 1,500,000,000
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2079 | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding					$ 1,426,000,000		$ 0
Effective Interest Rate					6.30%	6.30%	0.00%	0.00%
Stated interest rate					5.75%	5.75%
Stated interest rate, period of time					10 years
Debt instrument, face amount						$ 1,100,000,000
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2019-A | Junior subordinated notes
Debt Instrument [Line Items]
Stated interest rate	5.75%
Debt instrument, face amount	$ 1,100,000,000
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]
Basis points (percent)	4.404%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2019-A | September 2049 until September 2079 | Junior subordinated notes | LIBOR
Debt Instrument [Line Items]
Basis points (percent)	5.154%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-B | Junior subordinated notes
Debt Instrument [Line Items]
Stated interest rate									4.90%
Debt instrument, face amount									$ 1,500,000,000
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 2017-B | May 2027 until May 2047 | Junior subordinated notes | LIBOR
Debt Instrument [Line Items]
Basis points (percent)		3.33%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-B | May 2047 to May 2077 | Junior subordinated notes | LIBOR
Debt Instrument [Line Items]
Basis points (percent)		4.08%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-A | Junior subordinated notes
Debt Instrument [Line Items]
Stated interest rate			5.55%	5.55%
Debt instrument, face amount			$ 1,500,000,000	$ 1,500,000,000
Administrative charge percentage			0.25%	0.25%
Redemption price as a percentage of principal amount plus accrued and unpaid interest			100.00%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-A | March 2027 until March 2047 | Junior subordinated notes | LIBOR
Debt Instrument [Line Items]
Basis points (percent)			3.458%
TRANSCANADA PIPELINES LIMITED | Trust Notes - Series 2017-A | March 2047 until March 2077 | Junior subordinated notes | LIBOR
Debt Instrument [Line Items]
Basis points (percent)			4.208%
TransCanada Trust | Trust Notes - Series 2019-A | Notes payable
Debt Instrument [Line Items]
Stated interest rate, period of time	10 years
Debt instrument, face amount	$ 1,100,000,000
TransCanada Trust | Trust Notes - Series 2019-A | First Ten Years | Notes payable
Debt Instrument [Line Items]
Stated interest rate	5.50%
TransCanada Trust | Trust Notes - Series 2017-B | Notes payable
Debt Instrument [Line Items]
Stated interest rate, period of time		10 years
Debt instrument, face amount									$ 1,500,000,000
TransCanada Trust | Trust Notes - Series 2017-B | First Ten Years | Notes payable
Debt Instrument [Line Items]
Stated interest rate									4.65%
TransCanada Trust | Trust Notes - Series 2017-A | Notes payable
Debt Instrument [Line Items]
Stated interest rate, period of time				10 years
Debt instrument, face amount			$ 1,500,000,000	$ 1,500,000,000
TransCanada Trust | Trust Notes - Series 2017-A | First Ten Years | Notes payable
Debt Instrument [Line Items]
Stated interest rate			5.30%	5.30%

NON-CONTROLLING INTERESTS (Deta

NON-CONTROLLING INTERESTS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest in TC PipeLines, LP	$ 1,634	$ 1,655
Non-controlling interests included in the Consolidated Statement of Income
Net income/(loss) attributable to non-controlling interests	293	(185)	$ 238
Noncontrolling Interest
Non-controlling interests included in the Consolidated Statement of Income
Net income/(loss) attributable to non-controlling interests	(293)	185	(238)
TC PipeLines, LP | Noncontrolling Interest
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest in TC PipeLines, LP	1,634	1,655
Non-controlling interests included in the Consolidated Statement of Income
Net income/(loss) attributable to non-controlling interests	293	(185)	220
Portland Natural Gas Transmission System | Noncontrolling Interest
Non-controlling interests included in the Consolidated Statement of Income
Net income/(loss) attributable to non-controlling interests	0	0	9
Columbia Pipeline Partners LP | Noncontrolling Interest
Non-controlling interests included in the Consolidated Statement of Income
Net income/(loss) attributable to non-controlling interests	$ 0	$ 0	$ 9

NON-CONTROLLING INTERESTS - Nar

NON-CONTROLLING INTERESTS - Narrative (Details) - Noncontrolling Interest $ / shares in Units, $ / shares in Units, shares in Millions, $ in Millions, $ in Millions	Jun. 01, 2017	Feb. 17, 2017USD ($)$ / shares	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)shares	Dec. 31, 2019	Oct. 22, 2019$ / shares	Dec. 31, 2016USD ($)
Non-controlling interests
Aggregate transaction value			$ 9	$ 41
TC Pipe Lines LP
Non-controlling interests
Percentage of non-controlling interests						74.50%
Common units outstanding, subject to rescission, amount					$ 106			$ 82
Reclassification to Common Units, subject to redemption (in shares) | shares					1.6
TC Pipe Lines LP | Minimum
Non-controlling interests
Percentage of non-controlling interests			74.30%	73.20%
TC Pipe Lines LP | Maximum
Non-controlling interests
Percentage of non-controlling interests			74.50%	74.30%
Portland Natural Gas Transmission System
Non-controlling interests
Percentage of non-controlling interests						0.00%
Ownership interest before transaction	11.81%
Columbia Pipeline Partners LP
Non-controlling interests
Share price (in dollars per share) | (per share)		$ 17					$ 25.50
Stub period distribution payments acquired (in dollars per share) | $ / shares		$ 0.10
Aggregate transaction value		$ 921

COMMON SHARES - Reconciliation

COMMON SHARES - Reconciliation and Weighted Average Common Shares Outstanding (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)	918,000
Outstanding at the beginning of the period	$ 23,174
Exercise of options (in shares)	5,138
Outstanding at the end of the period (in shares)	938,000	918,000
Outstanding at the end of the period	$ 24,387	$ 23,174
Weighted Average Common Shares Outstanding
Basic (in shares)	929,000	902,000	872,000
Diluted (in shares)	931,000	903,000	874,000
Common Shares
Increase (decrease) in equity
Outstanding at the beginning of the period (in shares)	918,097	881,376	863,759
Outstanding at the beginning of the period	$ 23,174	$ 21,167	$ 20,099
Dividend reinvestment and share purchase plan (in shares)	15,165	15,937	12,824
Dividend reinvestment and share purchase plan	$ 931	$ 855	$ 790
At-the-market equity issuance program (in shares)		20,050	3,462
At-the-market equity issuance program		$ 1,118	$ 216
Exercise of options (in shares)	5,138	734	1,331
Exercise of options	$ 282	$ 34	$ 62
Outstanding at the end of the period (in shares)	938,400	918,097	881,376
Outstanding at the end of the period	$ 24,387	$ 23,174	$ 21,167
Weighted Average Common Shares Outstanding
Basic (in shares)	929,000	902,000	872,000
Diluted (in shares)	931,000	903,000	874,000

COMMON SHARES - Dividend Reinve

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%

COMMON SHARES - TC Energy Corpo

COMMON SHARES - TC Energy Corporation At-the-Market Equity Issuance Program (Details) - At-the-Market Equity Issuance Program - CAD ($)	Dec. 31, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2019	Dec. 31, 2018
Subsidiary, Sale of Stock [Line Items]
Stock issuance program, period in effect (in months)			25 months
Authorized amount		$ 2,000,000,000	$ 1,000,000,000
Additional authorized amount		$ 1,000,000,000
Treasury stock reissued during period (in shares)	3,500,000			0	20,000,000
Price per share (in Canadian dollars per share)	$ 63.03				$ 56.13
Consideration received on transaction	$ 216,000,000				$ 1,100,000,000
Payments of stock issuance costs	$ 2,000,000				$ 10,000,000

COMMON SHARES - Options (Detail

COMMON SHARES - Options (Details)	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Number of Options (thousands)
Outstanding at the beginning of the period (in shares)	12,404,000
Granted (in shares)	2,004,000
Exercised (in shares)	(5,138,000)
Options forfeited/expired (in shares)	(176,000)
Outstanding at the end of the period (in shares)	9,094,000
Options Exercisable (in shares)	5,110,000
Weighted Average Exercise Prices
Outstanding at the beginning of the period (in Canadian dollars per share) | $ / shares	$ 52.83
Granted (in Canadian dollars per share) | $ / shares	56.90
Exercised (in Canadian dollars per share) | $ / shares	49.08
Options forfeited/expired (in Canadian dollars per share) | $ / shares	56.69
Outstanding at the end of the period (in Canadian dollars per share) | $ / shares	55.77
Options Exercisable at December 31, 2017 (in Canadian dollars per share) | $ / shares	$ 54.28
Weighted Average Remaining Contractual Life (years)
Options Outstanding	4 years 1 month 6 days
Options Exercisable	3 years
Number of shares available for grant (in shares)	7,962,761
Options expiration term	7 years
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Vesting in year one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights percentage	33.33%
Vesting in year two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights percentage	33.33%
Vesting in year three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights percentage	33.34%

COMMON SHARES - Stock Options A

COMMON SHARES - Stock Options Assumptions Used (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan, Assumptions Used in Calculations [Abstract]
Weighted average fair value (in dollars per share)	$ 6.37	$ 5.80	$ 7.22
Expected life	5 years 8 months 12 days	5 years 8 months 12 days	5 years 8 months 12 days
Interest rate	1.90%	2.10%	1.20%
Volatility	19.00%	16.00%	18.00%
Dividend yield	5.00%	4.20%	3.60%
Expense for stock options	$ 13	$ 13	$ 12
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 Addi

COMMON SHARES - Summary of Additional Stock Options Information (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Total intrinsic value of options exercised	$ 75	$ 10	$ 28
Total fair value of options that have vested	$ 143	$ 101	$ 140
Total options vested (in shares)	2.1	2.1	2.3
Options, exercisable, intrinsic value	$ 76
Options, outstanding, intrinsic value	$ 122

COMMON SHARES - Shareholder Rig

COMMON SHARES - Shareholder Rights Plan (Details)	Dec. 31, 2019shares
Shareholder Rights Plan
Number of rights entitled to each common share (in shares)	1

PREFERRED SHARES (Details)

PREFERRED SHARES (Details) - CAD ($) $ / shares in Units, $ in Millions	Dec. 31, 2019	Oct. 30, 2019	Apr. 30, 2019	Dec. 31, 2015	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Preferred Shares [Line Items]
Carrying Value December 31	$ 3,980				$ 3,980	$ 3,980	$ 3,980
Series 1
Preferred Shares [Line Items]
Number of Shares Outstanding	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				$ 25
Carrying Value December 31	$ 360				$ 360	233	233
Number of preferred shares converted	173,954
Shares issued upon conversion per share of preferred stock	1				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%
Series 2
Preferred Shares [Line Items]
Number of Shares Outstanding	7,423,000				7,423,000
Current Yield					3.572%
Redemption Price Per Share (in Canadian dollars per share)	$ 25				$ 25
Carrying Value December 31	$ 179				$ 179	306	306
Number of preferred shares converted	5,252,715
Shares issued upon conversion per share of preferred stock	1				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%
Series 3
Preferred Shares [Line Items]
Number of Shares Outstanding	8,533,000				8,533,000
Current Yield					2.152%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 0.538
Redemption Price Per Share (in Canadian dollars per share)	$ 25				$ 25
Carrying Value December 31	$ 209				$ 209	209	209
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%
Series 4
Preferred Shares [Line Items]
Number of Shares Outstanding	5,467,000				5,467,000
Current Yield				2.932%
Redemption Price Per Share (in Canadian dollars per share)	$ 25				$ 25
Carrying Value December 31	$ 134				$ 134	134	134
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%
Series 5
Preferred Shares [Line Items]
Number of Shares Outstanding	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				$ 25
Carrying Value December 31	$ 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%
Series 6
Preferred Shares [Line Items]
Number of Shares Outstanding	1,286,000				1,286,000
Current Yield					3.164%
Redemption Price Per Share (in Canadian dollars per share)	$ 25				$ 25
Carrying Value December 31	$ 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%
Series 7
Preferred Shares [Line Items]
Number of Shares Outstanding	24,000,000				24,000,000
Current Yield			4.00%		3.903%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 0.975752
Redemption Price Per Share (in Canadian dollars per share)	$ 25				$ 25
Carrying Value December 31	$ 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%
Series 9
Preferred Shares [Line Items]
Number of Shares Outstanding	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				$ 25
Carrying Value December 31	$ 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%
Series 11
Preferred Shares [Line Items]
Number of Shares Outstanding	10,000,000				10,000,000
Current Yield					3.80%
Annual Dividend Rate per Share (in Canadian dollars per share)					$ 0.95
Redemption Price Per Share (in Canadian dollars per share)	$ 25				$ 25
Carrying Value December 31	$ 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%
Series 13
Preferred Shares [Line Items]
Number of Shares Outstanding	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				$ 25
Carrying Value December 31	$ 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%
Preferred stock, fixed percentage added To Bond Or Treasury Bill rate for calculating dividend yield, minimum	5.50%				5.50%
Series 15
Preferred Shares [Line Items]
Number of Shares Outstanding	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				$ 25
Carrying Value December 31	$ 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%
Preferred stock, fixed percentage added To Bond Or Treasury Bill rate for calculating dividend yield, minimum	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%
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%
Series 12 | Government of Canada, Treasury Bill Rate
Preferred Shares [Line Items]
Fixed percentage added to government of Canada bond or treasury bill rate, for calculating dividend yield per annum						2.96%
Series 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%
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%
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

OTHER COMPREHENSIVE (LOSS)_IN_3

OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Components (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Before Tax Amount
Other Comprehensive Income (Loss)	$ (1,055)	$ 1,259	$ (957)
Income Tax Recovery/(Expense)
Other Comprehensive Income (Loss)	3	55	31
Net of Tax Amount
Other comprehensive (loss)/income (Note 23)	(1,052)	1,314	(926)
Foreign currency translation losses on net investment in foreign operations
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(914)	1,323	(746)
Reclassification from accumulated other comprehensive Income	(13)		(77)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	(30)	35	(3)
Reclassification from AOCI	0		0
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(944)	1,358	(749)
Reclassification from accumulated other comprehensive income	(13)		(77)
Change in fair value of net investment hedges
Before Tax Amount
Other comprehensive income (loss), before reclassifications	46	(57)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	(11)	15
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	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	(78)	(14)	3
Reclassification from accumulated other comprehensive Income	19	27	(3)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	16	4	0
Reclassification from AOCI	(5)	(6)	1
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(62)	(10)	3
Reclassification from accumulated other comprehensive income	14	21	(2)
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)	(153)	(14)
Reclassification from accumulated other comprehensive Income	14	20	21
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	5	39	3
Reclassification from AOCI	(4)	(5)	(5)
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	(10)	(114)	(11)
Reclassification from accumulated other comprehensive income	10	15	16
Other comprehensive loss on equity investments
Before Tax Amount
Other comprehensive income (loss), before reclassifications	(114)
Other Comprehensive Income (Loss)		113	(141)
Income Tax Recovery/(Expense)
Other comprehensive income (loss) before reclassifications	32
Other Comprehensive Income (Loss)		(27)	35
Net of Tax Amount
Other comprehensive income/(loss), before reclassifications	$ (82)
Other comprehensive (loss)/income (Note 23)		$ 86	$ (106)

OTHER COMPREHENSIVE (LOSS)_IN_4

OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reconciliation (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	$ 30,993,000,000	$ 26,891,000,000
Other comprehensive (loss)/income (Note 23)	(1,052,000,000)	1,314,000,000	$ (926,000,000)
Balance at end of year	32,397,000,000	30,993,000,000	26,891,000,000
Reduction for settlement and curtailment	27,000,000
Cash flow hedge loss to be reclassified within twelve months	18,000,000
Cash flow hedge loss to be reclassified within twelve months, net of tax	13,000,000
Currency Translation Adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	107,000,000	(1,043,000,000)	(376,000,000)
Other comprehensive income/(loss), before reclassifications	(824,000,000)	1,150,000,000	(590,000,000)
Net current period other comprehensive (loss)/income	(13,000,000)	0	(77,000,000)
Other comprehensive (loss)/income (Note 23)	(837,000,000)	1,150,000,000	(667,000,000)
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform		0
Balance at end of year	(730,000,000)	107,000,000	(1,043,000,000)
Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(23,000,000)	(31,000,000)	(28,000,000)
Other comprehensive income/(loss), before reclassifications	(49,000,000)	(9,000,000)	(1,000,000)
Net current period other comprehensive (loss)/income	14,000,000	16,000,000	(2,000,000)
Other comprehensive (loss)/income (Note 23)	(35,000,000)	7,000,000	(3,000,000)
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform		1,000,000
Balance at end of year	(58,000,000)	(23,000,000)	(31,000,000)
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)	(203,000,000)	(208,000,000)
Other comprehensive income/(loss), before reclassifications	(10,000,000)	(114,000,000)	(11,000,000)
Net current period other comprehensive (loss)/income	10,000,000	15,000,000	16,000,000
Other comprehensive (loss)/income (Note 23)	0	(99,000,000)	5,000,000
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform		(12,000,000)
Balance at end of year	(314,000,000)	(314,000,000)	(203,000,000)
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(376,000,000)	(454,000,000)	(348,000,000)
Other comprehensive income/(loss), before reclassifications	(86,000,000)	72,000,000	(117,000,000)
Net current period other comprehensive (loss)/income	5,000,000	12,000,000	11,000,000
Other comprehensive (loss)/income (Note 23)	(81,000,000)	84,000,000	(106,000,000)
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform		(6,000,000)
Balance at end of year	(457,000,000)	(376,000,000)	(454,000,000)
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance at beginning of year	(606,000,000)	(1,731,000,000)	(960,000,000)
Other comprehensive income/(loss), before reclassifications	(969,000,000)	1,099,000,000	(719,000,000)
Net current period other comprehensive (loss)/income	16,000,000	43,000,000	(52,000,000)
Other comprehensive (loss)/income (Note 23)	(953,000,000)	1,142,000,000	(771,000,000)
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform		(17,000,000)
Balance at end of year	(1,559,000,000)	(606,000,000)	(1,731,000,000)
Accumulated foreign currency adjustment attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive income/(loss), before reclassifications	(85,000,000)	166,000,000	(159,000,000)
Accumulated net gain (loss) from cash flow hedges attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive income/(loss), before reclassifications	(13,000,000)	(1,000,000)	$ 4,000,000
Net current period other comprehensive (loss)/income	0
Accumulated net gain (loss) from equity investments attributable to noncontrolling interest
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive income/(loss), before reclassifications	$ (1,000,000)	$ 0

OTHER COMPREHENSIVE (LOSS)_IN_5

OTHER COMPREHENSIVE (LOSS)/INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reclassifications (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Storage)	$ 13,255,000,000	$ 13,679,000,000	$ 13,449,000,000
Interest expense	(2,333,000,000)	(2,265,000,000)	(2,069,000,000)
Plant operating costs and other	3,909,000,000	3,591,000,000	3,906,000,000
Income/(loss) from equity investments	920,000,000	714,000,000	773,000,000
(Loss)/gain on assets held for sale/sold	(121,000,000)	170,000,000	631,000,000
Total before tax	5,187,000,000	3,949,000,000	3,306,000,000
Income tax expense	(754,000,000)	(432,000,000)	89,000,000
Net Income Attributable to Common Shares	3,976,000,000	3,539,000,000	2,997,000,000
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before tax	(19,000,000)	(22,000,000)	3,000,000
Income tax expense	5,000,000	6,000,000	(1,000,000)
Net Income Attributable to Common Shares	(14,000,000)	(16,000,000)	2,000,000
Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges | Interest
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(12,000,000)	(18,000,000)	(17,000,000)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Amortization of actuarial gains and losses
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other	(14,000,000)	(16,000,000)	(15,000,000)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Settlement charge
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Plant operating costs and other		(4,000,000)	(2,000,000)
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	(14,000,000)	(20,000,000)	(17,000,000)
Income tax expense	4,000,000	5,000,000	5,000,000
Net Income Attributable to Common Shares	(10,000,000)	(15,000,000)	(12,000,000)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income/(loss) from equity investments	(8,000,000)	(16,000,000)	(15,000,000)
Income tax expense	3,000,000	4,000,000	4,000,000
Net Income Attributable to Common Shares	(5,000,000)	(12,000,000)	(11,000,000)
Amounts Reclassified From Accumulated Other Comprehensive Loss | Currency translation adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
(Loss)/gain on assets held for sale/sold	13,000,000	0	77,000,000
Income tax expense		0	0
Net Income Attributable to Common Shares	13,000,000	0	77,000,000
Amounts Reclassified From Accumulated Other Comprehensive Loss | Accumulated net gain (loss) from cash flow hedges attributable to noncontrolling interest
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net Income Attributable to Common Shares	0	5,000,000	0
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	2,000,000	0
Power and Storage | Amounts Reclassified From Accumulated Other Comprehensive Loss | Cash flow hedges | Commodities
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Power and Storage)	$ (7,000,000)	$ (4,000,000)	$ 20,000,000

EMPLOYEE POST-RETIREMENT BENE_3

EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments, Changes and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized		11 years	12 years	12 years
Expense for savings plan and DC Plans		$ 61	$ 59	$ 42
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Savings and DC Plans		61	59	42
Total cash contributions		205	185	$ 212
Reduction for settlement and curtailment		27
Change in Plan Assets
Plan assets at fair value – beginning of year		3,697
Plan assets at fair value – end of year	$ 3,697	4,099	3,697
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 13)	192	162	192
Other long-term liabilities (Note 16)	(569)	$ (540)	$ (569)
Pension Benefit Plans
Employee post-retirement benefits
Consecutive period of employment for highest average earnings		5 years	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		$ 122	$ 103	$ 163
Total amount outstanding under letters of credit	17	12	17
Change in Benefit Obligation
Benefit obligation – beginning of year		3,653	3,646
Service cost		126	121
Interest cost		142	134
Employee contributions		5	5
Benefits paid		(213)	(177)
Actuarial loss/(gain)		394	(92)
Settlement		0	(71)
Foreign exchange rate changes		(49)	87
Benefit obligation – end of year	3,653	4,058	3,653	3,646
Change in Plan Assets
Plan assets at fair value – beginning of year		3,321	3,451
Actual return on plan assets		505	(73)
Employer contributions		122	103
Employee contributions		5	5
Benefits paid		(212)	(176)
Settlement		0	(71)
Foreign exchange rate changes		(48)	82
Plan assets at fair value – end of year	3,321	3,693	3,321	3,451
Funded Status – Plan Deficit	(332)	(365)	(332)
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 13)	0	0	0
Accounts payable and other	(1)	0	(1)
Other long-term liabilities (Note 16)	(331)	(365)	(331)
Net	(332)	(365)	(332)
Other Post-Retirement Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
DB Plans and Other post-retirement benefit plans		22	23	7
Change in Benefit Obligation
Benefit obligation – beginning of year		430	375
Service cost		5	4
Interest cost		17	14
Employee contributions		0	0
Benefits paid		(24)	(23)
Actuarial loss/(gain)		13	43
Settlement		0	0
Foreign exchange rate changes		(14)	17
Benefit obligation – end of year	430	427	430	375
Change in Plan Assets
Plan assets at fair value – beginning of year		376	365
Actual return on plan assets		52	(15)
Employer contributions		22	23
Employee contributions		0	0
Benefits paid		(24)	(27)
Settlement		0	0
Foreign exchange rate changes		(20)	30
Plan assets at fair value – end of year	376	406	376	365
Funded Status – Plan Deficit	(54)	(21)	(54)
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 13)	192	162	192
Accounts payable and other	(8)	(8)	(8)
Other long-term liabilities (Note 16)	(238)	(175)	(238)
Net	(54)	(21)	(54)
Canadian | Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Letter of credit to the DB Plan		12	$ 17	27
Total amount outstanding under letters of credit		$ 289
U.S. | Pension Benefit Plans
Defined Benefits, Contribution And Other Postretirement Plan Contributions [Abstract]
Reduction for settlement and curtailment	4			3
Net periodic benefit cost, settlement charge	$ 4			$ 2

EMPLOYEE POST-RETIREMENT BENE_4

EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Benefit obligation and fair value of plan assets for plans that are not fully funded
Plan assets at fair value	$ 4,099	$ 3,697
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	$ (4,058)	$ (3,653)	$ (3,646)
Plan assets at fair value	3,693	3,321	3,451
Funded Status – Plan Deficit	(365)	(332)
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(3,719)	(3,347)
Plan assets at fair value	3,693	3,321
Funded Status	$ (26)	$ (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	32.00%	33.00%
Company debt or common shares included in plan assets, amount	$ 9	$ 8
Company debt or common shares included in plan assets, percentage	0.20%	0.30%
Pension Benefit Plans | Debt securities | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	25.00%
Pension Benefit Plans | Debt securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	45.00%
Pension Benefit Plans | Equity securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	58.00%	56.00%
Company debt or common shares included in plan assets, amount	$ 15	$ 7
Company debt or common shares included in plan assets, percentage	0.40%	0.20%
Pension Benefit Plans | Equity securities | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	40.00%
Pension Benefit Plans | Equity securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	70.00%
Pension Benefit Plans | Alternatives
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	10.00%	11.00%
Pension Benefit Plans | Alternatives | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	5.00%
Pension Benefit Plans | Alternatives | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	15.00%
Pension Benefit Plans | Not fully funded
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	$ (4,058)	$ (3,653)
Plan assets at fair value	3,693	3,321
Funded Status – Plan Deficit	(365)	(332)
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(2,397)	(3,347)
Plan assets at fair value	2,351	3,321
Funded Status	(46)	(26)
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	(427)	(430)	(375)
Plan assets at fair value	406	376	$ 365
Funded Status – Plan Deficit	(21)	(54)
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	(182)	(246)
Plan assets at fair value	0	0
Funded Status – Plan Deficit	$ (182)	$ (246)

EMPLOYEE POST-RETIREMENT BENE_5

EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Employee post-retirement benefits
Fair value of plan assets	$ 4,099	$ 3,697
Percentage of Total Portfolio	100.00%	100.00%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 1,860	$ 1,817
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1,860	1,518
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	379	362	$ 216
Cash and Cash Equivalents
Employee post-retirement benefits
Fair value of plan assets	$ 58	$ 48
Percentage of Total Portfolio	1.00%	1.00%
Cash and Cash Equivalents | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 58	$ 48
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	$ 591	$ 493
Percentage of Total Portfolio	14.00%	13.00%
Equity Securities, Canadian | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 402	$ 355
Equity Securities, Canadian | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	189	138
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	$ 679	$ 576
Percentage of Total Portfolio	17.00%	16.00%
Equity Securities, U.S. | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 523	$ 460
Equity Securities, U.S. | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	156	116
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	$ 366	$ 321
Percentage of Total Portfolio	9.00%	9.00%
Equity Securities, International | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 46	$ 40
Equity Securities, International | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	320	281
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	$ 433	$ 384
Percentage of Total Portfolio	11.00%	10.00%
Equity Securities, Global | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 136	$ 116
Equity Securities, Global | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	297	268
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	$ 134	$ 146
Percentage of Total Portfolio	3.00%	4.00%
Equity Securities, Emerging | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 8	$ 8
Equity Securities, Emerging | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	126	138
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	$ 198	$ 186
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	198	186
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	$ 246	$ 198
Percentage of Total Portfolio	6.00%	5.00%
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	246	198
Fixed Income Securities, Canadian Bonds, Provincial | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, Canadian Bonds, Municipal
Employee post-retirement benefits
Fair value of plan assets	$ 12	$ 8
Percentage of Total Portfolio	0.00%	1.00%
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	12	8
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	$ 125	$ 112
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	125	112
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	$ 428	$ 350
Percentage of Total Portfolio	11.00%	9.00%
Fixed Income Securities, U.S. Bonds, Federal | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 421	$ 350
Fixed Income Securities, U.S. Bonds, Federal | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	7	0
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, State
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Percentage of Total Portfolio	0.00%	0.00%
Fixed Income Securities, U.S. Bonds, State | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, U.S. Bonds, State | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, U.S. Bonds, State | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, U.S. Bonds, Municipal
Employee post-retirement benefits
Fair value of plan assets	$ 1	$ 0
Percentage of Total Portfolio	0.00%	0.00%
Fixed Income Securities, U.S. Bonds, Municipal | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0
Fixed Income Securities, U.S. Bonds, Municipal | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1	0
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	$ 187	$ 196
Percentage of Total Portfolio	5.00%	5.00%
Fixed Income Securities, U.S. Bonds, Corporate | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 67	$ 145
Fixed Income Securities, U.S. Bonds, Corporate | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	120	51
Fixed Income Securities, U.S. Bonds, Corporate | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	0	0
Fixed Income Securities, International, Government
Employee post-retirement benefits
Fair value of plan assets	$ 11	$ 10
Percentage of Total Portfolio	0.00%	1.00%
Fixed Income Securities, International, Government | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 7	$ 6
Fixed Income Securities, International, Government | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	4	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	$ 52	$ 37
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	$ 19
Fixed Income Securities, International, Corporate | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	52	18
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	$ 53	$ 128
Percentage of Total Portfolio	1.00%	3.00%
Fixed Income Securities, International, Mortgage-backed | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 46	$ 128
Fixed Income Securities, International, Mortgage-backed | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	7	0
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	$ 196	$ 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	196	196
Infrastructure
Employee post-retirement benefits
Fair value of plan assets	$ 181	$ 163
Percentage of Total Portfolio	4.00%	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	181	163
Private equity funds
Employee post-retirement benefits
Fair value of plan assets	$ 2	$ 3
Percentage of Total Portfolio	0.00%	1.00%
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	2	3
Funds held on deposit
Employee post-retirement benefits
Fair value of plan assets	$ 146	$ 142
Percentage of Total Portfolio	4.00%	4.00%
Funds held on deposit | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	$ 146	$ 142
Funds held on deposit | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	0	0
Funds held on deposit | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	$ 0	$ 0

EMPLOYEE POST-RETIREMENT BENE_6

EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	$ 3,697
Plan assets at fair value – end of year	4,099	$ 3,697
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	362	216
Purchases and sales	35	127
Realized and unrealized losses	(18)	19
Plan assets at fair value – end of year	$ 379	$ 362

EMPLOYEE POST-RETIREMENT BENE_7

EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions for savings plan and DC Plans	$ 62
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	4.50%
Effects of a one per cent change in assumed health care cost trend rates
Effect on total of service and interest cost components, Increase	$ 2
Effect on total of service and interest cost components, Decrease	(2)
Effect on post-retirement benefit obligation, Increase	31
Effect on post-retirement benefit obligation, Decrease	(25)
Pension Benefit Plans
DB Plans
Company's expected funding contributions	116
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	12
Estimated future benefit payments, which reflect expected future service
2020	195
2021	199
2022	203
2023	207
2024	209
2025 to 2029	$ 1,084
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	3.20%	3.90%
Rate of compensation increase	3.00%	3.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	3.90%	3.60%	3.95%
Expected long-term rate of return on plan assets	6.60%	6.70%	6.50%
Rate of compensation increase	3.00%	3.00%	1.20%
Net benefit cost
Service cost	$ 126	$ 121	$ 108
Other components of net benefit cost
Interest cost	142	134	122
Expected return on plan assets	(222)	(221)	(178)
Amortization of actuarial loss	12	15	14
Amortization of regulatory asset	14	18	37
Settlement charge – regulatory asset	0	0	2
Settlement charge – AOCI	0	4	2
Other components of net benefit cost	(54)	(50)	(1)
Net Benefit Cost Recognized	72	71	107
Pre-tax amounts recognized in AOCI
Net loss	398	364	273
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	21
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to net income	(12)	(15)	(18)
Curtailment	0	0	(14)
Settlement	0	(4)	(11)
Funded status adjustment	52	110	46
Total pre-tax amounts recognized in OCI	40	$ 91	$ 3
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	7
Estimated future benefit payments, which reflect expected future service
2020	25
2021	25
2022	24
2023	24
2024	24
2025 to 2029	$ 117
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	3.35%	4.10%
Rate of compensation increase	0.00%	0.00%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	4.10%	3.70%	4.15%
Expected long-term rate of return on plan assets	4.30%	4.00%	6.05%
Rate of compensation increase	0.00%	0.00%	0.00%
Net benefit cost
Service cost	$ 5	$ 4	$ 4
Other components of net benefit cost
Interest cost	17	14	14
Expected return on plan assets	(15)	(16)	(21)
Amortization of actuarial loss	2	1	1
Amortization of regulatory asset	2	0	1
Settlement charge – regulatory asset	0	0	0
Settlement charge – AOCI	0	0	0
Other components of net benefit cost	6	(1)	(5)
Net Benefit Cost Recognized	11	3	(1)
Pre-tax amounts recognized in AOCI
Net loss	20	53	11
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	2
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to net income	(2)	(1)	(1)
Curtailment	0	0	(2)
Settlement	0	0	0
Funded status adjustment	(37)	43	(7)
Total pre-tax amounts recognized in OCI	$ (39)	$ 42	$ (10)

RISK MANAGEMENT AND FINANCIAL_3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Derivative [Line Items]
Fair Value	$ 1,000,000	$ (166,000,000)
Designated as a net investment hedge
Derivative [Line Items]
Fair Value	13,000,000	(90,000,000)
Designated as a net investment hedge | US$ denominated
Derivative [Line Items]
Notional Amount			$ 3,100	$ 2,800
Designated as a net investment hedge | U.S. dollar cross-currency interest rate swaps (maturing 2019)
Derivative [Line Items]
Fair Value	3,000,000	(43,000,000)
Designated as a net investment hedge | U.S. dollar cross-currency interest rate swaps (maturing 2019) | US$ denominated
Derivative [Line Items]
Notional Amount			100	300
Net realized gains related to the interest component	0	2,000,000
Designated as a net investment hedge | U.S. dollar foreign exchange options (maturing 2020 to 2021)
Derivative [Line Items]
Fair Value	$ 10,000,000	$ (47,000,000)
Designated as a net investment hedge | U.S. dollar foreign exchange options (maturing 2020 to 2021) | US$ denominated
Derivative [Line Items]
Notional Amount			$ 3,000	$ 2,500

RISK MANAGEMENT AND FINANCIAL_4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - U.S. Dollar-Denominated Debt Designated as Net Investment Hedges (Details) - Designated as a net investment hedge $ in Millions, $ in Millions	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)
Derivative [Line Items]
Notional amount	$ 29,300		$ 31,000
Fair value	$ 33,400		$ 31,700
US$ denominated
Derivative [Line Items]
Notional amount		$ 22,600		$ 22,700
Fair value		$ 25,700		$ 23,200

RISK MANAGEMENT AND FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Concentration Risk [Line Items]
Financing receivable, recorded investment, past due	$ 0	$ 0
Provision for other credit losses	0	0
Customer Concentration Risk
Concentration Risk [Line Items]
Credit risk concentration	$ 0	$ 0

RISK MANAGEMENT AND FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion (Note 17)	$ (37,019)	$ (39,982)
Junior subordinated notes (Note 19)	(8,614)	(7,508)
Long-term debt			$ 200	$ 750
Interest rate swap agreements
Carrying and fair values of non-derivative financial instruments
Unrealized losses on hedged items	3	2
Long-term debt hedged			$ 200	$ 750
Level II | Carrying Amount
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion (Note 17)	(36,985)	(39,971)
Junior subordinated notes (Note 19)	(8,614)	(7,508)
Total liabilities	(45,599)	(47,479)
Level II | Fair Value
Carrying and fair values of non-derivative financial instruments
Long-term debt, including current portion (Note 17)	(43,187)	(42,284)
Junior subordinated notes (Note 19)	(8,777)	(6,665)
Total liabilities	$ (51,964)	$ (48,949)

RISK MANAGEMENT AND FINANCIAL_7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Total Derivatives
Derivative Assets	$ 197	$ 798
Derivative Liabilities	(196)	(964)
Total Derivatives	1	(166)
Total trading activity
Total Derivatives
Derivative Assets	179	767
Derivative Liabilities	(118)	(838)
Total Derivatives	61	(71)
Cash Flow Hedges
Total Derivatives
Derivative Assets	2	13
Derivative Liabilities	(76)	(15)
Total Derivatives	(74)	(2)
Fair Value Hedges
Total Derivatives
Derivative Assets	1	1
Derivative Liabilities	0	(4)
Total Derivatives	1	(3)
Net Investment Hedges
Total Derivatives
Derivative Assets	15	17
Derivative Liabilities	(2)	(107)
Total Derivatives	13	(90)
Other current assets
Total Derivatives
Derivative Assets	190	737
Other current assets | Total trading activity
Total Derivatives
Derivative Assets	179	717
Other current assets | Cash Flow Hedges
Total Derivatives
Derivative Assets	0	4
Other current assets | Fair Value Hedges
Total Derivatives
Derivative Assets	1	0
Other current assets | Net Investment Hedges
Total Derivatives
Derivative Assets	10	16
Other current assets | Commodities
Total Derivatives
Derivative Assets	118	717
Other current assets | Commodities | Commodities
Total Derivatives
Derivative Assets	118	716
Other current assets | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Assets	0	1
Other current assets | Commodities | Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets | Commodities | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Other current assets | Foreign exchange
Total Derivatives
Derivative Assets	71	17
Other current assets | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Assets	61	1
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	0
Other current assets | Foreign exchange | Net Investment Hedges
Total Derivatives
Derivative Assets	10	16
Other current assets | Interest rate
Total Derivatives
Derivative Assets	1	3
Other current assets | Interest rate | Interest rate
Total Derivatives
Derivative Assets	0	0
Other current assets | Interest rate | Cash Flow Hedges
Total Derivatives
Derivative Assets	0	3
Other current assets | Interest rate | Fair Value Hedges
Total Derivatives
Derivative Assets	1	0
Other current assets | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Intangible and other assets
Total Derivatives
Derivative Assets	7	61
Intangible and other assets | Total trading activity
Total Derivatives
Derivative Assets	0	50
Intangible and other assets | Cash Flow Hedges
Total Derivatives
Derivative Assets	2	9
Intangible and other assets | Fair Value Hedges
Total Derivatives
Derivative Assets	0	1
Intangible and other assets | Net Investment Hedges
Total Derivatives
Derivative Assets	5	1
Intangible and other assets | Commodities
Total Derivatives
Derivative Assets		51
Intangible and other assets | Commodities | Commodities
Total Derivatives
Derivative Assets		50
Intangible and other assets | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Assets		1
Intangible and other assets | Commodities | Fair Value Hedges
Total Derivatives
Derivative Assets		0
Intangible and other assets | Commodities | Net Investment Hedges
Total Derivatives
Derivative Assets		0
Intangible and other assets | Foreign exchange
Total Derivatives
Derivative Assets	5	1
Intangible and other assets | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Assets	0	0
Intangible and other assets | Foreign exchange | Cash Flow Hedges
Total Derivatives
Derivative Assets	0	0
Intangible and other assets | Foreign exchange | Fair Value Hedges
Total Derivatives
Derivative Assets	0	0
Intangible and other assets | Foreign exchange | Net Investment Hedges
Total Derivatives
Derivative Assets	5	1
Intangible and other assets | Interest rate
Total Derivatives
Derivative Assets	2	9
Intangible and other assets | Interest rate | Interest rate
Total Derivatives
Derivative Assets	0	0
Intangible and other assets | Interest rate | Cash Flow Hedges
Total Derivatives
Derivative Assets	2	8
Intangible and other assets | Interest rate | Fair Value Hedges
Total Derivatives
Derivative Assets	0	1
Intangible and other assets | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Assets	0	0
Accounts payable and other
Total Derivatives
Derivative Liabilities	(115)	(922)
Accounts payable and other | Total trading activity
Total Derivatives
Derivative Liabilities	(107)	(810)
Accounts payable and other | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(7)	(4)
Accounts payable and other | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	(3)
Accounts payable and other | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(1)	(105)
Accounts payable and other | Commodities
Total Derivatives
Derivative Liabilities	(108)	(626)
Accounts payable and other | Commodities | Commodities
Total Derivatives
Derivative Liabilities	(104)	(622)
Accounts payable and other | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(4)	(4)
Accounts payable and other | Commodities | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	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	(4)	(293)
Accounts payable and other | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Liabilities	(3)	(188)
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	0
Accounts payable and other | Foreign exchange | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(1)	(105)
Accounts payable and other | Interest rate
Total Derivatives
Derivative Liabilities	(3)	(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	(3)	0
Accounts payable and other | Interest rate | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	(3)
Accounts payable and other | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities (Note 16)
Total Derivatives
Derivative Liabilities	(81)	(42)
Other long-term liabilities (Note 16) | Total trading activity
Total Derivatives
Derivative Liabilities	(11)	(28)
Other long-term liabilities (Note 16) | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(69)	(11)
Other long-term liabilities (Note 16) | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	(1)
Other long-term liabilities (Note 16) | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(1)	(2)
Other long-term liabilities (Note 16) | Commodities
Total Derivatives
Derivative Liabilities	(17)	(28)
Other long-term liabilities (Note 16) | Commodities | Commodities
Total Derivatives
Derivative Liabilities	(11)	(28)
Other long-term liabilities (Note 16) | Commodities | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(6)	0
Other long-term liabilities (Note 16) | Commodities | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities (Note 16) | Commodities | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities (Note 16) | Foreign exchange
Total Derivatives
Derivative Liabilities	(1)	(2)
Other long-term liabilities (Note 16) | Foreign exchange | Foreign exchange
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities (Note 16) | Foreign exchange | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities (Note 16) | Foreign exchange | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities (Note 16) | Foreign exchange | Net Investment Hedges
Total Derivatives
Derivative Liabilities	(1)	(2)
Other long-term liabilities (Note 16) | Interest rate
Total Derivatives
Derivative Liabilities	(63)	(12)
Other long-term liabilities (Note 16) | Interest rate | Interest rate
Total Derivatives
Derivative Liabilities	0	0
Other long-term liabilities (Note 16) | Interest rate | Cash Flow Hedges
Total Derivatives
Derivative Liabilities	(63)	(11)
Other long-term liabilities (Note 16) | Interest rate | Fair Value Hedges
Total Derivatives
Derivative Liabilities	0	(1)
Other long-term liabilities (Note 16) | Interest rate | Net Investment Hedges
Total Derivatives
Derivative Liabilities	0	0
LMCI Restricted Investments
Fair value
Fair value of equity securities	556	0
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains/(losses)	32	11	$ (3)
Net realized gains/(losses)	60	(4)	(1)
Other Restricted Investments
Fair value
Fair value of equity securities	0	0
Gain (Loss) on Investments, Realized and Unrealized
Net unrealized gains/(losses)	3	0	1
Net realized gains/(losses)	0	0	$ 0
Fixed income securities | LMCI Restricted Investments
Fair value
Maturing within 1 year	0	0
Maturing within 1-5 years	26	0
Maturing within 5-10 years	801	140
Maturing after 10 years	61	952
Fair value of securities	1,444	1,092
Fixed income securities | Other Restricted Investments
Fair value
Maturing within 1 year	6	22
Maturing within 1-5 years	100	110
Maturing within 5-10 years	0	0
Maturing after 10 years	0	0
Fair value of securities	$ 106	$ 132

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Fair Value Hedging Relationships (Details) - CAD ($)	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value hedging adjustments, discontinued hedges	$ 0	$ 0
Current portion of long-term debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Carrying amount	0	(748,000,000)
Fair value hedging adjustments	0	3,000,000
Long-term debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Carrying amount	(260,000,000)	(273,000,000)
Fair value hedging adjustments	(1,000,000)	0
Long-term debt, including current portion
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Carrying amount	(260,000,000)	(1,021,000,000)
Fair value hedging adjustments	$ (1,000,000)	$ 3,000,000

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional and Maturity Summary (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019MXN ($)GWhBcfMMBbls	Dec. 31, 2018USD ($)GWhBcfMMBbls	Dec. 31, 2019USD ($)
Commodities | Power | Purchases
Derivative [Line Items]
Notional amount, energy (gwh) | GWh	492	23,865
Commodities | Power | Sales
Derivative [Line Items]
Notional amount, energy (gwh) | GWh	2,089	17,689
Commodities | Natural Gas | Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | Bcf	14	44
Commodities | Natural Gas | Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | Bcf	22	56
Commodities | Liquids | Purchases
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | MMBbls	39	59
Commodities | Liquids | Sales
Derivative [Line Items]
Notional amount, volume (bcf and mmbbls) | MMBbls	53	79
Foreign exchange
Derivative [Line Items]
Notional amount	$ 800	$ 3,862	$ 3,153
Interest rate
Derivative [Line Items]
Notional amount | $		$ 1,650	$ 1,600

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses)/Gains (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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 gains/(losses) in the year	(111,000,000)	28,000,000	62,000,000
Amount of realized gains/(losses) in the year	378,000,000	351,000,000	(107,000,000)
Commodities | Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	(6,000,000)	(1,000,000)	23,000,000
Foreign exchange
Derivative [Line Items]
Amount of unrealized gains/(losses) in the year	245,000,000	(248,000,000)	88,000,000
Amount of realized gains/(losses) in the year	(70,000,000)	(24,000,000)	18,000,000
Foreign exchange | Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	0	0	5,000,000
Interest rate
Derivative [Line Items]
Amount of unrealized gains/(losses) in the year	0	0	(1,000,000)
Amount of realized gains/(losses) in the year	0	0	1,000,000
Interest rate | Derivative instruments in hedging relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	$ 2,000,000	$ (1,000,000)	$ 1,000,000

RISK MANAGEMENT AND FINANCIA_11

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - Cash Flow Hedges - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	$ (78)	$ (14)	$ 3
Commodities | Power
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	(15)	(1)	(1)
Interest rate
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	$ (63)	$ (13)	$ 4

RISK MANAGEMENT AND FINANCIA_12

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Effect of Fair Value and Cash Flow Hedging Relationships (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest Expense | Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged items	$ (19)	$ (71)	$ (74)
Derivatives designated as hedging instruments	1	(4)	1
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	(12)	(22)	(17)
Revenue | Commodity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification of gains/(losses) on derivative instruments from AOCI to net income	$ (7)	$ (5)	$ 20

RISK MANAGEMENT AND FINANCIA_13

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD ($)	Dec. 31, 2019	Dec. 31, 2018
Derivative instrument assets
Gross Derivative Instruments	$ 197,000,000	$ 798,000,000
Amounts Available for Offset	(82,000,000)	(648,000,000)
Net Amounts	115,000,000	150,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(196,000,000)	(964,000,000)
Amounts Available for Offset	82,000,000	648,000,000
Net Amounts	(114,000,000)	(316,000,000)
Cash collateral provided by the Company	58,000,000	143,000,000
Letters of credit provided by the Company	25,000,000	22,000,000
Cash collateral received by the Company	0	0
Letters of credit received by the Company	0	1,000,000
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	4,000,000	6,000,000
Additional collateral required if credit-risk-related contingent features were triggered	4,000,000	6,000,000
Foreign exchange
Derivative instrument assets
Gross Derivative Instruments	76,000,000	18,000,000
Amounts Available for Offset	(5,000,000)	(18,000,000)
Net Amounts	71,000,000	0
Derivative instrument liabilities
Gross Derivative Instruments	(5,000,000)	(295,000,000)
Amounts Available for Offset	5,000,000	18,000,000
Net Amounts	0	(277,000,000)
Interest rate
Derivative instrument assets
Gross Derivative Instruments	3,000,000	12,000,000
Amounts Available for Offset	(1,000,000)	(4,000,000)
Net Amounts	2,000,000	8,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(66,000,000)	(15,000,000)
Amounts Available for Offset	1,000,000	4,000,000
Net Amounts	(65,000,000)	(11,000,000)
Power | Commodities
Derivative instrument assets
Gross Derivative Instruments	118,000,000	768,000,000
Amounts Available for Offset	(76,000,000)	(626,000,000)
Net Amounts	42,000,000	142,000,000
Derivative instrument liabilities
Gross Derivative Instruments	(125,000,000)	(654,000,000)
Amounts Available for Offset	76,000,000	626,000,000
Net Amounts	$ (49,000,000)	$ (28,000,000)

RISK MANAGEMENT AND FINANCIA_14

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value Hierarchy
Derivative Instrument Assets	$ 197	$ 798
Derivative Instrument Liabilities	(196)	(964)
Recurring basis
Fair Value Hierarchy
Assets and (liabilities), net	1	(166)
Recurring basis | Commodities | Power
Fair Value Hierarchy
Derivative Instrument Assets	118	768
Derivative Instrument Liabilities	(125)	(654)
Recurring basis | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets	76	18
Derivative Instrument Liabilities	(5)	(295)
Recurring basis | Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	3	12
Derivative Instrument Liabilities	(66)	(15)
Recurring basis | Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	4	26
Recurring basis | Quoted Prices in Active Markets (Level I) | Commodities | Power
Fair Value Hierarchy
Derivative Instrument Assets	81	581
Derivative Instrument Liabilities	(77)	(555)
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	0
Derivative Instrument Liabilities	0	0
Recurring basis | Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Assets and (liabilities), net	4	(188)
Recurring basis | Significant Other Observable Inputs (Level II) | Commodities | Power
Fair Value Hierarchy
Derivative Instrument Assets	37	187
Derivative Instrument Liabilities	(41)	(95)
Recurring basis | Significant Other Observable Inputs (Level II) | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets	76	18
Derivative Instrument Liabilities	(5)	(295)
Recurring basis | Significant Other Observable Inputs (Level II) | Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	3	12
Derivative Instrument Liabilities	(66)	(15)
Recurring basis | Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	(7)	(4)
Recurring basis | Significant Unobservable Inputs (Level III) | Commodities | Power
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Derivative Instrument Liabilities	(7)	(4)
Recurring basis | Significant Unobservable Inputs (Level III) | Foreign exchange
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Derivative Instrument Liabilities	0	0
Recurring basis | Significant Unobservable Inputs (Level III) | Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	0	0
Derivative Instrument Liabilities	$ 0	$ 0

RISK MANAGEMENT AND FINANCIA_15

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue
Net change in the Level III fair value category
Unrealized losses attributed to derivatives in the Level III category	$ 3	$ 5
Commodity contracts | Power
Net change in the Level III fair value category
Balance at beginning of year	(4)	(7)
Transfers out of Level III	4	5
Total (losses)/gains included in Net income	(3)	8
Total losses included in OCI	(4)	0
Settlements	0	(9)
Foreign exchange	0	(1)
Balance at end of year	$ (7)	$ (4)

CHANGES IN OPERATING WORKING _3

CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CHANGES IN OPERATING WORKING CAPITAL
Decrease/(increase) in Accounts receivable	$ 31	$ (69)	$ (576)
Increase in Inventories	(42)	(49)	(38)
Decrease in Assets held for sale	0	0	14
(Increase)/decrease in Other current assets	(15)	45	189
Increase/(decrease) in Accounts payable and other	352	(70)	151
(Decrease)/increase in Accrued interest	(33)	41	12
Decrease in Liabilities related to Assets held for sale	0	0	(25)
Decrease/(increase) in Operating Working Capital	$ 293	$ (102)	$ (273)

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Details) $ in Millions, $ in Millions

Aug. 01, 2019CAD ($)

Aug. 01, 2019USD ($)

Jul. 17, 2019CAD ($)

Jul. 16, 2019USD ($)

May 21, 2019CAD ($)

Oct. 24, 2018CAD ($)

Dec. 19, 2017CAD ($)

Jun. 02, 2017USD ($)

Jun. 01, 2017USD ($)

Apr. 19, 2017USD ($)

Jul. 31, 2019CAD ($)

Apr. 30, 2017CAD ($)

Dec. 31, 2019CAD ($)

Dec. 31, 2018CAD ($)

Dec. 31, 2017CAD ($)

Dec. 31, 2016CAD ($)

May 21, 2019USD ($)

Business Acquisition [Line Items]

Proceeds from sale of assets, net of transaction costs

$ 2,398

$ 614

$ 4,683

Goodwill

12,887

14,178

Gain on sale

(121)

170

631

Ravenswood, Ironwood, Kibby Wind and Ocean State Power

Business Acquisition [Line Items]

Proceeds from sale of assets, net of transaction costs

$ 2,029

Gain (loss) on disposition of property plant equipment

$ (829)

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

(863)

U.S. Natural Gas Pipelines

Business Acquisition [Line Items]

Goodwill

$ 12,887

14,178

13,084

Columbia Midstream assets

Business Acquisition [Line Items]

Proceeds from sale of assets, net of transaction costs

$ 1,300

Gain (loss) on disposition of property plant equipment

$ 21

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

(152)

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

4

Goodwill

$ 595

Iroquois | U.S. Natural Gas Pipelines

Business Acquisition [Line Items]

Ownership interest percentage

0.66%

50.00%

50.00%

Northern Courier pipeline | Liquids Pipelines

Business Acquisition [Line Items]

Ownership interest percentage

15.00%

15.00%

Ontario Solar Assets

Business Acquisition [Line Items]

Proceeds from sale of assets, net of transaction costs

$ 541

Gain (loss) on disposition of property plant equipment

127

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

$ 136

TC Hydro

Business Acquisition [Line Items]

Proceeds from sale of assets, net of transaction costs

$ 1,070

Gain (loss) on disposition of property plant equipment

$ 715

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

440

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

$ 5

Income tax recovery related to sale

$ 27

Ravenswood, Ironwood, Kibby Wind and Ocean State Power

Business Acquisition [Line Items]

Gain (loss) on disposition of property plant equipment

(211)

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

(167)

Foreign currency translation gain on assets held for sale

$ 2

$ 70

Disposal group, disposed of by sale, not discontinued operations | PNGTS And Iroquois Transmission systems

Business Acquisition [Line Items]

Total consideration

$ 765

Cash received

597

Assumption of debt by purchaser

$ 168

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

Business Acquisition [Line Items]

Ownership interest before transaction

85.00%

Total consideration

$ 144

Gain on sale

69

Gain on sale, net of tax

$ 115

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

Business Acquisition [Line Items]

Total consideration

$ 448

Gain on sale

$ 68

Gain on sale, net of tax

54

Foreign currency translation gain

$ 9

Disposal group, disposed of by sale, not discontinued operations | Cartier Wind

Business Acquisition [Line Items]

Proceeds from sale of assets, net of transaction costs

$ 630

Gain (loss) on disposition of property plant equipment

170

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

$ 143

Ownership interest before transaction

62.00%

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

Business Acquisition [Line Items]

Ownership interest before transaction

49.34%

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

Business Acquisition [Line Items]

Ownership interest before transaction

11.81%

Northern Courier pipeline | Senior Secured Notes due June 2042

Business Acquisition [Line Items]

Proceeds from issuance of debt

$ 1,000

$ 1,000

COMMITMENTS, CONTINGENCIES AN_3

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Narrative (Details) - CAD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Commitments
Purchase commitment		$ 236	$ 207	$ 214
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites	$ 39	39	$ 40
Canadian Natural Gas Pipelines | Capital expenditures
Other Commitments
Purchase commitment		4,500
U.S. Natural Gas Pipelines | Capital expenditures
Other Commitments
Purchase commitment		100
Mexico Natural Gas Pipelines | Capital expenditures
Other Commitments
Purchase commitment		200
Liquids Pipelines | Capital expenditures
Other Commitments
Purchase commitment		200
Power and Storage | Capital expenditures
Other Commitments
Purchase commitment		$ 700
KKR and AIMCo | Disposal group, disposed of by sale, not discontinued operations | Coastal GasLink pipeline project
Other Commitments
Equity interest	65.00%

COMMITMENTS, CONTINGENCIES AN_4

COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) - Contingent financial obligation - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Guarantees
Potential Exposure	$ 597	$ 375
Carrying Value	37	12
Northern Courier pipeline
Guarantees
Potential Exposure	300	0
Carrying Value	27	0
Sur de Texas
Guarantees
Potential Exposure	109	183
Carrying Value	0	1
Bruce Power
Guarantees
Potential Exposure	88	88
Carrying Value	0	0
Other jointly-owned entities
Guarantees
Potential Exposure	100	104
Carrying Value	$ 10	$ 11

CORPORATE RESTRUCTURING COSTS_2

CORPORATE RESTRUCTURING COSTS (Details) $ in Millions	Dec. 31, 2019CAD ($)
Restructuring Cost and Reserve [Line Items]
Cumulative recoverable restructuring costs	$ 158
Employee Severance
Restructuring Cost and Reserve [Line Items]
Cumulative restructuring costs incurred	86
Lease Commitments
Restructuring Cost and Reserve [Line Items]
Cumulative restructuring costs incurred	$ 61

CORPORATE RESTRUCTURING COSTS -

CORPORATE RESTRUCTURING COSTS - Schedule of Change In Restructuring Liability (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Restructuring Reserve [Roll Forward]
Restructuring liability as at the beginning of period	$ 81	$ 62
Restructuring charges		42
Accretion expense	2	1
Cash payments	(14)	(24)
Restructuring liability as at the end of period	69	81
Recoverable restructuring costs incurred		21
Employee Severance
Restructuring Reserve [Roll Forward]
Restructuring liability as at the beginning of period	0	9
Restructuring charges		0
Accretion expense	0	0
Cash payments	0	(9)
Restructuring liability as at the end of period	0	0
Lease Commitments
Restructuring Reserve [Roll Forward]
Restructuring liability as at the beginning of period	81	53
Restructuring charges		42
Accretion expense	2	1
Cash payments	(14)	(15)
Restructuring liability as at the end of period	$ 69	$ 81

VARIABLE INTEREST ENTITIES - Na

VARIABLE INTEREST ENTITIES - Narrative (Details)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable interest entity ownership percentage	100.00%

VARIABLE INTEREST ENTITIES - As

VARIABLE INTEREST ENTITIES - Assets and Liabilities of Variable Interest Entities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 1,343		$ 446
Accounts receivable	2,422		2,535
Inventories	452		431
Other	627		1,180
Total Current Assets	7,651		5,135
Plant, Property and Equipment	65,489	$ 67,088	66,503
Equity Investments	6,506		7,113
Goodwill	12,887		14,178
Total Assets	99,279		98,920
Current Liabilities
Accounts payable and other	4,544	$ 5,465	5,408
Accrued interest	613		646
Current portion of long-term debt	2,705		3,462
Total Current Liabilities	12,899		12,946
Total Regulatory Liabilities	3,772		3,930
Deferred Income Tax Liabilities	5,703		6,026
Total Liabilities	66,882		67,927
Variable Interest Entity, Primary Beneficiary
Current Assets
Cash and cash equivalents	106		45
Accounts receivable	88		79
Inventories	27		24
Other	8		13
Total Current Assets	229		161
Plant, Property and Equipment	3,050		3,026
Equity Investments	785		965
Goodwill	431		453
Intangible and Other Assets	0		8
Total Assets	4,495		4,613
Current Liabilities
Accounts payable and other	70		88
Accrued interest	21		24
Current portion of long-term debt	187		79
Total Current Liabilities	278		191
Total Regulatory Liabilities	45		43
Other Long-Term Liabilities	9		3
Deferred Income Tax Liabilities	9		13
Long-Term Debt	2,694		3,125
Total Liabilities	$ 3,035		$ 3,375

VARIABLE INTEREST ENTITIES - Ca

VARIABLE INTEREST ENTITIES - Carrying Value of VIEs and Maximum Exposure (Details) - Variable Interest Entity, Not Primary Beneficiary - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Balance sheet
Equity investments	$ 4,720	$ 4,575
Off-balance sheet
Potential exposure to guarantees	466	170
Maximum exposure to loss	$ 5,186	$ 4,745