0001628280-21-003065 | 10-K | XBRL Viewer

COVER PAGE - USD ($) $ in Billions	12 Months Ended
COVER PAGE - USD ($) $ in Billions	Dec. 31, 2020	Feb. 19, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-35358
Entity Registrant Name	TC PipeLines, LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	52-2135448
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	77002-2761
City Area Code	877
Local Phone Number	290-2772
Title of 12(b) Security	Common units representing limited partner interests
Trading Symbol	TCP
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 2.2
Entity Common Stock, Shares Outstanding		71,306,396
Documents Incorporated by Reference	None
Entity Central Index Key	0001075607
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Amendment Flag	false

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current Assets
Cash and cash equivalents	$ 200	$ 83
Accounts receivable and other (Note 20)	40	43
Distribution receivable from Iroquois (Note 5)	0	14
Inventories	11	10
Other	6	6
Total current assets	257	156
Equity investments (Note 5)	1,070	1,098
Property, plant and equipment, net (Note 7)	1,747	1,528
Goodwill (Note 4)	71	71
TOTAL ASSETS	3,145	2,853
Current Liabilities
Accounts payable and accrued liabilities	46	28
Accounts payable to affiliates (Note 17)	7	8
Accrued interest	11	11
Current portion of long-term debt (Note 8)	423	123
Total current liabilities	487	170
Long-term debt (Note 8)	1,768	1,880
Deferred state income taxes (Note 2)	10	7
Other liabilities (Note 9)	47	36
Total liabilities	2,312	2,093
Partners’ Equity (Note 10)
General partner	16	14
Accumulated other comprehensive income (loss) (AOCI) (Note 11)	(13)	(5)
Controlling interests	735	656
Non–controlling interest	98	104
Total partners' equity	833	760
TOTAL LIABILITIES AND PARTNERS' EQUITY	3,145	2,853
Common units
Partners’ Equity (Note 10)
Limited partner	637	544
Class B units
Partners’ Equity (Note 10)
Limited partner	$ 95	$ 103

CONSOLIDATED STATEMENTS OF OPERATIONS $ in Millions	12 Months Ended
CONSOLIDATED STATEMENTS OF OPERATIONS $ in Millions	Dec. 31, 2020 USD ($) $ / shares shares	Dec. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2018 USD ($) $ / shares shares
Transmission revenues, net (Note 6)	$ 399	$ 403	$ 549
Equity earnings (Note 5)	170	160	173
Impairment of long-lived assets (Note 7)	0	0	(537)
Impairment of goodwill (Note 4)	0	0	(59)
Operation and maintenance expenses	(64)	(71)	(67)
Property taxes	(26)	(26)	(28)
General and administrative	(10)	(8)	(6)
Depreciation	(89)	(78)	(97)
Financial charges and other (Note 12)	(73)	(83)	(92)
Net income (loss) before taxes	307	297	(164)
Income taxes (Note 2)	(6)	1	(1)
Net Income (loss)	301	298	(165)
Net income attributable to non-controlling interests	17	18	17
Net income (loss)	284	280	(182)
Net income (loss) attributable to controlling interest allocation (Note 13)
Common units	278	267	(191)
General Partner	6	5	(4)
Class B units	0	8	13
Net income (loss) attributable to controlling interests	$ 284	$ 280	$ (182)
Net income (loss) per common unit - basic and diluted (in dollars per unit) \| $ / shares	$ 3.90	$ 3.74	$ (2.68)
Weighted average common units outstanding – basic and diluted (in units) \| shares	71,300,000	71,300,000	71,300,000
Common units
Net income (loss) attributable to controlling interest allocation (Note 13)
Common units	$ 278	$ 267	$ (191)
Net income (loss) per common unit - basic and diluted (in dollars per unit) \| $ / shares	$ 3.90	$ 3.74	$ (2.68)
Weighted average common units outstanding – basic and diluted (in units) \| shares	71,300,000	71,300,000	71,300,000
Common units outstanding, end of year (in units) \| shares	71,300,000	71,300,000	71,300,000

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 301	$ 298	$ (165)
Other comprehensive income (loss)
Change in fair value of cash flow hedges (Notes 11 and 19)	(16)	(13)	(2)
Reclassification to net income of gains and losses on cash flow hedges (Notes 11 and 19)	7	(1)	5
Amortization of realized loss on derivative instrument (Notes 11 and 19)	0	0	1
Other comprehensive income (loss) on equity investments (Note 11)	1	1	(1)
Comprehensive income (loss)	293	285	(162)
Comprehensive income attributable to non-controlling interests	17	18	17
Comprehensive income (loss) attributable to controlling interests	$ 276	$ 267	$ (179)

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash Generated from Operations
Net income (loss)	$ 301	$ 298	$ (165)
Depreciation	89	78	97
Impairment of long-lived assets (Note 7)	0	0	537
Impairment of goodwill (Note 4)	0	0	59
Amortization of Debt Issuance Costs and Discounts	2	2	2
Amortization of realized loss on derivative instrument (Note 19)	0	0	1
Equity earnings from equity investments (Note 5)	(170)	(160)	(173)
Distributions from equity investments	196	200	188
Change in other long-term liabilities	1	(1)	(2)
Equity allowance for funds used during construction	(10)	(2)	(1)
Change in operating working capital (Note 15)	4	(3)	(3)
Cash Generated from Operations	413	412	540
Investing Activities
Distribution received as return on investment	29	58	10
Capital expenditures	(278)	(75)	(40)
Other	(1)	(1)	4
Investing Activities	(262)	(32)	(35)
Financing Activities
Distributions paid (Note 14)	(189)	(189)	(218)
Distributions paid to Class B units (Notes 10 and 14)	(8)	(13)	(15)
Distributions paid to non-controlling interests	(23)	(22)	(14)
Common unit issuance, net (Note 10)	0	0	40
Long-term debt issued, net of discount (Note 8)	385	30	219
Long-term debt repaid (Note 8)	(199)	(136)	(516)
Debt issuance costs	0	0	(1)
Financing Activities	(34)	(330)	(505)
Increase/(decrease) in cash and cash equivalents	117	50	0
Cash and cash equivalents, beginning of year	83	33	33
Cash and cash equivalents, end of year	200	83	33
Interest payments paid	75	87	94
State income taxes paid	1	2	1
Supplemental information about non-cash investing and financing activities
Accrued capital expenditures, net	8	4	2
Great Lakes
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	(56)	(51)	(59)
Investing Activities
Investment of interests	(10)	(10)	(9)
Iroquois
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	(38)	(40)	(46)
Investing Activities
Investment of interests	(2)	(4)	0
Distribution received as return on investment	29	8	10
Northern Border
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	(76)	(69)	(68)
Investing Activities
Distribution received as return on investment	$ 0	$ 50	$ 0

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - USD ($)
shares in Millions, $ in Millions

Total

Non-Controlling Interest

Accumulated Other Comprehensive Income (Loss)

^[1]

Limited Partners

Common units

Limited Partners

Class B units

General Partner

Partners' Equity at beginning of period (in units) at Dec. 31, 2017

70.6

1.9

Partners' Equity at beginning of period at Dec. 31, 2017

$ 1,068

$ 105

$ 5

$ 824

$ 110

$ 24

Increase (Decrease) in Partners' Equity

Net income (loss)

(165)

$ (191)

(4)

Other comprehensive income

ATM equity issuances, net (in units)

0.7

ATM equity issuances, net

$ 39

Distributions

(247)

(14)

$ (210)

$ (15)

(8)

Partners' Equity at end of period (in units) at Dec. 31, 2018

71.3

1.9

Partners' Equity at end of period at Dec. 31, 2018

699

108

$ 462

$ 108

Increase (Decrease) in Partners' Equity

Net income (loss)

298

267

Other comprehensive income

(13)

Distributions

(224)

(22)

$ (185)

$ (13)

(4)

Partners' Equity at end of period (in units) at Dec. 31, 2019

71.3

1.9

Partners' Equity at end of period at Dec. 31, 2019

760

104

(5)

$ 544

$ 103

Increase (Decrease) in Partners' Equity

Net income (loss)

301

278

Other comprehensive income

(8)

Distributions

(220)

(23)

$ (185)

$ (8)

(4)

Partners' Equity at end of period (in units) at Dec. 31, 2020

71.3

1.9

Partners' Equity at end of period at Dec. 31, 2020

$ 833

$ 98

$ (13)

$ 637

$ 95

$ 16

[1]

Gains / losses related to cash flow hedges reported in accumulated other comprehensive income (loss) (AOCI) and expected to be reclassified to net income in the next 12 months are estimated to be a loss of $9 million. This estimate assumes constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

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+ Details

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
Statement of Partners' Capital [Abstract]
Gain (losses) related to cash flow hedges in AOCI expected to be reclassified to Net income in the next 12 months	$ (9)

ORGANIZATION

12 Months Ended

Dec. 31, 2020

Limited Liability Company or Limited Partnership, Business Organization and Operations [Abstract]

ORGANIZATION

TC PipeLines, LP and its subsidiaries are collectively referred to herein as the Partnership. The Partnership, which owns its pipeline assets directly as noted in the table below, was formed by TransCanada PipeLines Limited, a wholly owned subsidiary of TC Energy Corporation (TC Energy Corporation together with its subsidiaries collectively referred to herein as TC Energy), to acquire, own and participate in the management of energy infrastructure assets in North America.


Pipeline	Length	Description	Ownership
GTN	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent

Bison	303 miles	Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent

North Baja	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent

Tuscarora	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent

Northern Border	1,412 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Bakken, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border.	50 percent

PNGTS	295 miles	Connects with the TQM at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS. The 295-mile pipeline includes 107 miles of jointly owned pipeline facilities (the Joint Facilities) with MNE. The Joint Facilities extend from Westbrook, Maine to Dracut, Massachusetts and PNGTS owns approximately 32 percent of the undivided ownership interest based on contractually agreed upon percentages. The Joint Facilities are maintained and operated by MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.	61.71 percent

Great Lakes	2,115 miles	Connects with the TC Energy Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TC Energy owns the remaining 53.55 percent of Great Lakes.	46.45 percent

Iroquois	416 miles	Extends from the TC Energy Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by: TC Energy (0.66 percent), Berkshire Hathaway (50 percent). Iroquois is maintained and operated by a subsidiary of Iroquois.	49.34 percent

The Partnership is managed by its General Partner, TC PipeLines GP, Inc. (General Partner), an indirect wholly owned subsidiary of TC Energy. The General Partner provides management and operating services to the Partnership and is reimbursed for its costs and expenses. The General Partner owns 5,797,106 of our common units, 100 percent of our Incentive Distribution Rights (IDRs) and a two percent general partner interest in the Partnership at December 31, 2020. TC Energy also indirectly holds an additional 11,287,725 common units, for a total ownership of approximately 24 percent of our outstanding common units and 100 percent of our Class B units at December 31, 2020 (Refer to Note 10).

Planned Merger with TC Energy

On December 14, 2020, the Partnership, the General Partner, TC Energy, TransCan Northern Ltd., a Delaware corporation (TC Northern), TransCanada PipeLine USA Ltd., a Nevada corporation (TC PipeLine USA), and TCP Merger Sub, LLC, a Delaware limited liability company and an indirect wholly owned subsidiary of TC Energy (Merger Sub), entered into an Agreement and Plan of Merger (the TC Energy Merger Agreement). Pursuant to the TC Energy Merger Agreement, Merger Sub will be merged with and into the Partnership (TC Energy Merger), with the Partnership continuing as the sole surviving entity and an indirect, wholly owned subsidiary of TC Energy.

Subject to the terms and conditions set forth in the TC Energy Merger Agreement, at the effective time of the TC Energy Merger, each of the Partnership’s common units representing the limited partner interests in the Partnership issued and outstanding

immediately prior to the effective time of the TC Energy Merger to Unaffiliated TCP Unitholders, will be cancelled in exchange for 0.70 shares of TC Energy’s common shares.

The transaction is expected to close late in the first quarter subject to the approval by the holders of a majority of outstanding common units of the Partnership and customary regulatory approvals. Upon closing, the Partnership will be wholly owned by TC Energy and will cease to be a publicly-held master limited partnership.

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
SIGNIFICANT ACCOUNTING POLICIES	Dec. 31, 2020
Accounting Policies [Abstract]
SIGNIFICANT ACCOUNTING POLICIES	SIGNIFICANT ACCOUNTING POLICIES The accompanying consolidated financial statements and related notes have been prepared in accordance with U.S. generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The financial statements and notes present the financial position of the Partnership as of December 31, 2020 and 2019 and the results of its operations, cash flows and changes in partners’ equity for the years ended December 31, 2020, 2019 and 2018. (a)Basis of Presentation The Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence. The Partnership is considered to have a variable interest in Great Lakes, which is accounted as an equity investment since the Partnership is not the primary beneficiary (Refer to Note 5 for more details). Acquisitions by the Partnership from TC Energy are considered common control transactions. When businesses that will be consolidated are acquired from TC Energy by the Partnership, the historical financial statements are required to be recast, with the exception of net income (loss) per common unit, to include the acquired entities for all periods presented. When the Partnership acquires an asset or an investment from TC Energy, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition. (b)Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates. (c)Government Regulation The Partnership's subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC). Under FERC's regulatory accounting principles, certain assets or liabilities that result from the regulated rate-making process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators' decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition and the ability to recover regulatory assets. At December 31, 2020 and 2019, the Partnership had an immaterial amount of regulatory assets reported as part of other current assets in the balance sheet and an immaterial amount of regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities. Long-term regulatory liabilities that the Partnership has collected in its current rates related to future removal costs on its transmissions and gathering facilities are included in other long-term liabilities (refer to Note 9). (d)Cash and Cash Equivalents The Partnership’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. (e)Trade Accounts Receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. (f)Natural gas imbalances Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines’ tariff. Imbalances due from others are reported as trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. The determination of the asset or liability classification is based on the net position of the customer. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year. (g)Inventories Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or net realizable value. (h)Property, Plant and Equipment Property, plant and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized. Pipeline facilities and compression equipment have an estimated useful life of 20 to 68 years and metering and other equipment ranges from 5 to 77 years. Depreciation of our subsidiaries’ assets is based on rates approved by FERC from the pipelines’ last rate proceeding and is calculated on a straight-line composite basis over the assets’ estimated useful lives. Under the composite method, assets with similar lives and characteristics are grouped and depreciated as one asset. Amounts included in construction work in progress are not depreciated until transferred into service. During the years ended December 31, 2020, 2019 and 2018, the Partnership incurred depreciation expenses of $88 million, $78 million and $97 million, respectively. Refer to Note 7 for further details regarding our Property, plant and equipment balance. The Partnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long-lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based on the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of property, plant and equipment on the balance sheets. Both capitalized AFUDC debt and equity amounts are reported as part of Financial Charges and Other line item in the Consolidated Statements of Operations and broken out further in Note 12. Capitalized AFUDC equity amounts during the years ended December 31, 2020, 2019 and 2018 were $10 million, $2 million and $1 million, respectively. Capitalized AFUDC Debt during the year ended December 31, 2020 was $1.3 million (2019 and 2018 - less than $1 million). Refer to Note 12. (i)Impairment of Equity Method Investments We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment. If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge. (j)Impairment of Long-lived Assets The Partnership reviews long-lived assets, such as property, plant and equipment 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 is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets. (k)Partners’ Equity Costs incurred in connection with the issuance of units are deducted from the proceeds received. (l)Revenue Recognition The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. 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. The Partnership utilizes the practical expedient of recognizing revenue as invoiced. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities. The Partnership's pipeline systems 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, as applicable, at the time a regulatory decision becomes final. Refer to Note 6 for detailed disclosures regarding the Partnership’s revenues. (m)Debt Issuance Costs Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Consistent with debt discount, debt issuance costs are presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities. The amortization of debt issuance costs is reported as interest expense. (n)Income Taxes U.S. federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Consolidated statement of operations, is includable in the U.S. federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the partnership is not available. In instances where the Partnership is subject to state income taxes, the asset-liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are classified as non-current on our balance sheet. State Income Taxes in Oregon Beginning in 2020, the Partnership became subject to a corporate activity tax in Oregon which is measured on the commercial activity of a business and levied at the partnership level. The tax amounted to $0.6 million for the year ended December 31, 2020 and was included in current income tax expense. State Income Taxes in New Hampshire PNGTS is subject to the business profits tax (BPT) levied at the partnership level by the state of New Hampshire (NH). As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at December 31, 2020, 2019 and 2018 relate primarily to utility plant. The NH BPT effective tax rate was 3.0 percent for the year ended December 31, 2020 (2019 – 2.6 percent, 2018 – 3.5 percent) and was applied to PNGTS’ taxable income. During the year ended December 31, 2020 and 2018, PNGTS recorded state income tax expense amounting to $5 million and $1 million, respectively. In 2019, PNGTS recognized a state income tax benefit of $1 million. (o)Acquisitions and Goodwill The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if any indicators of impairment are evident. The Partnership can initially assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. The factors the Partnership 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 Partnership concludes there is not a greater than 50 percent likelihood that the fair value of the reporting unit is greater than its carrying value, the Partnership will then perform the quantitative goodwill impairment test. The Partnership can also 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 Partnership compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. We calculate the estimated fair value of the reporting unit using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the reporting unit, estimates of the useful life over which cash flows will occur, and a determination of weighted average cost of capital. The estimates used to calculate the fair value of the reporting unit can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether the goodwill in the reporting unit has suffered an impairment. The Partnership accounts for business acquisitions between itself and affiliates under TC Energy, also known as “dropdowns,” as transactions between entities under common control. Using this approach, the assets and liabilities of the acquired entities are recorded at TC Energy’s carrying value. In the event recasting is required, the Partnership’s historical financial information will be recast, with the exception of net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners’ equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners’ equity. (p)Fair Value Measurements For cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Judgment is required in developing these estimates. (q)Derivative Financial Instruments and Hedging Activities The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings. The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). In a cash flow hedging relationship, the change in the fair value of the hedging derivative is reported as a component of other comprehensive income and reclassified into earnings as part of “financial charges and other” line in the Consolidated statement of operations in the same period or periods during which the hedged transaction affects earnings or is reclassified immediately to net income when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. In some instances, the 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. (r)Asset Retirement Obligation The Partnership recognizes the fair value of a liability for asset retirement obligations 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 expenses. The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system’s assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2020 and 2019. (s)Contingencies The Partnership and its pipeline systems are subject to various legal proceedings in the ordinary course of business. Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the assessments indicate it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated in accordance with ASC 450, Contingencies. We base these estimates on currently available facts and the estimates of the ultimate outcome or resolution. Actual results may differ from estimates resulting in an impact, positive or negative, on earnings and cash flow. Contingencies that might result in a gain are not accrued in our consolidated financial statements. At December 31, 2020, the Partnership is not aware of any contingent liabilities that would have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

ACCOUNTING PRONOUNCEMENTS	12 Months Ended
ACCOUNTING PRONOUNCEMENTS	Dec. 31, 2020
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
ACCOUNTING PRONOUNCEMENTS	ACCOUNTING PRONOUNCEMENTS Changes in Accounting Policies effective January 1, 2020 Measurement of credit losses on financial instruments In June 2016, the Financial Accounting Standards Board (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 (loss). 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 became effective January 1, 2020 and was applied using a modified retrospective approach. The adoption of this new guidance did not have a material impact on the Partnership’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 became effective January 1, 2020, and was applied on a retrospective basis. The adoption of this new guidance did not have a material impact on the Partnership’s consolidated financial statements. Reference rate reform In March 2020, in response to the expected cessation of the London Interbank Offered Rate (LIBOR) from late 2021 to mid-2023, the FASB issued new optional guidance that eases the potential burden of accounting for reference rate reform. The new guidance provides optional expedients for contracts and hedging relationships that are affected by reference rate reform, if certain criteria are met. Each of the expedients can be applied as of January 1, 2020 through December 31, 2022. For eligible hedging relationships existing as of January 1, 2020 and prospectively, the Partnership has applied the optional expedient allowing an entity to assume that the hedged forecasted transaction in a cash flow hedge is probable of occurring.The Partnership is continuing to identify and analyze existing agreements to determine the effect of reference rate reform on its consolidated financial statements The Partnership will continue to evaluate the timing and potential impact of adoption of other optional expedients when deemed necessary.

GOODWILL	12 Months Ended
GOODWILL	Dec. 31, 2020
GOODWILL
GOODWILL	GOODWILL Under U.S. GAAP, we evaluate our goodwill related to Tuscarora and North Baja for impairment at least annually or more frequently if indicators of impairment are evident. In 2018, our analysis resulted in the estimated fair value of Tuscarora not exceeding its carrying value, including goodwill that primarily resulted from the 2019 Tuscarora Settlement as part of the 2018 FERC Actions. As a result, we recorded a goodwill impairment charge amounting to $59 million against Tuscarora’s goodwill balance of $82 million. In 2019, based on our analysis of Tuscarora and North Baja’s current market conditions, we believed there was a greater than 50 percent likelihood that Tuscarora and North Baja’s estimated fair value exceeded their carrying value. As a result, at December 31, 2019, we did not identify an impairment on the $71 million of goodwill related to the Tuscarora ($23 million) and North Baja ($48 million) reporting units. On a quarterly basis during 2020, we evaluated changes within our business and the external environment including considerations regarding whether such changes are permanent, to determine whether a triggering event had occurred. This analysis included the quarterly assessment of the impact of COVID-19 on our North Baja and Tuscarora reporting units. Through our quarterly analysis, no triggering events were identified. The following factors were considered as part of our annual qualitative analysis specific to the Partnership's Tuscarora and North Baja reporting units: •we evaluated the multiples and discount rate assumptions within the current economic environment and compared to the last quantitative model. The multiples and discount rates identified for the current year, used in our qualitative model, are reflective of the long-term outlook for Tuscarora and North Baja, in line with their underlying asset lives; •at least 90 percent of Tuscarora's and North Baja's revenue is tied to long-term take-or-pay, fixed-price contracts which have a low correlation to short-term changes in demand; •Tuscarora and North Baja have not experienced any material customer defaults to date and hold collateral, as appropriate, in support of their contracts; •Tuscarora's expansion project, Tuscarora XPress and North Baja's expansion project, North Baja XPress, are materially on track, and we do not anticipate any significant changes in outlook or delay or inability to proceed due to financing requirements; and •Tuscarora and North Baja's businesses are broadly considered essential in the United States given the important role their infrastructures play in delivering energy to the market areas they serve. Based on our qualitative analysis of Tuscarora and North Baja’s current market conditions we believe there is a greater than 50 percent likelihood that Tuscarora and North Baja’s estimated fair value exceeded their carrying value. As a result, at December 31, 2020, we have not identified an impairment on the $71 million of goodwill related to the Tuscarora ($23 million) and North Baja ($48 million) acquisitions. Adverse changes to our key considerations could, however, result in future impairments on our goodwill.

EQUITY INVESTMENTS

12 Months Ended

Dec. 31, 2020

Equity Method Investments and Joint Ventures [Abstract]

EQUITY INVESTMENTS

The Partnership has equity interests in Northern Border, Great Lakes and Iroquois. The pipeline systems owned by these entities are regulated by FERC. The pipeline systems of Northern Border and Great Lakes are operated by subsidiaries of TC Energy. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees.


	Ownership Interest at		Equity Earnings (b)			Equity Investments
	December 31, 2020		Year ended December 31			December 31
(millions of dollars)			2020	2019	2018	2020	2019
Northern Border(a)	50.00	%	76	69	68	407	422
Great Lakes	46.45	%	56	51	59	509	491
Iroquois	49.34	%	38	40	46	154	185
			170	160	173	1,070	1,098

(a)Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent in April 2006. The fee was fully amortized in May 2018.

(b)Equity Earnings represents our share in an investee’s earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here.

Impairment considerations

As noted under Note 2 - Significant accounting policies, our equity investments in Northern Border, Great Lakes and Iroquois are evaluated whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. We performed a qualitative analysis to determine if there was a non-temporary decline in our equity investments' fair value and no triggers were identified. As a result, we continue to believe no impairment exists on our equity investments. There is a risk that adverse changes in our analysis could result in additional quantitative steps to evaluate our equity method investments.

Distributions from Equity Investments

Distributions received from equity investments for the year ended December 31, 2020 were $225 million (2019 - $258 million; 2018 - $198 million) of which $29 million (2019 - $58 million and 2018 - $10 million) was considered a return of capital and is included in Investing activities in the Partnership’s consolidated statement of cash flows. The return of capital was related to our investment in Northern Border and Iroquois (see further discussion below).

Northern Border

During the year ended December 31, 2020, the Partnership received distributions from Northern Border amounting to $91 million (2019 - $144 million; 2018 – $83 million) The $144 million received in 2019 included the Partnership's 50 percent share of the Northern Border $100 million distribution in June 2019. The $100 million distribution was 100 percent financed by borrowing on Northern Border's $200 million revolving credit facility. The $50 million of cash the Partnership received did not represent a distribution of operating cash flow during the period and, therefore, it was reported as a return of investment in the Partnership's consolidated statement of cash flows.

The Partnership recorded no undistributed earnings from Northern Border for the years ended December 31, 2020, 2019 and 2018. At December 31, 2020 the Partnership had a $115 million (December 31, 2019 - $115 million) difference between the carrying value of Northern Border and the underlying equity in the net assets primarily resulting from the recognition and inclusion of goodwill in the Partnership’s investment in Northern Border relating to the Partnership’s April 2006 acquisition of an additional 20 percent general partnership interest in Northern Border.

The summarized financial information provided to us by Northern Border is as follows:


December 31 (millions of dollars)	2020	2019
Assets
Cash and cash equivalents	31	21
Other current assets	38	37
Property, plant and equipment, net	977	989
Other assets	12	12
	1,058	1,059
Liabilities and Partners’ Equity
Current liabilities	52	42
Deferred credits and other	42	39
Long-term debt, net (a)	380	364
Partners’ equity
Partners’ capital	584	615
Accumulated other comprehensive loss	—	(1)
	1,058	1,059


Year ended December 31 (millions of dollars)	2020	2019	2018

Transmission revenues	308	300	289
Operating expenses	(77)	(82)	(78)
Depreciation	(62)	(62)	(60)
Financial charges and other	(18)	(18)	(15)
Net income	151	138	136

(a)Includes current maturities of $250 million as of December 31, 2020 for Northern Border's 7.50% Senior Notes (December 31, 2019 - none), net of unamortized debt issuance costs and debt discounts. At December 31, 2020, Northern Border was in compliance with all of its financial covenants.

Great Lakes, a variable interest entity

The Partnership is considered to have a variable interest in Great Lakes, which is accounted for as an equity investment as we are not its primary beneficiary. A variable interest entity is a legal entity that either does not have sufficient equity at risk to finance its activities without additional subordinated financial support, 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 or losses of the entity.

During the year ended December 31, 2020, the Partnership received distributions from Great Lakes amounting to $48 million (2019 - $59 million; 2018 - $58 million), all of which were reported as a return on investment in the Partnership's consolidated statement of cash flows.

During the year ended December 31, 2020, the Partnership made equity contributions to Great Lakes amounting to $10 million representing cash calls from Great Lakes to make scheduled debt payments (2019 - $10 million 2018 - $9 million)

The Partnership recorded no undistributed earnings from Great Lakes for the years ended December 31, 2020, 2019, and 2018.

At December 31, 2020, the equity method goodwill related to Great Lakes amounted to $260 million (December 31, 2019 - $260 million). The equity method goodwill relates to the Partnership’s February 2007 acquisition of a 46.45 percent general partner

interest in Great Lakes and is the difference between the carrying value of our investment in Great Lakes and the underlying equity in Great Lakes’ net assets.

The summarized financial information provided to us by Great Lakes is as follows:


December 31 (millions of dollars)	2020	2019
Assets
Current assets	66	72
Property, plant and equipment, net	716	685
	782	757
Liabilities and Partners’ Equity
Current liabilities	38	33
Long-term debt, net (a)	198	219
Other long-term liabilities	9	6
Partners’ equity	537	499
	782	757


Year ended December 31 (millions of dollars)	2020	2019	2018

Transmission revenues	239	238	246
Operating expenses	(70)	(79)	(68)
Depreciation	(33)	(32)	(32)
Financial charges and other	(15)	(16)	(18)
Net income	121	111	128

(a)Includes current maturities of $31 million as of December 31, 2020 (December 31, 2019 - $21 million).

Iroquois

For the year ended December 31, 2020, the Partnership received distributions from Iroquois amounting to $86 million (2019 - $55 million: 2018 - $56 million) which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution as part of its 2017 acquisition agreement with Iroquois amounting to approximately $5 million (2019 - $8 million) .

Also included in the $86 million distribution was the Partnership's receipt of (a) a $24 million one-time, non-recurring distribution from Iroquois, representing our 49.34 percent of the reimbursement proceeds received by Iroquois from a terminated project that was guaranteed by the customer and (b) an additional $4 million distribution representing our 49.34 percent of the excess cash generated by Iroquois' operating activities in 2020.

The 2020 unrestricted cash of $5 million (2019 - $8 million) and the $24 million non-recurring distributions do not represent a distribution of Iroquois’ cash from operations during the period and therefore were reported as a return of investment in the Partnership’s consolidated statement of cash flows.

The Partnership made an equity contribution to Iroquois of $2 million and $4 million in December 2020 and August 2019, respectively. This amount represents the Partnership’s 49.34 percent share of a cash call from Iroquois to cover costs of regulatory approvals related to their capital project.

The Partnership recorded no undistributed earnings for the years ended December 31, 2020, 2019 and 2018. At December 31, 2020 and 2019, the Partnership had a $39 million and $40 million difference, respectively, between the carrying value of Iroquois and the underlying equity in the net assets primarily from TC Energy’s carrying value due to the fair value assessment of Iroquois’ assets at the time of its acquisition of interests from third parties (refer to Note 2 - Acquisitions and Goodwill for our accounting policy on acquisitions from TC Energy).

Distribution receivable from Iroquois

Iroquois declared its third quarter 2019 distribution of $28 million on November 1, 2019, and the Partnership received its 49.34 percent share or $14 million on January 6, 2020.

The summarized financial information provided to us by Iroquois, which is not considered a significant equity investee under Regulation SX-3-09, is as follows:


December 31 (millions of dollars)	2020	2019
ASSETS
Cash and cash equivalents	25	43
Other current assets	36	36
Property, plant and equipment, net	506	570
Other assets	20	16
	587	665
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	20	34
Net long-term debt, net (a)	314	317
Other non-current liabilities	21	20
Partners’ equity	232	294
	587	665


Year ended December 31 (millions of dollars)	2020	2019	2018

Transmission revenues	183	180	194
Operating expenses	(59)	(58)	(57)
Depreciation	(30)	(29)	(29)
Financial charges and other	(15)	(11)	(14)
Net income	79	82	94

(a)Includes current maturities of $5 million as of December 31, 2020 (December 31, 2019 - $3 million).

REVENUES	12 Months Ended
REVENUES	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
REVENUES	REVENUES Disaggregation of Revenues For the year ended December 31, 2020, 2019 and 2018, effectively all of the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed under Note 2 - Significant Accounting Policies. During the fourth quarter of 2018, Bison received an unsolicited offer from Tenaska Marketing Ventures (Tenaska) regarding the termination of its contract. Also, during 2018, through a Permanent Capacity Release Agreement, Tenaska assumed Anadarko Energy Services Company’s (Anadarko) ship-or-pay contract obligation on Bison, which was the largest contract on Bison. Bison and Tenaska mutually agreed to terms which included a non-refundable payment to Bison of $95.4 million in December 2018 in exchange for the termination of all its contract obligations with Bison. Following the amendment of its tariff to enable this transaction, another customer executed a similar agreement to terminate its contract on Bison in exchange for a non-refundable payment to Bison of approximately $2.0 million in December 2018. At the termination of the contracts, Bison was released from performing any future services with the two customers and as such, the amounts received were recorded in revenue in 2018. Accordingly, the $97 million we received from contract terminations was considered as revenue from capacity and transportation contracts with customers and therefore no further disaggregation of revenue is needed (See also related discussion under Note 7 - Plant Property and Equipment). As noted under Note 2 - Significant Accounting Policies, a portion of our revenues collected may be subject to refund when a rate proceeding is ongoing or as part of a rate case settlement with customers. We use our best estimate based on the facts and circumstances of the proceeding to provide for allowances for these potential refunds in the revenue we recognized. Accordingly, as part of the 2018 GTN Settlement, in 2018, we issued a $10 million refund that was allocated amongst GTN's firm customers. The refund was recognized as an offset against revenue in the income statement for the year ended December 31, 2018. Contract Balances All of the Partnership’s contract balances pertain to receivables from contracts with customers amounting to $36 million at December 31, 2020 (December 31, 2019 - $37 million) and are recorded as Trade accounts receivable and reported as “Accounts receivable and other” in the Partnership’s consolidated balance sheet (Refer to Note 20). Additionally, our accounts receivable represents the Partnership’s unconditional right to consideration for services completed which includes billed and unbilled accounts. Right to invoice practical expedient In the application of the right to invoice practical expedient, the Partnership’s revenues from regulated capacity arrangements are recognized based on rates specified in the contract. Therefore, the amount invoiced, which includes the capacity contracted and variable volume of natural gas transported, corresponds directly to the value the customer received. These revenues are recognized on a monthly basis once the Partnership’s performance obligation to provide capacity has been satisfied.

PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

PROPERTY, PLANT AND EQUIPMENT

The following table includes property, plant and equipment of our consolidated entities:


	2020			2019
December 31 (millions of dollars)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
Pipeline	1,910	(982)	928	1,907	(929)	978
Compression	730	(210)	520	584	(202)	382
Metering and other (a)	208	(58)	150	180	(56)	124
Construction in progress	149	—	149	44	—	44
	2,997	(1,250)	1,747	2,715	(1,187)	1,528

(a)Includes the commercial system purchase described under Note 17 related to our consolidated entities amounting to $26 million and does not include our portion of the capital expenditure related to our equity investment in Great Lakes, amounting to $12 million.

2018 Impairment of Bison’s long-lived assets

At December 31, 2018, the Partnership performed an impairment analysis on Bison’s long-lived assets in connection with the termination of certain customer transportation agreements (refer to Note 6 - Revenues).

With the loss of future cash flows resulting from the contract terminations described above and the persistence of unfavorable market conditions which inhibited systems flows on the pipeline during the fourth quarter of 2018, the Partnership recognized an impairment charge of $537 million relating to the remaining carrying value of Bison’s property, plant and equipment after determining that it was no longer recoverable. The impairment charge was recorded under Impairment of long-lived assets line on the Consolidated statement of operations.

DEBT AND CREDIT FACILITIES

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

DEBT AND CREDIT FACILITIES


(millions of dollars)	2020		Weighted Average Interest Rate for the Year Ended December 31, 2020			2019	Weighted Average Interest Rate for the Year Ended December 31, 2019
TC PipeLines, LP
Senior Credit Facility due 2021	—		—			—	—
2013 Term Loan Facility due 2022	450		1.87	%		450	3.52	%
4.65% Unsecured Senior Notes due 2021	350	(c)	4.65	%	(a)	350	4.65	%	(a)
4.375% Unsecured Senior Notes due 2025	350		4.375	%	(a)	350	4.375	%	(a)
3.90% Unsecured Senior Notes due 2027	500		3.90	%	(a)	500	3.90	%	(a)
GTN
5.29% Unsecured Senior Notes due 2020	—		—			100	5.29	%	(a)
5.69% Unsecured Senior Notes due 2035	150		5.69	%	(a)	150	5.69	%	(a)
3.12% Series A Senior Notes due 2030	175		3.12	%	(a)	—	—
PNGTS
Revolving Credit Facility due 2023	25		1.88	%		39	3.47	%
2.84% Series A Senior Notes due 2030	125		2.84	%	(a)	—	—
Tuscarora
Unsecured Term Loan due 2021	23		2.13	%		23	3.39	%
North Baja
Unsecured Term Loan due 2021	50		1.70	%		50	3.34	%
	2,198					2,012
Less: unamortized debt issuance costs and debt discount	7					9
Less: current portion	423	(b)				123
	1,768					1,880

(a)Fixed interest rate.

(b)Includes the Partnership's 4.65% Unsecured Senior Notes due June 15, 2021, Tuscarora’s Unsecured Term Loan due August 20, 2021 and North Baja's Unsecured Term Loan due December 19, 2021.

(c)Refer to Note 21- Subsequent events for more details on the Partnership's announcement on its intention to exercise its option to redeem this Unsecured Senior Notes at March 15, 2021.

TC PipeLines, LP

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, under which no borrowings were outstanding at December 31, 2020, leaving $500 million available for future borrowing.

At the Partnership’s option, the interest rate on the outstanding borrowings under the Senior Credit Facility may be the lenders’ base rate or LIBOR plus, in either case, an applicable margin that is based on the Partnership’s long-term unsecured credit ratings. The Senior Credit Facility permits the Partnership to specify the portion of the borrowings to be covered by specific interest rate options and, for LIBOR-based borrowings, to specify the interest rate period. The Partnership is required to pay a commitment fee based on its credit rating and on the unused principal amount of the commitments under the Senior Credit Facility. The Senior Credit Facility has a feature whereby at any time, so long as no event of default has occurred and is continuing, the Partnership may request an increase in the Senior Credit Facility of up to $500 million, but no lender has an obligation to increase their respective share of the facility.

On September 29, 2017, the Partnership’s term loan credit facility under a term loan agreement (2013 Term Loan Facility) was amended to extend the maturity period through October 2, 2022. The 2013 Term Loan Facility bears interest based, at the Partnership’s election, on the LIBOR or the base rate plus, in either case, an applicable margin. The base rate equals the highest of (i) SunTrust Bank’s prime rate, (ii) 0.50 percent above the U.S. federal funds rate and (iii) 1.00 percent above one-month LIBOR. The applicable margin for the term loan is based on the Partnership’s senior debt rating and ranges between 1.125 percent and 2.00 percent for LIBOR borrowings and 0.125 percent and 1.00 percent for base rate borrowings.

On June 26, 2019, the Partnership repaid $50 million of the principal balance under its 2013 Term Loan Facility using proceeds from Northern Border's additional distribution (see Note 5). Additionally, in conjunction with this repayment, the Partnership also terminated an equivalent amount in interest rate swaps that were used to hedge this facility at a rate of 2.81 percent. As of December 31, 2020, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 3.26 percent (2019 – 3.26 percent). Prior to hedging activities, the LIBOR-based interest rate was 1.40 percent at December 31, 2020 (December 31, 2019 – 2.94 percent).

The Senior Credit Facility and the 2013 Term Loan Facility require the Partnership to maintain a debt to adjusted cash flow leverage ratio of no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 3.85 to 1.00 as of December 31, 2020.

The Senior Credit Facility and the 2013 Term Loan Facility contain additional covenants that include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurrence of additional debt by the Partnership’s subsidiaries and distributions to unitholders. Upon any breach of these covenants, amounts outstanding under the Senior Credit Facility and the 2013 Term Loan Facility may become immediately due and payable.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 acquisition of a 49.34 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS. The indenture for the notes contains customary investment grade covenants.

PNGTS

On April 5, 2018, PNGTS entered into a revolving credit agreement under which PNGTS has the ability to borrow up to $125 million with a variable interest rate based on LIBOR. The credit agreement matures on April 5, 2023 and requires PNGTS to maintain a leverage ratio not greater than 5.00 to 1.00. The leverage ratio was 1.99 to 1.00 as of December 31, 2020. The facility is being utilized by PNGTS primarily to fund the costs of its expansion projects and for general partnership purposes. As of December 31, 2020, $25 million was drawn on the Revolving Credit Facility and the LIBOR-based interest rate was 1.28 percent (December 31, 2019 - 2.99 percent).

On October 8, 2020, PNGTS entered into a Note Purchase and Private Shelf Agreement whereby PNGTS issued $125 million 10-year Series A Senior Notes (PNGTS Series A Notes) with a coupon rate of 2.84% per annum and entered into a 3 year private shelf agreement for an additional $125 million of Senior Notes (PNGTS Private Shelf Facility). The PNGTS Series A Notes do not require any principal payments until maturity on October 8, 2030. Proceeds from the PNGTS' Series A Note issuance were used to repay the outstanding balance of PNGTS' revolving credit facility and for general partnership purposes including funding growth capital expenditures. PNGTS expects to draw the remaining $125 million available under the PNGTS Private Shelf Facility by the end of the third quarter of 2021 to refinance amounts funded on its revolving credit facility for costs associated with the Westbrook XPress Project. The PNGTS Private Shelf Facility and PNGTS Series A Notes contain a covenant that limits total debt to no greater than 65 percent of PNGTS’ total capitalization and requires PNGTS to maintain a leverage ratio of no greater than 5.00 to 1.00. The ratio of debt to capitalization was 37 percent and the leverage ratio was 1.99 to 1.00 as of December 31, 2020.

GTN

On June 1, 2020, GTN's $100 million 5.29% Unsecured Senior Notes became due and were refinanced through a Note Purchase and Private Shelf Agreement whereby GTN issued $175 million of 10-year Series A Senior Notes (GTN Series A Notes) with a coupon rate of 3.12% per annum and entered into a 3-year private shelf agreement for an additional $75 million of Senior Notes (GTN Private Shelf Facility). The GTN Series A Notes do not require any principal payments until maturity on June 1, 2030. Proceeds from the GTN Series A Note issuance were used to repay the outstanding balance of the 5.29% Unsecured Senior Notes and the remaining proceeds is being used to fund the GTN XPress capital expenditures. GTN expects to draw the remaining $75 million available under the GTN Private Shelf Facility by the end of 2023, the estimated completion date of GTN XPress. The GTN Private Shelf Facility and GTN Series A Notes contain a covenant that limits total debt to no greater than 65 percent of total capitalization. GTN's Unsecured Senior Notes contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization. GTN’s total debt to total capitalization ratio at December 31, 2020 was 36.8 percent.

Tuscarora

On July 23, 2020, Tuscarora's $23 million variable rate Unsecured Term Loan (Unsecured Term Loan) was amended to extend the maturity date to August 20, 2021 under generally the same terms. Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of December 31, 2020, the ratio was 31.16 to 1.00.

The LIBOR-based interest rate applicable to Tuscarora’s Unsecured Term Loan Facility was 2.15 percent at December 31, 2020 (December 31, 2019 - 2.82 percent).

North Baja

On December 19, 2018, North Baja entered into a $50 million unsecured variable rate term loan facility, which matures on December 19, 2021. The net proceeds were used for general partnership purposes. The variable interest rate is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on this term loan facility was 1.23 percent at December 31, 2020 (December 31, 2019 - 2.77 percent). North Baja’s Term Loan Facility contains a covenant that limits total debt to no greater than 70 percent of North Baja’s total capitalization. North Baja’s total debt to total capitalization ratio at December 31, 2020 is 40.8 percent.

Partnership (TC PipeLines, LP and its subsidiaries)

At December 31, 2020, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurring additional debt and distributions to unitholders.

The principal repayments required by the Partnership on its consolidated debt are as follows:


(millions of dollars)
2021			423
2022			450
2023			25
2024			—
2025			350
Thereafter			950
			2,198

OTHER LIABILITIES

12 Months Ended

Dec. 31, 2020

Other Liabilities Disclosure [Abstract]

OTHER LIABILITIES


December 31 (millions of dollars)	2020	2019

Regulatory liabilities	38	29
Other liabilities	9	7
	47	36

The Partnership collects estimated future removal costs related to its transmission and gathering facilities in its current rates (also known as “negative salvage”) and recognizes regulatory liabilities in this respect on the balance sheet. Estimated costs associated with the future removal of transmission and gathering facilities are collected through depreciation as allowed by FERC. These amounts do not represent asset retirement obligations as defined by FASB Accounting Standards Codification (ASC) 410, Accounting for Asset Retirement Obligations. (Refer to Note 2)

PARTNERS' EQUITY	12 Months Ended
PARTNERS' EQUITY	Dec. 31, 2020
Partners' Capital Notes [Abstract]
PARTNERS' EQUITY	PARTNERS’ EQUITY At December 31, 2020, the Partnership had 71,306,396 common units outstanding, of which 54,221,565 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of TC Energy, including 5,797,106 common units held by our General Partner. Additionally, TC Energy, through our General Partner, owns 100 percent of our IDRs and a two percent general partner interest in the Partnership. TC Energy also holds 100 percent of our 1,900,000 outstanding Class B units. At-the-Market Equity Issuance Program (ATM Program) In 2018, the Partnership issued 0.7 million common units under its previous At-the-Market Equity Issuance Program (ATM Program), which allowed the Partnership from time to time to offer and sell, through sales agents, common units representing limited partner interests. In 2018, the Partnership's ATM Program generated net proceeds of approximately $39 million, plus an additional $1 million from the General Partner to maintain its two percent interest. The commissions to our sales agents were immaterial. The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility and for general partnership purposes. In August 2019, the ATM Program expired with no common unit issuances in 2019. Issuance of Class B units The Class B Units issued on April 1, 2015 to finance a portion of the Partnership’s acquisition of the remaining 30 percent interest of GTN from TC Energy represent a limited partner interest in us and entitles TC Energy to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter, which equates to 43.75 percent of distributions above $20 million for the year ended December 31, 2020. The Class B units contain no mandatory or optional redemption features and are also non-convertible, non-exchangeable, non-voting and rank equally with common units upon liquidation. Additionally, the Class B Distribution was reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018. The Class B Reduction was implemented during the first quarter of 2018 following the Partnership’s common unit distribution reduction of 35 percent from its fourth quarter 2017 distribution level of $1.00 per common unit. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit. The Class B units’ equity account is increased by the “Class B Distribution,” less the “Class B Reduction,” if any, and until such amount is declared for distribution and paid in the first quarter of the subsequent year. For the year ended December 31, 2020, there was no Class B Distribution as the thresholds noted above were not exceeded. For the years ended December 31, 2019 and 2018, the Class B units’ equity account was increased by $8 million and $13 million, respectively. (Refer to Notes 13 and 14).

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

12 Months Ended

Dec. 31, 2020

Partners' Capital, Comprehensive Income [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The changes in AOCI by component are as follows:


(millions of dollars)	Cash flow hedges	Equity Investments	Total
Balance at December 31, 2017	4	1	5
Change in fair value of cash flow hedges	(2)	—	(2)
Amounts reclassified from AOCI	5	—	5
PNGTS’ amortization of realized loss on derivative instrument (Note 19)	1	—	1
Other comprehensive income - effects of Iroquois’ retirement benefit plans	—	(1)	(1)
Net other comprehensive income	4	(1)	3
Balance at December 31, 2018	8	—	8
Change in fair value of cash flow hedges	(13)	—	(13)
Amounts reclassified from AOCI	(1)	—	(1)
Other comprehensive loss - effects of Iroquois’ retirement benefit plans	—	1	1
Net other comprehensive income (loss)	(14)	1	(13)
Balance as of December 31, 2019	(6)	1	(5)
Change in fair value of cash flow hedges	(16)	—	(16)
Amounts reclassified from AOCI	7	—	7
Other comprehensive income - effects of Iroquois’ retirement benefit plans	—	1	1
Net other comprehensive income (loss)	(9)	1	(8)
Balance as of December 31, 2020	(15)	2	(13)

FINANCIAL CHARGES AND OTHER

12 Months Ended

Dec. 31, 2020

Other Expense, Nonoperating [Abstract]

FINANCIAL CHARGES AND OTHER


Year ended December 31 (millions of dollars)	2020	2019	2018

Interest expense(a)	78	88	95
Net realized loss (gain) related to the interest rate swaps	7	(1)	(2)
PNGTS’ amortization of realized loss on derivative instrument (Note 19)	—	—	1
AFUDC - Equity	(10)	(2)	(1)
Other (b)	(2)	(2)	(1)
	73	83	92

(a)Interest expense includes amortization of debt issuance costs and discount costs amounting to approximately $2 million each year ended December 31, 2020, 2019 and 2018.

(b)Includes AFUDC Debt amounting to $1.3 million for the year ended December 31, 2020 (2019 and 2018 - less than $1 million).

NET INCOME (LOSS) PER COMMON UNIT

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

NET INCOME (LOSS) PER COMMON UNIT

Net income (loss) per common unit is computed by dividing net income (loss) attributable to controlling interests, after deduction of amounts attributable to the General Partner and Class B units, by the weighted average number of common units outstanding.

The amounts allocable to the General Partner equals an amount based upon the General Partner’s two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement (Refer to Note 14).

The amount allocable to the Class B units in 2020 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2020 less $20 million, the residual of which is further multiplied by 43.75 percent. This amount is further reduced by the estimated Class B Reduction for 2020, an approximately 35 percent reduction applied to the estimated annual Class B Distribution (December 31, 2019 and 2018 - $20 million less Class B Reduction). During the year ended December 31, 2020, no amounts were allocated to the Class B units as the annual threshold was not exceeded (2019 - $8 million, 2018 - $13 million).

Net income (loss) per common unit was determined as follows:


(millions of dollars, except per common unit amounts)	2020		2019		2018

Net income (loss) attributable to controlling interests	284		280		(182)
Amounts attributable to the Class B units (a)	—		(8)		(13)
Net income (loss) allocable to the General Partner and common units	284		272		(195)
Amounts attributable to General Partner's two percent interest	(6)		(5)		4
Net income (loss) attributable to common units	278		267		(191)
Weighted average common units outstanding (millions) – basic and diluted	71.3		71.3		71.3
Net income (loss) per common unit – basic and diluted	$	3.90	$	3.74	$	(2.68)

(a) As discussed in Note 10, the Class B units entitle TC Energy to a distribution which is an amount based on 30 percent of GTN’s distributions after exceeding certain annual thresholds and Class B Reduction. The distribution will be payable in the first quarter with respect to the prior year’s distributions. There was no Class B Unit distribution declared for 2020. However, consistent with the application of Accounting Standards Codification (ASC) Topic 260 – “Earnings per share,” the Partnership allocated the Class B units distribution in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2019 less the threshold level of $20 million (2018 - less $20 million) and less the Class B Reduction (2019 - $4 million, 2018 - $7 million).

CASH DISTRIBUTIONS

12 Months Ended

Dec. 31, 2020

Partners' Capital Account, Distributions [Abstract]

CASH DISTRIBUTIONS

The Partnership makes cash distributions to its partners with respect to each calendar quarter within 45 days after the end of each quarter. Distributions are based on available cash, as defined in the Partnership Agreement, which includes all cash and cash equivalents of the Partnership and working capital borrowings less reserves established by the General Partner.

Pursuant to the Partnership Agreement, the General Partner receives two percent of all cash distributions in regard to its general partner interest and is also entitled to incentive distributions as described below. The unitholders receive the remaining portion of the cash distribution.

The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and our General Partner after providing for Class B distributions based on the specified target distribution levels. The percentage interests set forth below for our General Partner include its IDRs and two percent general partner interest and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The percentage interest distributions to the General Partner illustrated below that are in excess of its two percent general partner interest represent the IDRs.


		Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Per Unit Target Amount	Common Unitholders		General Partner
Minimum Quarterly Distribution	$0.45	98	%	2	%
First Target Distribution	above $0.45 up to $0.81	98	%	2	%
Second Target Distribution	above $0.81 up to $0.88	85	%	15	%
Thereafter	above $0.88	75	%	25	%

The following table provides information about our distributions (in millions except per unit distributions amounts).


				Limited Partners				General Partner
Declaration Date	Payment Date	Per Unit Distribution		Common Units		Class B Units(b)		2		%	IDRs(a)		Total Cash Distribution
1/23/2018	2/13/2018	$	1.00	$	71	$	15	$	2		$	3	$	91
5/1/2018	5/15/2018	$	0.65	$	46	$	—	$	1		$	—	$	47
7/26/2018	8/15/2018	$	0.65	$	46	$	—	$	1		$	—	$	47
10/23/2018	11/14/2018	$	0.65	$	46	$	—	$	1		$	—	$	47
1/22/2019	2/11/2019	$	0.65	$	46	$	13	$	1		$	—	$	60
4/23/2019	5/13/2019	$	0.65	$	46	$	—	$	1		$	—	$	47
7/23/2019	8/14/2019	$	0.65	$	46	$	—	$	1		$	—	$	47
10/22/2019	11/14/2019	$	0.65	$	46	$	—	$	1		$	—	$	47
1/21/2020	2/14/2020	$	0.65	$	46	$	8	$	1		$	—	$	55
4/21/2020	5/12/2020	$	0.65	$	46	$	—	$	1		$	—	$	47
7/23/2020	8/14/2020	$	0.65	$	46	$	—	$	1		$	—	$	47
10/21/2020	11/13/2020	$	0.65	$	46	$	—	$	1		$	—	$	47
1/19/2021(c)	2/12/2021(c)	$	0.65	$	46	$	—	$	1		$	—	$	47

(a)The distributions paid during the year ended December 31, 2020 and 2019 included no incentive distributions to the General Partner (2018 - $3 million).

(b)The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TC Energy to an annual distribution which is an amount based on 30 percent of GTN’s annual distributions after exceeding certain annual thresholds and adjustments (refer to Note 10).

(c)On February 12, 2021, we paid a cash distribution of $0.65 per unit on our outstanding common units to unitholders of record at the close of business on January 29, 2021 (refer to Note 21).

CHANGE IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2020

Increase (Decrease) in Operating Capital [Abstract]

CHANGE IN OPERATING WORKING CAPITAL


Year Ended December 31 (millions of dollars)	2020	2019	2018
Change in accounts receivable and other	1	9	(6)
Change in inventory	(1)	(2)	—
Change in other current assets	—	—	(1)
Change in accounts payable and accrued liabilities (a)	5	(11)	3
Change in accounts payable to affiliates	(1)	2	1
Change in accrued interest	—	(1)	—
Change in operating working capital	4	(3)	(3)

(a)Excludes certain non-cash items primarily related to capital accruals and credits.

TRANSACTIONS WITH MAJOR CUSTOMERS	12 Months Ended
TRANSACTIONS WITH MAJOR CUSTOMERS	Dec. 31, 2020
Risks and Uncertainties [Abstract]
TRANSACTIONS WITH MAJOR CUSTOMERS	TRANSACTIONS WITH MAJOR CUSTOMERS For the year ended December 31, 2020 and 2019, no customer accounted for more than 10 percent of our consolidated revenue and trade accounts receivable. At December 31, 2018, Tenaska owed the Partnership approximately $4 million, which was approximately 10 percent of our consolidated trade accounts receivable. As noted under Note 6, in 2018, Tenaska assumed Anadarko’s ship-or-pay contract obligation on Bison. After assuming the transportation obligation, Bison accepted an offer from Tenaska to terminate its contract. For the year ended December 31, 2018, revenues from both Anadarko and Tenaska amounted to $144 million, which was approximately 36 percentof our consolidated revenues.

RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2020

RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership.

The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket

expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner was $4 million for the year ended December 31, 2020 (2019 - $4 million; 2018 - $4 million).

As operator of most of our pipelines (except Iroquois and the Pipeline facilities jointly owned with MNE on PNGTS (the Joint Facilities)), TC Energy’s subsidiaries provide capital and operating services to our pipeline systems. TC Energy’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Joint Facilities are operated by MNOC. Therefore, Iroquois and the Joint Facilities do not receive capital and operating services from TC Energy.

Capital and operating costs charged to our pipeline systems, except for Iroquois, for the years ended December 31, 2020, 2019 and 2018 by TC Energy's subsidiaries and amounts payable to TC Energy's subsidiaries at December 31, 2020 and 2019 are summarized in the following tables:


Year ended December 31 (millions of dollars)	2020	2019	2018
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes (a)	66	47	44
Northern Border(a)	39	39	36
PNGTS (a)	6	7	9
GTN	68	45	34
Bison	2	2	6
North Baja	7	5	4
Tuscarora	6	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	16	20	19
Northern Border	16	18	16
PNGTS	3	4	5
GTN	29	33	28
Bison	2	2	6
North Baja	3	4	4
Tuscarora	3	4	4


December 31 (millions of dollars)	2020	2019
Amount payable to TC Energy’s subsidiaries for costs charged in the year by:
Great Lakes (a)	3	5
Northern Border(a)	2	4
PNGTS (a)	1	1
GTN	4	5
Bison	—	—
North Baja	—	1
Tuscarora	1	—

(a)Represents 100 percent of the costs.

Great Lakes

Great Lakes earns significant transportation revenues from TC Energy and its affiliates. For the year ended December 31, 2020, Great Lakes earned 73 percent of its transportation revenues from TC Energy and its affiliates (2019 – 73 percent; 2018 – 73 percent). Additionally, included in Great Lakes’ other revenues for 2018 and 2019 were cost recovery charges to affiliates for the use of office space in the building owned by Great Lakes. These revenues comprised less than one percent of total revenue in 2018 and 2019. The building was sold to a third party in the third quarter of 2019.

At December 31, 2020, $17 million was included in Great Lakes’ receivables in regard to the transportation contracts with TC Energy and its affiliates (December 31, 2019 – $19 million).

Great Lakes has a cash management agreement with TC Energy whereby Great Lakes’ funds are pooled with other TC Energy affiliates. The agreement also gives Great Lakes the ability to obtain short-term borrowings to provide liquidity for Great Lakes’

operating needs. At December 31, 2020 and 2019, Great Lakes had outstanding receivables from this arrangement amounting to $27 million and $34 million, respectively.

Great Lakes has a long-term transportation agreement with TC Energy's Canadian Mainline natural gas transmission system (Canadian Mainline) that commenced on November 1, 2017 for a ten-year period and allows TC Energy to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system. This contract, which contains volume reduction options up to full contract quantity beginning in year three, was a direct benefit from TC Energy’s long-term fixed price service on its Canadian Mainline that was launched in 2017. For the year ended December 31, 2020, the total reservation revenue earned by Great Lakes on this contract was $75 million (2019 - $76 million; 2018 - $76 million). On November 20, 2020, this contract was revised. Effective November 1, 2021 the original contract rate will be reduced with no changes in the contracted volume. Additionally, after November 20, 2020, the Canadian Mainline shall have the right to reduce the contracted volume or terminate the full contract, effective November 1st of the applicable year, provided that 349 days’ prior written notice has been given to Great Lakes. As of February 24, 2021, no further changes to this contract have been made. The future revenue reduction on Great Lakes from the revised contract is not expected to have a material impact on the Partnership's expected distributions from Great Lakes.

In 2018, Great Lakes executed long-term transportation capacity contracts with its affiliate, ANR Pipeline Company (ANR) in anticipation of specific possible future needs. The original total contract value of these contracts was approximately $1.3 billion over a 15-year period. These contracts were subject to certain conditions and provisions, including a reduction option up to the full contract quantity if exercised up to a certain date. During the first quarter of 2020, several amendments were made to these contracts and ANR exercised the right to terminate a significant portion of the contracts amounting to approximately $1.1 billion. The remaining maximum rate contract, which has a total capacity of approximately 168,000 Dth/day and total contract value of $182 million over a term of 20 years, is expected to begin in late 2022. This contract, which has a full quantity reduction option at any time before October 1, 2022, is dependent on ANR being able to secure the required regulatory approvals and other requirements of the project associated with these volumes. Any remaining unsubscribed capacity on Great Lakes will be available for contracting in response to developing marketing conditions.

Northern Border

For the year ended December 31, 2020, Northern Border provided transportation service to TC Energy Marketing Inc., a subsidiary of TC Energy and earned revenues of $0.8 million in 2020 (2019 and 2018 - none). At December 31, 2020 and 2019, Northern Border had no outstanding receivables from TC Energy Marketing, Inc.

PNGTS

For the year ended December 31, 2020, PNGTS did not provide transportation services to TC Energy subsidiaries. For the years ended December 31, 2019 and 2018, PNGTS provided transportation service to TransCanada Energy Ltd., a subsidiary of TC Energy and earned revenues of less than $1 million and $1 million, respectively. At December 31, 2020 and 2019, PNGTS had no outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets.

In connection with the Portland XPress expansion project (PXP), which was designed to be phased in over a three-year time period, PNGTS has entered into an arrangement with affiliates regarding the construction of certain facilities on their systems that are required to fulfill future contracts on the PNGTS system. In the event the expansions are terminated prior to their in-service dates, PNGTS would be required to reimburse its affiliates for any costs incurred related to the development of these facilities. In November 2020, the last phase of PXP (Phase III) was placed in service. As a result of placing the TC Energy facilities associated with the Phases I, II and III volumes in service, PNGTS' reimbursement obligation to TC Energy relating to this project has been extinguished.

Commercial System Purchase

On August 1, 2020, GTN, Great Lakes, Tuscarora and North Baja entered into a purchase agreement with a TC Energy affiliate to purchase an internally developed customer-facing commercial natural gas transmission IT application that maintains and manages customer contracts, natural gas capacity release, customer nominations, metering and billings. The total value of the transaction was $51 million and the Partnership's proportionate share of the cost was $38 million. Prior to the transaction close, GTN, Great Lakes, Tuscarora and North Baja paid the affiliate for the use of this system and the costs are included in the "Impact on Partnership's income" tabular summary above. Refer to Note 7 for additional information.

QUARTERLY FINANCIAL DATA (Unaudited)

12 Months Ended

Dec. 31, 2020

Quarterly Financial Information Disclosure [Abstract]

QUARTERLY FINANCIAL DATA (unaudited)

QUARTERLY FINANCIAL DATA (unaudited)The following sets forth selected unaudited financial data for the four quarters in 2020 and 2019:


Quarter ended (millions of dollars except per common unit amounts)	Mar 31		Jun 30		Sept 30		Dec 31
2020
Transmission revenues	101		95		99		104
Equity earnings	55		29		39		47
Net income (loss)	94		61		68		78
Net income (loss) attributable to controlling interests	88		57		65		74
Net income (loss) per common unit	$	1.21	$	0.78	$	0.90	$	1.01
Cash distributions paid to common units (a)	47		47		47		47
Cash distribution paid to Class B units	8		—		—		—
2019
Transmission revenues	113		93		93		104
Equity earnings	54		30		31		45
Net income	100		57		59		82
Net income attributable to controlling interests	93		55		56		76
Net income per common unit	$	1.28	$	0.75	$	0.76	$	0.95
Cash distributions paid to common units (a)	47		47		47		47
Cash distribution paid to Class B units	13		—		—		—

(a)Distributions paid to common units includes our general partner’s two percent share and IDRs, if any.

FAIR VALUE MEASUREMENTS	12 Months Ended
FAIR VALUE MEASUREMENTS	Dec. 31, 2020
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS (a)Fair Value Hierarchy Under ASC 820, Fair Value Measurements and Disclosures, fair value measurements are characterized in one of three levels based upon the input used to arrive at the measurement. The three levels of the fair value hierarchy are as follows: •Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date. •Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. •Level 3 inputs are unobservable inputs for the asset or liability. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. (b)Fair Value of Financial Instruments The carrying value of "cash and cash equivalents," "accounts receivable and other," "accounts payable and accrued liabilities," "accounts payable to affiliates" and "accrued interest" approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach, which uses period-end market rates and applies a discounted cash flow valuation model. The Partnership has classified the fair value of natural gas imbalances as a Level 2 of the fair value hierarchy for fair value disclosure purposes, as the valuation approach includes quoted prices in the market index and observable volumes for the imbalance. Long-term debt is recorded at amortized cost and classified in Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified in Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership's debt as at December 31, 2020 and December 31, 2019 was $2,388 million and $2,111 million, respectively. Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. The Partnership’s floating rate debt is subject to LIBOR benchmark interest rate risk. The Partnership uses interest rate derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk. The Partnership’s interest rate swaps mature on October 2, 2022 and are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The fixed weighted average interest rate on these instruments is 3.26 percent. On June 26, 2019, in conjunction with the Partnership's $50 million repayment on its 2013 Term Loan Facility, the Partnership also terminated an equivalent amount in interest rate swaps that were used to hedge this facility at an unwind rate of 2.81 percent (See also Note 8). At December 31, 2020, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $15 million (on both gross and net basis) (December 31, 2019 - liability of $6 million), the net change of which is recognized in other comprehensive income. For the year ended December 31, 2020, the net realized loss related to interest rate swaps was $7 million and was included in financial charges and other (2019 - $1 million gain, 2018 – $2 million gain). Refer to Note 12 – Financial Charges and Other. The Partnership has no master netting agreements; however, its contracts contain provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of December 31, 2020 and 2019. Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value of non-derivative financial assets, such as cash and cash equivalents and receivables, as well as the fair value of derivative financial assets. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At December 31, 2020, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At December 31, 2020, no customer accounted for more than 10 percent of our consolidated revenues and accounts receivable, respectively (refer also to Note 16 for more details). PNGTS In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its 5.90% Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in AOCI as of the termination date. At December 31, 2018, and as a result of the repayment of the 5.90% Senior Secured Notes, the remaining balance of the $20.9 million realized loss in AOCI included in other comprehensive income at the termination date was fully amortized against earnings. For the year ended December 31, 2018, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $1 million. (c)Other The estimated fair value measurements used in any of our impairment analyses are classified as Level 3. In the determination of fair value utilized in the recoverability assessments for the respective assets, we used internal forecasts on expected future cash flows and applied appropriate discount rates which involved significant assumptions and estimates

ACCOUNTS RECEIVABLE AND OTHER

12 Months Ended

Dec. 31, 2020

Receivables [Abstract]

ACCOUNTS RECEIVABLE AND OTHER


December 31 (millions of dollars)	2020	2019
Trade accounts receivable, net of immaterial allowance for doubtful accounts	36	37
Receivable from affiliates	1	—
Other	3	6
	40	43

SUBSEQUENT EVENTS	12 Months Ended
SUBSEQUENT EVENTS	Dec. 31, 2020
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Management of the Partnership has reviewed subsequent events through February 24, 2021, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes. Partnership On January 19, 2021, the board of directors of our General Partner declared the Partnership's fourth quarter 2020 cash distribution in the amount of $0.65 per common unit and was paid on February 12, 2021 to unitholders of record as of January 29, 2021. The declared distribution totaled $47 million and is payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to the General Partner for its two percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the fourth quarter 2020. Northern Border Northern Border declared its December 2020 distribution of $16 million on January 15, 2021, of which the Partnership received its 50 percent share or $8 million on January 29, 2021. Northern Border declared its January 2021 distribution of $18 million on February 16, 2021, of which the Partnership will receive its 50 percent share or $9 million on February 26, 2021. Great Lakes Great Lakes declared its fourth quarter 2020 distribution of $23 million on January 13, 2021, of which the Partnership received its 46.45 percent share or $11 million on January 29, 2021. Iroquois Iroquois declared its fourth quarter 2020 distribution of $22 million on February 18, 2021, and the Partnership will receive its 49.34 percent share or $11 million on March 24, 2021. Additionally, on March 24, 2021, the Partnership will make a $1 million capital contribution to Iroquois representing the Partnership's 49.34 percent share of a cash call from Iroquois to cover costs related to their ExC Project. PNGTS PNGTS declared its fourth quarter 2020 distribution of $12 million on January 13, 2021, of which $5 million was paid to its non-controlling interest owner on January 29, 2021. TC PipeLines, LP The Partnership's $350 million aggregate principal amount of 4.65 percent Unsecured Senior Notes mature on June 15, 2021. On February 12, 2021, the Partnership exercised its option to redeem the Unsecured Senior Notes on March 15, 2021, at a redemption price equal to 100% of the principal amount of the notes then outstanding, plus unpaid interest accrued to March 15, 2021. Partial funding for the redemption is expected to be provided using cash on hand, and borrowings under the Partnership’s $500 million Senior Credit Facility.

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Policies)	Dec. 31, 2020
Accounting Policies [Abstract]
Basis of Presentation - Consolidation and equity method of accounting	Basis of PresentationThe Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence. The Partnership is considered to have a variable interest in Great Lakes, which is accounted as an equity investment since the Partnership is not the primary beneficiary
Basis of Presentation - Transactions between entities under common control	Acquisitions by the Partnership from TC Energy are considered common control transactions. When businesses that will be consolidated are acquired from TC Energy by the Partnership, the historical financial statements are required to be recast, with the exception of net income (loss) per common unit, to include the acquired entities for all periods presented. When the Partnership acquires an asset or an investment from TC Energy, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition.
Use of Estimates	Use of EstimatesThe preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Government Regulation	Government RegulationThe Partnership's subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC). Under FERC's regulatory accounting principles, certain assets or liabilities that result from the regulated rate-making process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators' decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition and the ability to recover regulatory assets. At December 31, 2020 and 2019, the Partnership had an immaterial amount of regulatory assets reported as part of other current assets in the balance sheet and an immaterial amount of regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities. Long-term regulatory liabilities that the Partnership has collected in its current rates related to future removal costs on its transmissions and gathering facilities are included in other long-term liabilities
Cash and Cash Equivalents	Cash and Cash EquivalentsThe Partnership’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.
Trade Accounts Receivable	Trade Accounts ReceivableTrade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method.
Natural gas imbalances	Natural gas imbalancesNatural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines’ tariff. Imbalances due from others are reported as trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. The determination of the asset or liability classification is based on the net position of the customer. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.
Inventories	InventoriesInventories primarily consist of materials and supplies and are carried at the lower of weighted average cost or net realizable value.
Property, Plant and Equipment	Property, Plant and EquipmentProperty, plant and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized. Pipeline facilities and compression equipment have an estimated useful life of 20 to 68 years and metering and other equipment ranges from 5 to 77 years. Depreciation of our subsidiaries’ assets is based on rates approved by FERC from the pipelines’ last rate proceeding and is calculated on a straight-line composite basis over the assets’ estimated useful lives. Under the composite method, assets with similar lives and characteristics are grouped and depreciated as one asset. Amounts included in construction work in progress are not depreciated until transferred into service. During the years ended December 31, 2020, 2019 and 2018, the Partnership incurred depreciation expenses of $88 million, $78 million and $97 million, respectively. Refer to Note 7 for further details regarding our Property, plant and equipment balance.The Partnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long-lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based on the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of property, plant and equipment on the balance sheets.
Impairment of Equity Method Investments	Impairment of Equity Method Investments We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment. If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.
Impairment of Long-lived Assets	Impairment of Long-lived AssetsThe Partnership reviews long-lived assets, such as property, plant and equipment 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 is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.
Partners' Equity	Partners’ EquityCosts incurred in connection with the issuance of units are deducted from the proceeds received.
Revenue Recognition	Revenue Recognition The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. 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. The Partnership utilizes the practical expedient of recognizing revenue as invoiced. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities. The Partnership's pipeline systems 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, as applicable, at the time a regulatory decision becomes final. Refer to Note 6 for detailed disclosures regarding the Partnership’s revenues.
Debt Issuance Costs	Debt Issuance CostsCosts related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Consistent with debt discount, debt issuance costs are presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities. The amortization of debt issuance costs is reported as interest expense.
Income Taxes	Income Taxes U.S. federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Consolidated statement of operations, is includable in the U.S. federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the partnership is not available. In instances where the Partnership is subject to state income taxes, the asset-liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are classified as non-current on our balance sheet.
Acquisitions and Goodwill	Acquisitions and Goodwill The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if any indicators of impairment are evident. The Partnership can initially assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. The factors the Partnership 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 Partnership concludes there is not a greater than 50 percent likelihood that the fair value of the reporting unit is greater than its carrying value, the Partnership will then perform the quantitative goodwill impairment test. The Partnership can also 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 Partnership compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. We calculate the estimated fair value of the reporting unit using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the reporting unit, estimates of the useful life over which cash flows will occur, and a determination of weighted average cost of capital. The estimates used to calculate the fair value of the reporting unit can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether the goodwill in the reporting unit has suffered an impairment. The Partnership accounts for business acquisitions between itself and affiliates under TC Energy, also known as “dropdowns,” as transactions between entities under common control. Using this approach, the assets and liabilities of the acquired entities are recorded at TC Energy’s carrying value. In the event recasting is required, the Partnership’s historical financial information will be recast, with the exception of net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners’ equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners’ equity.
Fair Value Measurements	Fair Value MeasurementsFor cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Judgment is required in developing these estimates.Fair Value Hierarchy Under ASC 820, Fair Value Measurements and Disclosures, fair value measurements are characterized in one of three levels based upon the input used to arrive at the measurement. The three levels of the fair value hierarchy are as follows: •Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date. •Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. •Level 3 inputs are unobservable inputs for the asset or liability. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.
Derivative Financial Instruments and Hedging Activities	Derivative Financial Instruments and Hedging Activities The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings. The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). In a cash flow hedging relationship, the change in the fair value of the hedging derivative is reported as a component of other comprehensive income and reclassified into earnings as part of “financial charges and other” line in the Consolidated statement of operations in the same period or periods during which the hedged transaction affects earnings or is reclassified immediately to net income when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. In some instances, the 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.
Asset Retirement Obligation	Asset Retirement ObligationThe Partnership recognizes the fair value of a liability for asset retirement obligations 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 expenses.The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future.
Contingencies	ContingenciesThe Partnership and its pipeline systems are subject to various legal proceedings in the ordinary course of business. Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the assessments indicate it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated in accordance with ASC 450, Contingencies. We base these estimates on currently available facts and the estimates of the ultimate outcome or resolution. Actual results may differ from estimates resulting in an impact, positive or negative, on earnings and cash flow. Contingencies that might result in a gain are not accrued in our consolidated financial statements.At December 31, 2020, the Partnership is not aware of any contingent liabilities that would have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows

ORGANIZATION (Tables)

12 Months Ended

Dec. 31, 2020

Limited Liability Company or Limited Partnership, Business Organization and Operations [Abstract]

Schedule of ownership interests in natural gas pipeline systems


Pipeline	Length	Description	Ownership
GTN	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent

Bison	303 miles	Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent

North Baja	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent

Tuscarora	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent

Northern Border	1,412 miles	Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Bakken, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border.	50 percent

PNGTS	295 miles	Connects with the TQM at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS. The 295-mile pipeline includes 107 miles of jointly owned pipeline facilities (the Joint Facilities) with MNE. The Joint Facilities extend from Westbrook, Maine to Dracut, Massachusetts and PNGTS owns approximately 32 percent of the undivided ownership interest based on contractually agreed upon percentages. The Joint Facilities are maintained and operated by MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.	61.71 percent

Great Lakes	2,115 miles	Connects with the TC Energy Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TC Energy owns the remaining 53.55 percent of Great Lakes.	46.45 percent

Iroquois	416 miles	Extends from the TC Energy Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by: TC Energy (0.66 percent), Berkshire Hathaway (50 percent). Iroquois is maintained and operated by a subsidiary of Iroquois.	49.34 percent

EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2020

Equity Method Investments and Joint Ventures [Abstract]

Schedule of equity investments and summarized financial information for equity investees


	Ownership Interest at		Equity Earnings (b)			Equity Investments
	December 31, 2020		Year ended December 31			December 31
(millions of dollars)			2020	2019	2018	2020	2019
Northern Border(a)	50.00	%	76	69	68	407	422
Great Lakes	46.45	%	56	51	59	509	491
Iroquois	49.34	%	38	40	46	154	185
			170	160	173	1,070	1,098

The summarized financial information provided to us by Northern Border is as follows:


December 31 (millions of dollars)	2020	2019
Assets
Cash and cash equivalents	31	21
Other current assets	38	37
Property, plant and equipment, net	977	989
Other assets	12	12
	1,058	1,059
Liabilities and Partners’ Equity
Current liabilities	52	42
Deferred credits and other	42	39
Long-term debt, net (a)	380	364
Partners’ equity
Partners’ capital	584	615
Accumulated other comprehensive loss	—	(1)
	1,058	1,059


Year ended December 31 (millions of dollars)	2020	2019	2018

Transmission revenues	308	300	289
Operating expenses	(77)	(82)	(78)
Depreciation	(62)	(62)	(60)
Financial charges and other	(18)	(18)	(15)
Net income	151	138	136

The summarized financial information provided to us by Great Lakes is as follows:


December 31 (millions of dollars)	2020	2019
Assets
Current assets	66	72
Property, plant and equipment, net	716	685
	782	757
Liabilities and Partners’ Equity
Current liabilities	38	33
Long-term debt, net (a)	198	219
Other long-term liabilities	9	6
Partners’ equity	537	499
	782	757


Year ended December 31 (millions of dollars)	2020	2019	2018

Transmission revenues	239	238	246
Operating expenses	(70)	(79)	(68)
Depreciation	(33)	(32)	(32)
Financial charges and other	(15)	(16)	(18)
Net income	121	111	128

(a)Includes current maturities of $31 million as of December 31, 2020 (December 31, 2019 - $21 million).

The summarized financial information provided to us by Iroquois, which is not considered a significant equity investee under Regulation SX-3-09, is as follows:


December 31 (millions of dollars)	2020	2019
ASSETS
Cash and cash equivalents	25	43
Other current assets	36	36
Property, plant and equipment, net	506	570
Other assets	20	16
	587	665
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	20	34
Net long-term debt, net (a)	314	317
Other non-current liabilities	21	20
Partners’ equity	232	294
	587	665


Year ended December 31 (millions of dollars)	2020	2019	2018

Transmission revenues	183	180	194
Operating expenses	(59)	(58)	(57)
Depreciation	(30)	(29)	(29)
Financial charges and other	(15)	(11)	(14)
Net income	79	82	94

(a)Includes current maturities of $5 million as of December 31, 2020 (December 31, 2019 - $3 million).

PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Schedule of property, plant and equipment

The following table includes property, plant and equipment of our consolidated entities:


	2020			2019
December 31 (millions of dollars)	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
Pipeline	1,910	(982)	928	1,907	(929)	978
Compression	730	(210)	520	584	(202)	382
Metering and other (a)	208	(58)	150	180	(56)	124
Construction in progress	149	—	149	44	—	44
	2,997	(1,250)	1,747	2,715	(1,187)	1,528

DEBT AND CREDIT FACILITIES (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Schedule of debt and credit facilities


(millions of dollars)	2020		Weighted Average Interest Rate for the Year Ended December 31, 2020			2019	Weighted Average Interest Rate for the Year Ended December 31, 2019
TC PipeLines, LP
Senior Credit Facility due 2021	—		—			—	—
2013 Term Loan Facility due 2022	450		1.87	%		450	3.52	%
4.65% Unsecured Senior Notes due 2021	350	(c)	4.65	%	(a)	350	4.65	%	(a)
4.375% Unsecured Senior Notes due 2025	350		4.375	%	(a)	350	4.375	%	(a)
3.90% Unsecured Senior Notes due 2027	500		3.90	%	(a)	500	3.90	%	(a)
GTN
5.29% Unsecured Senior Notes due 2020	—		—			100	5.29	%	(a)
5.69% Unsecured Senior Notes due 2035	150		5.69	%	(a)	150	5.69	%	(a)
3.12% Series A Senior Notes due 2030	175		3.12	%	(a)	—	—
PNGTS
Revolving Credit Facility due 2023	25		1.88	%		39	3.47	%
2.84% Series A Senior Notes due 2030	125		2.84	%	(a)	—	—
Tuscarora
Unsecured Term Loan due 2021	23		2.13	%		23	3.39	%
North Baja
Unsecured Term Loan due 2021	50		1.70	%		50	3.34	%
	2,198					2,012
Less: unamortized debt issuance costs and debt discount	7					9
Less: current portion	423	(b)				123
	1,768					1,880

(a)Fixed interest rate.

(b)Includes the Partnership's 4.65% Unsecured Senior Notes due June 15, 2021, Tuscarora’s Unsecured Term Loan due August 20, 2021 and North Baja's Unsecured Term Loan due December 19, 2021.

(c)Refer to Note 21- Subsequent events for more details on the Partnership's announcement on its intention to exercise its option to redeem this Unsecured Senior Notes at March 15, 2021.

Schedule of principal repayments required on debt

The principal repayments required by the Partnership on its consolidated debt are as follows:


(millions of dollars)
2021			423
2022			450
2023			25
2024			—
2025			350
Thereafter			950
			2,198

OTHER LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2020

Other Liabilities Disclosure [Abstract]

Schedule of other liabilities


December 31 (millions of dollars)	2020	2019

Regulatory liabilities	38	29
Other liabilities	9	7
	47	36

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)

12 Months Ended

Dec. 31, 2020

Partners' Capital, Comprehensive Income [Abstract]

Schedule of changes in accumulated other comprehensive income (loss) (AOCI) by component

The changes in AOCI by component are as follows:


(millions of dollars)	Cash flow hedges	Equity Investments	Total
Balance at December 31, 2017	4	1	5
Change in fair value of cash flow hedges	(2)	—	(2)
Amounts reclassified from AOCI	5	—	5
PNGTS’ amortization of realized loss on derivative instrument (Note 19)	1	—	1
Other comprehensive income - effects of Iroquois’ retirement benefit plans	—	(1)	(1)
Net other comprehensive income	4	(1)	3
Balance at December 31, 2018	8	—	8
Change in fair value of cash flow hedges	(13)	—	(13)
Amounts reclassified from AOCI	(1)	—	(1)
Other comprehensive loss - effects of Iroquois’ retirement benefit plans	—	1	1
Net other comprehensive income (loss)	(14)	1	(13)
Balance as of December 31, 2019	(6)	1	(5)
Change in fair value of cash flow hedges	(16)	—	(16)
Amounts reclassified from AOCI	7	—	7
Other comprehensive income - effects of Iroquois’ retirement benefit plans	—	1	1
Net other comprehensive income (loss)	(9)	1	(8)
Balance as of December 31, 2020	(15)	2	(13)

FINANCIAL CHARGES AND OTHER (Tables)

12 Months Ended

Dec. 31, 2020

Other Expense, Nonoperating [Abstract]

Schedule of components of financial charges and other


Year ended December 31 (millions of dollars)	2020	2019	2018

Interest expense(a)	78	88	95
Net realized loss (gain) related to the interest rate swaps	7	(1)	(2)
PNGTS’ amortization of realized loss on derivative instrument (Note 19)	—	—	1
AFUDC - Equity	(10)	(2)	(1)
Other (b)	(2)	(2)	(1)
	73	83	92

(a)Interest expense includes amortization of debt issuance costs and discount costs amounting to approximately $2 million each year ended December 31, 2020, 2019 and 2018.

(b)Includes AFUDC Debt amounting to $1.3 million for the year ended December 31, 2020 (2019 and 2018 - less than $1 million).

NET INCOME (LOSS) PER COMMON UNIT (Tables)

12 Months Ended

Dec. 31, 2020

Earnings Per Share [Abstract]

Schedule of net income per common unit

Net income (loss) per common unit was determined as follows:


(millions of dollars, except per common unit amounts)	2020		2019		2018

Net income (loss) attributable to controlling interests	284		280		(182)
Amounts attributable to the Class B units (a)	—		(8)		(13)
Net income (loss) allocable to the General Partner and common units	284		272		(195)
Amounts attributable to General Partner's two percent interest	(6)		(5)		4
Net income (loss) attributable to common units	278		267		(191)
Weighted average common units outstanding (millions) – basic and diluted	71.3		71.3		71.3
Net income (loss) per common unit – basic and diluted	$	3.90	$	3.74	$	(2.68)

CASH DISTRIBUTIONS (Tables)

12 Months Ended

Dec. 31, 2020

Partners' Capital Account, Distributions [Abstract]

Schedule of allocations of available cash from operating surplus between common unitholders and General Partner


		Marginal Percentage Interest in Distribution
	Total Quarterly Distribution Per Unit Target Amount	Common Unitholders		General Partner
Minimum Quarterly Distribution	$0.45	98	%	2	%
First Target Distribution	above $0.45 up to $0.81	98	%	2	%
Second Target Distribution	above $0.81 up to $0.88	85	%	15	%
Thereafter	above $0.88	75	%	25	%

Schedule of distributions

The following table provides information about our distributions (in millions except per unit distributions amounts).


				Limited Partners				General Partner
Declaration Date	Payment Date	Per Unit Distribution		Common Units		Class B Units(b)		2		%	IDRs(a)		Total Cash Distribution
1/23/2018	2/13/2018	$	1.00	$	71	$	15	$	2		$	3	$	91
5/1/2018	5/15/2018	$	0.65	$	46	$	—	$	1		$	—	$	47
7/26/2018	8/15/2018	$	0.65	$	46	$	—	$	1		$	—	$	47
10/23/2018	11/14/2018	$	0.65	$	46	$	—	$	1		$	—	$	47
1/22/2019	2/11/2019	$	0.65	$	46	$	13	$	1		$	—	$	60
4/23/2019	5/13/2019	$	0.65	$	46	$	—	$	1		$	—	$	47
7/23/2019	8/14/2019	$	0.65	$	46	$	—	$	1		$	—	$	47
10/22/2019	11/14/2019	$	0.65	$	46	$	—	$	1		$	—	$	47
1/21/2020	2/14/2020	$	0.65	$	46	$	8	$	1		$	—	$	55
4/21/2020	5/12/2020	$	0.65	$	46	$	—	$	1		$	—	$	47
7/23/2020	8/14/2020	$	0.65	$	46	$	—	$	1		$	—	$	47
10/21/2020	11/13/2020	$	0.65	$	46	$	—	$	1		$	—	$	47
1/19/2021(c)	2/12/2021(c)	$	0.65	$	46	$	—	$	1		$	—	$	47

(a)The distributions paid during the year ended December 31, 2020 and 2019 included no incentive distributions to the General Partner (2018 - $3 million).

(c)On February 12, 2021, we paid a cash distribution of $0.65 per unit on our outstanding common units to unitholders of record at the close of business on January 29, 2021 (refer to Note 21).

CHANGE IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2020

Increase (Decrease) in Operating Capital [Abstract]

Schedule of change in operating working capital


Year Ended December 31 (millions of dollars)	2020	2019	2018
Change in accounts receivable and other	1	9	(6)
Change in inventory	(1)	(2)	—
Change in other current assets	—	—	(1)
Change in accounts payable and accrued liabilities (a)	5	(11)	3
Change in accounts payable to affiliates	(1)	2	1
Change in accrued interest	—	(1)	—
Change in operating working capital	4	(3)	(3)

(a)Excludes certain non-cash items primarily related to capital accruals and credits.

RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2020

Summary of capital and operating costs charged to pipeline systems by related party


Year ended December 31 (millions of dollars)	2020	2019	2018
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes (a)	66	47	44
Northern Border(a)	39	39	36
PNGTS (a)	6	7	9
GTN	68	45	34
Bison	2	2	6
North Baja	7	5	4
Tuscarora	6	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	16	20	19
Northern Border	16	18	16
PNGTS	3	4	5
GTN	29	33	28
Bison	2	2	6
North Baja	3	4	4
Tuscarora	3	4	4

Summary of amount payable to related party for costs charged


December 31 (millions of dollars)	2020	2019
Amount payable to TC Energy’s subsidiaries for costs charged in the year by:
Great Lakes (a)	3	5
Northern Border(a)	2	4
PNGTS (a)	1	1
GTN	4	5
Bison	—	—
North Baja	—	1
Tuscarora	1	—

(a)Represents 100 percent of the costs.

QUARTERLY FINANCIAL DATA (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2020

Quarterly Financial Information Disclosure [Abstract]

Schedule of quarterly financial information

The following sets forth selected unaudited financial data for the four quarters in 2020 and 2019:


Quarter ended (millions of dollars except per common unit amounts)	Mar 31		Jun 30		Sept 30		Dec 31
2020
Transmission revenues	101		95		99		104
Equity earnings	55		29		39		47
Net income (loss)	94		61		68		78
Net income (loss) attributable to controlling interests	88		57		65		74
Net income (loss) per common unit	$	1.21	$	0.78	$	0.90	$	1.01
Cash distributions paid to common units (a)	47		47		47		47
Cash distribution paid to Class B units	8		—		—		—
2019
Transmission revenues	113		93		93		104
Equity earnings	54		30		31		45
Net income	100		57		59		82
Net income attributable to controlling interests	93		55		56		76
Net income per common unit	$	1.28	$	0.75	$	0.76	$	0.95
Cash distributions paid to common units (a)	47		47		47		47
Cash distribution paid to Class B units	13		—		—		—

(a)Distributions paid to common units includes our general partner’s two percent share and IDRs, if any.

ACCOUNTS RECEIVABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2020

Receivables [Abstract]

Schedule of accounts receivable and other


December 31 (millions of dollars)	2020	2019
Trade accounts receivable, net of immaterial allowance for doubtful accounts	36	37
Receivable from affiliates	1	—
Other	3	6
	40	43

ORGANIZATION - Narrative (Details) - shares		12 Months Ended
ORGANIZATION - Narrative (Details) - shares	Dec. 14, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
TC Energy Merger
Partners' Equity
Common shares exchanged in merger (in shares)	0.70
Common units
Partners' Equity
Number of units (in units)		71,300,000	71,300,000	71,300,000
Common units \| General Partner \| TC Pipelines, LP
Partners' Equity
Limited partner interest (as a percent)		2.00%
Class B units \| TC Energy \| TC Energy
Partners' Equity
Limited partner interest (as a percent)		24.00%
Limited Partners \| Common units
Partners' Equity
Number of units (in units)		71,306,396
Limited Partners \| Common units \| TC Pipelines, LP
Partners' Equity
Number of units (in units)		5,797,106
Limited Partners \| Common units \| TC Energy
Partners' Equity
Number of units (in units)		11,287,725
Limited Partners \| Class B units \| TC Pipelines, LP
Partners' Equity
Limited partner interest (as a percent)		100.00%
Limited Partners \| Class B units \| TC Energy
Partners' Equity
Number of units (in units)		1,900,000
Limited partner interest (as a percent)		100.00%
General Partner \| TC Pipelines, LP
Partners' Equity
IDRs ownership		100.00%

ORGANIZATION - Schedule of ownership interests in natural gas pipeline systems (Details)	12 Months Ended
	Dec. 31, 2020 mi
GTN
Organization
Length of pipeline owned (in miles)	1,377
Ownership interest	100.00%
Bison
Organization
Length of pipeline owned (in miles)	303
Ownership interest	100.00%
North Baja
Organization
Length of pipeline owned (in miles)	86
Ownership interest	100.00%
Tuscarora
Organization
Length of pipeline owned (in miles)	305
Ownership interest	100.00%
Northern Border
Organization
Length of pipeline owned (in miles)	1,412
Ownership interest	50.00%
PNGTS
Organization
Length of pipeline owned (in miles)	295
Ownership interest	61.71%
PNGTS \| Maritimes and Northeast Pipeline LLC
Organization
Length of pipeline owned (in miles)	107
PNGTS \| Maritimes and Northeast Pipeline LLC \| PNGTS
Organization
Ownership interest	32.00%
Northern New England Investment \| PNGTS
Organization
Remaining noncontrolling ownership interest (as a percent)	38.29%
Great Lakes
Organization
Length of pipeline owned (in miles)	2,115
Ownership interest	46.45%
Great Lakes \| TC Energy
Organization
Remaining noncontrolling ownership interest (as a percent)	53.55%
Iroquois
Organization
Length of pipeline owned (in miles)	416
Ownership interest	49.34%
Iroquois \| TC Energy
Organization
Ownership interest	0.66%
Iroquois \| TC Energy
Organization
Remaining ownership interest (as a percent)	50.66%
Iroquois \| ONEOK Partners, L.P.
Organization
Remaining ownership interest (as a percent)	50.00%

SIGNIFICANT ACCOUNTING POLICIES - Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment
Depreciation expenses	$ 88.0	$ 78.0	$ 97.0
AFUDC - Equity	10.0	2.0	1.0
AFUDC debt	$ 1.3	$ 1.0	$ 1.0
Pipeline facilities and compression equipment \| Minimum
Property, Plant and Equipment
Estimated useful lives	20 years
Pipeline facilities and compression equipment \| Maximum
Property, Plant and Equipment
Estimated useful lives	68 years
Metering and other \| Minimum
Property, Plant and Equipment
Estimated useful lives	5 years
Metering and other \| Maximum
Property, Plant and Equipment
Estimated useful lives	77 years

SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - PNGTS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Oregon Department of Revenue
Income Taxes
Current state and local tax expense (benefit)	$ 0.6
New Hampshire Department of Revenue Administration
Income Taxes
Effective income tax rate (as a percent)	3.00%	2.60%	3.50%
State and local income tax expense (benefit), continuing operations	$ 5.0	$ (1.0)	$ 1.0

SIGNIFICANT ACCOUNTING POLICIES - Asset Retirement Obligation and Regulatory Assets (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Pipeline
Asset Retirement Obligation
Asset retirement liabilities	$ 0	$ 0

GOODWILL (Details) - USD ($) $ in Millions	12 Months Ended
GOODWILL (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
REGULATORY
Goodwill impairment charge	$ 0	$ 0	$ 59
Goodwill	$ 71	71
Long-term take-or-pay revenue	90.00%
North Baja
REGULATORY
Goodwill	$ 48	48
Tuscarora
REGULATORY
Goodwill	$ 23	$ 23
Tuscarora
REGULATORY
Goodwill impairment charge			59
Goodwill			$ 82

EQUITY INVESTMENTS - Summary of equity investments (Details) - USD ($)	1 Months Ended	3 Months Ended								12 Months Ended
	Apr. 30, 2006	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 06, 2020	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity Earnings		$ 47,000,000	$ 39,000,000	$ 29,000,000	$ 55,000,000	$ 45,000,000	$ 31,000,000	$ 30,000,000	$ 54,000,000	$ 170,000,000	$ 160,000,000	$ 173,000,000
Equity Investments		1,070,000,000				1,098,000,000				1,070,000,000	1,098,000,000
ASSETS
Current assets		257,000,000				156,000,000				257,000,000	156,000,000
Property, plant and equipment, net		1,747,000,000				1,528,000,000				1,747,000,000	1,528,000,000
Cash and cash equivalents		200,000,000				83,000,000				200,000,000	83,000,000
Other current assets		6,000,000				6,000,000				6,000,000	6,000,000
TOTAL ASSETS		3,145,000,000				2,853,000,000				3,145,000,000	2,853,000,000
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		487,000,000				170,000,000				487,000,000	170,000,000
Long-term debt, net		2,198,000,000								2,198,000,000
Deferred credits and other		47,000,000				36,000,000				47,000,000	36,000,000
Partners’ equity		833,000,000				760,000,000				833,000,000	760,000,000	699,000,000		$ 1,068,000,000
Accumulated other comprehensive loss		(13,000,000)				(5,000,000)				(13,000,000)	(5,000,000)
TOTAL LIABILITIES AND PARTNERS' EQUITY		3,145,000,000				2,853,000,000				3,145,000,000	2,853,000,000
Revenues (expenses)
Transmission revenues		104,000,000	$ 99,000,000	$ 95,000,000	$ 101,000,000	104,000,000	$ 93,000,000	$ 93,000,000	$ 113,000,000	399,000,000	403,000,000	549,000,000
Depreciation										(89,000,000)	(78,000,000)	(97,000,000)
Financial charges and other										(73,000,000)	(83,000,000)	(92,000,000)
Net income (loss)										284,000,000	280,000,000	(182,000,000)
Current maturities		423,000,000				123,000,000				423,000,000	123,000,000
Northern Border
ASSETS
Property, plant and equipment, net		977,000,000				989,000,000				977,000,000	989,000,000
Cash and cash equivalents		31,000,000				21,000,000				31,000,000	21,000,000
Other current assets		38,000,000				37,000,000				38,000,000	37,000,000
Other assets		12,000,000				12,000,000				12,000,000	12,000,000
TOTAL ASSETS		1,058,000,000				1,059,000,000				1,058,000,000	1,059,000,000
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		52,000,000				42,000,000				52,000,000	42,000,000
Long-term debt, net		380,000,000				364,000,000				380,000,000	364,000,000
Deferred credits and other		42,000,000				39,000,000				42,000,000	39,000,000
Partners’ capital		584,000,000				615,000,000				584,000,000	615,000,000
Accumulated other comprehensive loss		0				(1,000,000)				0	(1,000,000)
TOTAL LIABILITIES AND PARTNERS' EQUITY		1,058,000,000				1,059,000,000				1,058,000,000	1,059,000,000
Revenues (expenses)
Transmission revenues										308,000,000	300,000,000	289,000,000
Operating expenses										(77,000,000)	(82,000,000)	(78,000,000)
Depreciation										(62,000,000)	(62,000,000)	(60,000,000)
Financial charges and other										(18,000,000)	(18,000,000)	(15,000,000)
Net income (loss)										151,000,000	138,000,000	136,000,000
Current maturities		$ 250,000,000				0				$ 250,000,000	0
Stated interest rate		7.50%								7.50%
Great Lakes
ASSETS
Current assets		$ 66,000,000				72,000,000				$ 66,000,000	72,000,000
Property, plant and equipment, net		716,000,000				685,000,000				716,000,000	685,000,000
TOTAL ASSETS		782,000,000				757,000,000				782,000,000	757,000,000
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		38,000,000				33,000,000				38,000,000	33,000,000
Long-term debt, net		198,000,000				219,000,000				198,000,000	219,000,000
Deferred credits and other		9,000,000				6,000,000				9,000,000	6,000,000
Partners’ equity		537,000,000				499,000,000				537,000,000	499,000,000
TOTAL LIABILITIES AND PARTNERS' EQUITY		782,000,000				757,000,000				782,000,000	757,000,000
Revenues (expenses)
Transmission revenues										239,000,000	238,000,000	246,000,000
Operating expenses										(70,000,000)	(79,000,000)	(68,000,000)
Depreciation										(33,000,000)	(32,000,000)	(32,000,000)
Financial charges and other										(15,000,000)	(16,000,000)	(18,000,000)
Net income (loss)										121,000,000	111,000,000	128,000,000
Current maturities		31,000,000				21,000,000				31,000,000	21,000,000
Iroquois
ASSETS
Property, plant and equipment, net		506,000,000				570,000,000				506,000,000	570,000,000
Cash and cash equivalents		25,000,000				43,000,000				25,000,000	43,000,000
Other current assets		36,000,000				36,000,000				36,000,000	36,000,000
Other assets		20,000,000				16,000,000				20,000,000	16,000,000
TOTAL ASSETS		587,000,000				665,000,000				587,000,000	665,000,000
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		20,000,000				34,000,000				20,000,000	34,000,000
Long-term debt, net		314,000,000				317,000,000				314,000,000	317,000,000
Deferred credits and other		21,000,000				20,000,000				21,000,000	20,000,000
Partners’ equity		232,000,000				294,000,000				232,000,000	294,000,000
TOTAL LIABILITIES AND PARTNERS' EQUITY		587,000,000				665,000,000				587,000,000	665,000,000
Revenues (expenses)
Transmission revenues										183,000,000	180,000,000	194,000,000
Operating expenses										(59,000,000)	(58,000,000)	(57,000,000)
Depreciation										(30,000,000)	(29,000,000)	(29,000,000)
Financial charges and other										(15,000,000)	(11,000,000)	(14,000,000)
Net income (loss)										79,000,000	82,000,000	94,000,000
Current maturities		$ 5,000,000				3,000,000				$ 5,000,000	3,000,000
Northern Border
Schedule of Equity Method Investments [Line Items]
Interest acquired		50.00%								50.00%
Equity Earnings										$ 76,000,000	69,000,000	68,000,000
Equity Investments		$ 407,000,000				422,000,000				407,000,000	422,000,000
Transaction fee amortization period	12 years
Transaction fee	$ 10,000,000
Additional ownership percentage	20.00%
Equity Method Investment, Other than Temporary Impairment										$ 0	0	0
Great Lakes
Schedule of Equity Method Investments [Line Items]
Interest acquired		46.45%								46.45%
Equity Earnings										$ 56,000,000	51,000,000	59,000,000
Equity Investments		$ 509,000,000				491,000,000				$ 509,000,000	491,000,000
Iroquois
Schedule of Equity Method Investments [Line Items]
Interest acquired		49.34%								49.34%			49.34%
Equity Earnings										$ 38,000,000	40,000,000	$ 46,000,000
Equity Investments		$ 154,000,000				$ 185,000,000				$ 154,000,000	$ 185,000,000

EQUITY INVESTMENTS - Narrative (Details) - USD ($)			1 Months Ended			12 Months Ended
EQUITY INVESTMENTS - Narrative (Details) - USD ($)	Jan. 06, 2020	Nov. 01, 2019	Dec. 31, 2020	Aug. 31, 2019	Jun. 30, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Apr. 30, 2006
Schedule of Equity Method Investments [Line Items]
Distributions received from equity investments						$ 225,000,000	$ 258,000,000	$ 198,000,000
Return on investment distribution classified as investing activities						29,000,000	58,000,000	10,000,000
Partnership's share of distributions						196,000,000	200,000,000	188,000,000
Distribution made to limited partner, cash distributions paid						8,000,000	13,000,000	15,000,000
Northern Border
Schedule of Equity Method Investments [Line Items]
Distributions received from equity investments						91,000,000	144,000,000	83,000,000
Return on investment distribution classified as investing activities						$ 0	50,000,000	0
Ownership interest			50.00%			50.00%
Undistributed earnings						$ 0	0	0
Difference between carrying amount and underlying equity			$ 115,000,000			115,000,000	$ 115,000,000
Additional ownership percentage									20.00%
Northern Border \| Northern Border
Schedule of Equity Method Investments [Line Items]
Ownership interest							50.00%
Great Lakes
Schedule of Equity Method Investments [Line Items]
Distributions received from equity investments						$ 48,000,000	$ 59,000,000	58,000,000
Ownership interest			46.45%			46.45%
Undistributed earnings						$ 0	0	0
Difference between carrying amount and underlying equity			$ 260,000,000			260,000,000	260,000,000
Equity contribution						10,000,000	10,000,000	9,000,000
Iroquois
Schedule of Equity Method Investments [Line Items]
Distributions received from equity investments						86,000,000	55,000,000	56,000,000
Return on investment distribution classified as investing activities						$ 29,000,000	8,000,000	10,000,000
Ownership interest	49.34%		49.34%			49.34%
Partnership's share of distributions	$ 14,000,000
Undistributed earnings						$ 0	0	0
Difference between carrying amount and underlying equity			$ 39,000,000			39,000,000	40,000,000
Equity contribution			$ 2,000,000	$ 4,000,000		2,000,000	4,000,000	$ 0
Northern Border
Schedule of Equity Method Investments [Line Items]
Distribution made to limited partner, cash distributions paid					$ 100,000,000
Distribution finance by borrowings, percent					100.00%
Northern Border \| Revolving Credit Facility
Schedule of Equity Method Investments [Line Items]
Maximum borrowing capacity					$ 200,000,000
Iroquois
Schedule of Equity Method Investments [Line Items]
Return on investment distribution classified as investing activities						$ 5,000,000	$ 8,000,000
Ownership interest			49.34%			49.34%
Partnership's share of distributions						$ 4,000,000
Limited partners, Distribution declared		$ 28,000,000
Iroquois \| Special distribution, terminated project guaranteed proceeds
Schedule of Equity Method Investments [Line Items]
Return on investment distribution classified as investing activities						$ 24,000,000

REVENUES - Disaggregation of Revenues (Details) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2018 USD ($) customer	Dec. 31, 2018 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Disaggregation of Revenues
Provision For revenue sharing		$ 10.0
Contract balances			$ 36.0	$ 37.0
Bison
Disaggregation of Revenues
Non-refundable receipt from contract termination		$ 97.0
Number of customers that terminated transportation agreement \| customer	2
Bison \| Tenaska
Disaggregation of Revenues
Non-refundable receipt from contract termination	$ 95.4
Bison \| Another customer
Disaggregation of Revenues
Non-refundable receipt from contract termination	$ 2.0

PROPERTY, PLANT AND EQUIPMENT - Summary (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
PROPERTY, PLANT AND EQUIPMENT
Cost	$ 2,997	$ 2,715
Accumulated Depreciation	(1,250)	(1,187)
Net Book Value	1,747	1,528
Pipeline
PROPERTY, PLANT AND EQUIPMENT
Cost	1,910	1,907
Accumulated Depreciation	(982)	(929)
Net Book Value	928	978
Compression
PROPERTY, PLANT AND EQUIPMENT
Cost	730	584
Accumulated Depreciation	(210)	(202)
Net Book Value	520	382
Metering and other
PROPERTY, PLANT AND EQUIPMENT
Cost	208	180
Accumulated Depreciation	(58)	(56)
Net Book Value	150	124
Payment to acquire commercial system	26
Metering and other \| Great Lakes Gas Transmissions Limited Partnership
PROPERTY, PLANT AND EQUIPMENT
Payment to acquire commercial system	12
Construction in progress
PROPERTY, PLANT AND EQUIPMENT
Cost	149	44
Net Book Value	$ 149	$ 44

PROPERTY, PLANT AND EQUIPMENT - Property, Plant and Equipment Impairment in Bison (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Investments [Line Items]
Impairment of long-lived assets (Note 7)		$ 0	$ 0	$ 537
Bison
Schedule of Investments [Line Items]
Impairment of long-lived assets (Note 7)	$ 537

DEBT AND CREDIT FACILITIES - Schedule of Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	May 25, 2017
Debt and credit facilities
Total credit facilities, short-term loan facility and long-term debt	$ 2,198	$ 2,012
Less: unamortized debt issuance costs and debt discount	7	9
Current portion of long-term debt (Note 8)	423	123
Long-term debt	1,768	1,880
TC PipeLines, LP Senior Credit Facility due 2021
Debt and credit facilities
Debt and credit facilities	$ 0	$ 0
Weighted average interest rate (as a percent)	0.00%	0.00%
TC PipeLines, LP 2013 Term Loan Facility due 2022
Debt and credit facilities
Debt and credit facilities	$ 450	$ 450
Weighted average interest rate (as a percent)	1.87%	3.52%
TC PipeLines, LP 4.65% Senior Notes due 2021
Debt and credit facilities
Stated interest rate	4.65%	4.65%
Debt and credit facilities	$ 350	$ 350
Weighted average interest rate (as a percent)	4.65%	4.65%
TC PipeLines, LP 4.375% Senior Notes due 2025
Debt and credit facilities
Stated interest rate	4.375%	4.375%
Debt and credit facilities	$ 350	$ 350
Weighted average interest rate (as a percent)	4.375%	4.375%
TC PipeLines, LP 3.90% Senior Notes due 2027
Debt and credit facilities
Stated interest rate	3.90%	3.90%	3.90%
Debt and credit facilities	$ 500	$ 500
Weighted average interest rate (as a percent)	3.90%	3.90%
GTN 5.29% Senior Notes due 2020
Debt and credit facilities
Stated interest rate	5.29%	5.29%
Debt and credit facilities	$ 0	$ 100
Weighted average interest rate (as a percent)	0.00%	5.29%
GTN 5.69% Senior Notes due 2035
Debt and credit facilities
Stated interest rate	5.69%	5.69%
Debt and credit facilities	$ 150	$ 150
Weighted average interest rate (as a percent)	5.69%	5.69%
G T N Series A Senior Notes due 2030
Debt and credit facilities
Stated interest rate	3.12%
Debt and credit facilities	$ 175	$ 0
Weighted average interest rate (as a percent)	3.12%	0.00%
PNGTS Revolving Credit Facility due 2023
Debt and credit facilities
Debt and credit facilities	$ 25	$ 39
Weighted average interest rate (as a percent)	1.88%	3.47%
PNGTS Series A Senior Notes due 2030
Debt and credit facilities
Stated interest rate	2.84%
Debt and credit facilities	$ 125	$ 0
Weighted average interest rate (as a percent)	2.84%	0.00%
Tuscarora Term Loan due 2020
Debt and credit facilities
Debt and credit facilities	$ 23	$ 23
Weighted average interest rate (as a percent)	2.13%	3.39%
North Baja Term Loan Due 2021
Debt and credit facilities
Debt and credit facilities	$ 50	$ 50
Weighted average interest rate (as a percent)	1.70%	3.34%

DEBT AND CREDIT FACILITIES - Narrative (Details) - USD ($)						12 Months Ended
	Oct. 08, 2020	Jun. 01, 2020	Jun. 26, 2019	Sep. 29, 2017	May 25, 2017	Dec. 31, 2020	Dec. 31, 2019	Jul. 23, 2020	Dec. 19, 2018	Apr. 05, 2018
Iroquois
Credit facilities, short-term loan facility and long-term debt
Ownership interest					49.34%
PNGTS
Credit facilities, short-term loan facility and long-term debt
Ownership interest					11.81%
2013 Term Loan Facility
Credit facilities, short-term loan facility and long-term debt
Repayments of secured debt			$ 50,000,000
Unwind rate of interest rate swap (as a percent)			2.81%
TC PipeLines, LP Senior Credit Facility due 2021
Credit facilities, short-term loan facility and long-term debt
Maximum borrowing capacity						$ 500,000,000
Amount outstanding under credit facility						0
Remaining borrowing capacity						500,000,000
Increase in credit facility						500,000,000
Debt and credit facilities						$ 0	$ 0
TC PipeLines, LP 2013 Term Loan Facility due 2022
Credit facilities, short-term loan facility and long-term debt
Effective interest rate (as a percent)						1.40%	2.94%
Leverage ratio, actual (as a percent)						3.85%
Debt and credit facilities						$ 450,000,000	$ 450,000,000
TC PipeLines, LP 2013 Term Loan Facility due 2022 \| Fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, actual (as a percent)						5.50%
TC PipeLines, LP 2013 Term Loan Facility due 2022 \| Debt agreement covenants, periods subsequent to initial period after occurrence of acquisition
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, actual (as a percent)						5.00%
TC PipeLines, LP 2013 Term Loan Facility due 2022 \| Hedges of cash flows \| Interest rate swaps
Credit facilities, short-term loan facility and long-term debt
Effective interest rate (as a percent)						3.26%	3.26%
TC PipeLines, LP 2013 Term Loan Facility due 2022 \| Federal funds rate
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)				0.50%
TC PipeLines, LP 2013 Term Loan Facility due 2022 \| LIBOR
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)				1.00%
TC PipeLines, LP 2013 Term Loan Facility due 2022 \| LIBOR \| Minimum
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)				1.125%
TC PipeLines, LP 2013 Term Loan Facility due 2022 \| LIBOR \| Maximum
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)				2.00%
TC PipeLines, LP 2013 Term Loan Facility due 2022 \| Base rate \| Minimum
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)				0.125%
TC PipeLines, LP 2013 Term Loan Facility due 2022 \| Base rate \| Maximum
Credit facilities, short-term loan facility and long-term debt
Basis spread on variable rate (as a percent)				1.00%
TC PipeLines, LP 3.90% Senior Notes due 2027
Credit facilities, short-term loan facility and long-term debt
Amount of debt					$ 500,000,000
Stated interest rate					3.90%	3.90%	3.90%
Net proceeds					$ 497,000,000
Debt and credit facilities						$ 500,000,000	$ 500,000,000
PNGTS Senior Notes due 2030 \| PNGTS \| Senior notes
Credit facilities, short-term loan facility and long-term debt
Debt instrument, term	10 years
Amount of debt	$ 125,000,000
Stated interest rate	2.84%
GTN 5.29% Senior Notes due 2020
Credit facilities, short-term loan facility and long-term debt
Stated interest rate						5.29%	5.29%
Debt and credit facilities						$ 0	$ 100,000,000
GTN 5.29% Senior Notes due 2020 \| GTN \| Unsecured debt
Credit facilities, short-term loan facility and long-term debt
Amount of debt		$ 100,000,000
Stated interest rate		5.29%
GTN 3.12% Series A Senior Notes due 2030 \| GTN \| Secured debt
Credit facilities, short-term loan facility and long-term debt
Debt instrument, term		10 years
Amount of debt		$ 175,000,000
Stated interest rate		3.12%
GTN Private Shelf Facility \| GTN \| Secured debt
Credit facilities, short-term loan facility and long-term debt
Debt instrument, term	3 years
Amount of debt		$ 75,000,000
Percentage of debt to total capitalization, actual						36.80%
GTN Private Shelf Facility \| Maximum \| GTN \| Secured debt
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant		65.00%
GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Stated interest rate						5.69%	5.69%
Debt and credit facilities						$ 150,000,000	$ 150,000,000
GTN 5.69% Senior Notes due 2035 \| GTN \| Unsecured debt
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant		70.00%
PNGTS Revolving Credit Facility due 2023
Credit facilities, short-term loan facility and long-term debt
Maximum borrowing capacity										$ 125,000,000
Amount outstanding under credit facility						$ 25,000,000
Leverage ratio, actual (as a percent)						1.99%				5.00%
Interest rate (as a percent)						1.28%	2.99%
Debt and credit facilities						$ 25,000,000	$ 39,000,000
PNGTS Private Shelf Facility \| PNGTS \| Senior notes
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, actual (as a percent)						199.00%
Debt instrument, term	3 years
Amount of debt	$ 125,000,000
Ratio of debt to capitalization						0.37
PNGTS Private Shelf Facility \| Maximum \| PNGTS \| Senior notes
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, actual (as a percent)	500.00%
Percentage of debt to total capitalization, covenant	65.00%
Tuscarora Term Loan due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities						$ 23,000,000	$ 23,000,000
North Baja Term Loan Due 2021
Credit facilities, short-term loan facility and long-term debt
Effective interest rate (as a percent)						1.23%	2.77%
Amount of debt									$ 50,000,000
Debt and credit facilities						$ 50,000,000	$ 50,000,000
Percentage of debt to total capitalization, covenant						70.00%
Percentage of debt to total capitalization, actual						40.80%
Term Loan due 2021
Credit facilities, short-term loan facility and long-term debt
Effective interest rate (as a percent)						2.15%	2.82%
Debt service coverage, covenant (as a percent)						3.00%
Debt service coverage, actual (as a percent)						31.16%
Term Loan due 2021 \| Tuscarora \| Unsecured debt
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities								$ 23,000,000

DEBT AND CREDIT FACILITIES - Principal Repayments Required (Details) $ in Millions	Dec. 31, 2020 USD ($)
Principal repayments required on debt
2021	$ 423
2022	450
2023	25
2024	0
2025	350
Thereafter	950
Total debt	$ 2,198

OTHER LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Other Liabilities Disclosure [Abstract]
Regulatory liabilities	$ 38	$ 29
Other liabilities	9	7
Other liabilities, total	$ 47	$ 36

PARTNERS' EQUITY - Ownership (Details) - shares	12 Months Ended
PARTNERS' EQUITY - Ownership (Details) - shares	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
TC Pipelines, LP
PARTNERS' EQUITY
Ownership interest in the partnership	2.00%
Common units
PARTNERS' EQUITY
Common units outstanding, end of year (in units)	71,300,000	71,300,000	71,300,000
Common units \| TC Pipelines, LP \| General Partner
PARTNERS' EQUITY
Ownership interest in the partnership	2.00%	2.00%	2.00%
Ownership interest (as a percent)	2.00%
Common units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (in units)	71,306,396
Class B units \| Limited Partners \| TC Pipelines, LP
PARTNERS' EQUITY
Ownership interest (as a percent)	100.00%
Class B units \| Limited Partners \| TC Energy
PARTNERS' EQUITY
Common units outstanding, end of year (in units)	1,900,000
Ownership interest (as a percent)	100.00%
Non-affiliates \| Common units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (in units)	54,221,565
TC Pipelines, LP \| General Partner
PARTNERS' EQUITY
IDRs ownership	100.00%
TC Pipelines, LP \| Common units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (in units)	5,797,106
TransCanada Corporation and subsidiaries \| Common units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (in units)	17,084,831
TC Energy \| Common units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (in units)	11,287,725
TC Energy \| Class B units \| TC Energy
PARTNERS' EQUITY
Ownership interest (as a percent)	24.00%

PARTNERS' EQUITY - ATM Equity Issuance Program (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
ATM Equity Issuance Program \| Common units
PARTNERS' EQUITY
Common units issued (in units)		0	700,000
Net proceeds from issuance of common units			$ 39
ATM Equity Issuance Program \| TC Pipelines, LP \| General Partner
PARTNERS' EQUITY
Equity contribution			$ 1
TC Pipelines, LP
PARTNERS' EQUITY
Ownership interest in the partnership	2.00%
TC Pipelines, LP \| General Partner \| Common units
PARTNERS' EQUITY
Ownership interest in the partnership	2.00%	2.00%	2.00%

PARTNERS' EQUITY - Class B Units (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended	12 Months Ended
	Apr. 01, 2015	Dec. 31, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
PARTNERS' EQUITY
Net income allocated to partner			$ 278	$ 267	$ (191)
Common units
PARTNERS' EQUITY
Net income allocated to partner			$ 278	267	(191)
Class B units
PARTNERS' EQUITY
Distribution of Class B units (in shares)			0
Net income allocated to partner			$ 8	13
TC Energy
PARTNERS' EQUITY
Remaining ownership interest (as a percent)			30.00%
TC Energy \| Distributions \| Common units
PARTNERS' EQUITY
Percentage of reduction in distributions payable		35.00%
Distribution per common unit		$ 1.00
Minimum distribution payable per common unit			$ 3.94
TC Energy \| Distributions \| Class B units
PARTNERS' EQUITY
Percentage of reduction in distributions payable			35.00%
GTN \| TC Energy \| Class B units
PARTNERS' EQUITY
Percentage applied to 30 percent of GTN's distributions above threshold for the year ending March 31, 2020			100.00%
GTN \| TC Energy \| Distributions \| Class B units
PARTNERS' EQUITY
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)	30.00%		30.00%
Percentage applied to 30 percent of GTN's distributions above threshold for the year ending March 31, 2020			43.75%
Threshold of GTN's total distributable cash flows for payment to Class B units for the March 31, 2020			$ 20
Percentage applied to GTN's distributions above threshold			25.00%
Threshold of GTN's distributions for payment to Class B units			$ 20	$ 20	$ 20
Percentage of reduction in distributions payable			35.00%

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Changes in accumulated other comprehensive income (loss) (AOCI) by component

Partners' Equity at beginning of period

$ 760

$ 699

$ 1,068

Change in fair value of cash flow hedges

(16)

(13)

(2)

Amounts reclassified from AOCI

(1)

PNGTS’ amortization of realized loss on derivative instrument (Note 19)

Other comprehensive income - effects of Iroquois’ retirement benefit plans

(1)

Net other comprehensive income

(8)

(13)

Partners' Equity at end of period

833

760

699

Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss) (AOCI) by component

Partners' Equity at beginning of period

^[1]

(5)

Net other comprehensive income

^[1]

(8)

(13)

Partners' Equity at end of period

^[1]

(13)

(5)

Cash flow hedges

Changes in accumulated other comprehensive income (loss) (AOCI) by component

Partners' Equity at beginning of period

(6)

Change in fair value of cash flow hedges

(16)

(13)

(2)

Amounts reclassified from AOCI

(1)

PNGTS’ amortization of realized loss on derivative instrument (Note 19)

Other comprehensive income - effects of Iroquois’ retirement benefit plans

Net other comprehensive income

(9)

(14)

Partners' Equity at end of period

(15)

(6)

Equity Investments

Changes in accumulated other comprehensive income (loss) (AOCI) by component

Partners' Equity at beginning of period

Change in fair value of cash flow hedges

Amounts reclassified from AOCI

PNGTS’ amortization of realized loss on derivative instrument (Note 19)

Other comprehensive income - effects of Iroquois’ retirement benefit plans

(1)

Net other comprehensive income

(1)

Partners' Equity at end of period

$ 2

$ 1

$ 0

[1]

FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Expense, Nonoperating [Abstract]
Interest expense	$ 78.0	$ 88.0	$ 95.0
Net realized loss (gain) related to the interest rate swaps	7.0	(1.0)	(2.0)
PNGTS' amortization of loss on derivative instrument	0.0	0.0	1.0
AFUDC - Equity	(10.0)	(2.0)	(1.0)
Other (b)	(2.0)	(2.0)	(1.0)
Financial charges and other	73.0	83.0	92.0
Amortization of debt issuance costs and discounts	2.0	2.0	2.0
AFUDC debt	$ 1.3	$ 1.0	$ 1.0

NET INCOME (LOSS) PER COMMON UNIT - Narrative (Details) - USD ($)		3 Months Ended	12 Months Ended
	Apr. 01, 2015	Dec. 31, 2017	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
TC Pipelines, LP
PARTNERS' EQUITY
General partner interest			(2.00%)
General Partner \| Common units \| TC Pipelines, LP
PARTNERS' EQUITY
General partner interest			(2.00%)	(2.00%)	(2.00%)
TC Energy \| GTN \| Class B units
PARTNERS' EQUITY
Class B reduction				$ 4,000,000	$ 7,000,000
TC Energy \| Distributions \| Common units
PARTNERS' EQUITY
Percentage of reduction in distributions payable		35.00%
TC Energy \| Distributions \| Class B units
PARTNERS' EQUITY
Percentage of reduction in distributions payable			35.00%
TC Energy \| Distributions \| GTN \| Class B units
PARTNERS' EQUITY
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)	30.00%		30.00%
Threshold of GTN's distributions for payment to Class B units			$ 20,000,000	20,000,000	20,000,000
Percentage of distributions above threshold			43.75%
Percentage of reduction in distributions payable			35.00%
Portion of annual distributions entitled to receive a percentage share of the distributions above threshold			30.00%
Class B reduction			$ 0	$ 8,000,000	$ 13,000,000

NET INCOME (LOSS) PER COMMON UNIT - Determination of Net Income (Loss) per Common Unit (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net income (loss) per common unit
Net income (loss) attributable to controlling interests									$ 284	$ 280	$ (182)
Amounts attributable to the Class B units									0	(8)	(13)
Net income (loss) allocable to the General Partner and common units									284	272	(195)
Amounts attributable to General Partner's two percent interest									(6)	(5)	4
Common units									$ 278	$ 267	$ (191)
Weighted average common units outstanding – basic and diluted (in units)									71,300,000	71,300,000	71,300,000
Net income (loss) per common unit - basic and diluted (in dollars per unit)	$ 1.01	$ 0.90	$ 0.78	$ 1.21	$ 0.95	$ 0.76	$ 0.75	$ 1.28	$ 3.90	$ 3.74	$ (2.68)
Common units
Net income (loss) per common unit
Common units									$ 278	$ 267	$ (191)
Weighted average common units outstanding – basic and diluted (in units)									71,300,000	71,300,000	71,300,000
Net income (loss) per common unit - basic and diluted (in dollars per unit)									$ 3.90	$ 3.74	$ (2.68)
TC Pipelines, LP
Net income (loss) per common unit
General partner interest									(2.00%)
General Partner \| TC Pipelines, LP \| Common units
Net income (loss) per common unit
General partner interest									(2.00%)	(2.00%)	(2.00%)

CASH DISTRIBUTIONS - Quarterly Distributions (Details)	12 Months Ended
CASH DISTRIBUTIONS - Quarterly Distributions (Details)	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash distributions
Period after the end of each quarter within which quarterly cash distributions to partners are to be paid	45 days
TC Pipelines, LP
Cash distributions
Ownership interest in the partnership	2.00%
General Partner \| TC Pipelines, LP \| Common units
Cash distributions
Ownership interest in the partnership	2.00%	2.00%	2.00%

CASH DISTRIBUTIONS - General Partner Distribution Incentives (Details)	12 Months Ended
	Dec. 31, 2020 $ / shares
Minimum Quarterly Distribution
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.45
Thereafter
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	0.88
Minimum \| First Target Distribution
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	0.45
Minimum \| Second Target Distribution
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	0.81
Maximum \| First Target Distribution
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	0.81
Maximum \| Second Target Distribution
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.88
Limited Partners \| Common units \| Minimum Quarterly Distribution
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	98.00%
Limited Partners \| Common units \| First Target Distribution
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	98.00%
Limited Partners \| Common units \| Second Target Distribution
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	85.00%
Limited Partners \| Common units \| Thereafter
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	75.00%
General Partner \| Minimum Quarterly Distribution
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	2.00%
General Partner \| First Target Distribution
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	2.00%
General Partner \| Second Target Distribution
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	15.00%
General Partner \| Thereafter
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	25.00%

CASH DISTRIBUTIONS - Distributions by Payment Date (Details) - USD ($)															3 Months Ended								12 Months Ended
	Feb. 12, 2021	Nov. 13, 2020	Aug. 14, 2020	May 12, 2020	Feb. 14, 2020	Nov. 14, 2019	Aug. 14, 2019	May 13, 2019	Feb. 11, 2019	Nov. 14, 2018	Aug. 15, 2018	May 15, 2018	Feb. 13, 2018	Apr. 01, 2015	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Partners' Equity
Per Unit Distribution, paid (in dollars per unit)		$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 1.00
Cash distribution																							$ 8,000,000	$ 13,000,000	$ 15,000,000
General Partner 2% paid		$ 1,000,000	$ 1,000,000	$ 1,000,000	$ 1,000,000	$ 1,000,000	$ 1,000,000	$ 1,000,000	$ 1,000,000	$ 1,000,000	$ 1,000,000	$ 1,000,000	$ 2,000,000
General Partner IDRs paid		0	0	0	0	0	0	0	0	0	0	0	3,000,000										0	0	3,000,000
Total Cash Distribution		47,000,000	47,000,000	47,000,000	55,000,000	47,000,000	47,000,000	47,000,000	60,000,000	47,000,000	47,000,000	47,000,000	91,000,000										$ 189,000,000	$ 189,000,000	$ 218,000,000
T C Pipelines L
Partners' Equity
Ownership interest in the partnership																							2.00%
Subsequent Events
Partners' Equity
Per Unit Distribution, paid (in dollars per unit)	$ 0.65
General Partner 2% paid	$ 1,000,000
General Partner IDRs paid	0
Total Cash Distribution	$ 47,000,000
Common units
Partners' Equity
Cash distribution		46,000,000	46,000,000	46,000,000	46,000,000	46,000,000	46,000,000	46,000,000	46,000,000	46,000,000	46,000,000	46,000,000	71,000,000
Total Cash Distribution															$ 47,000,000	$ 47,000,000	$ 47,000,000	$ 47,000,000	$ 47,000,000	$ 47,000,000	$ 47,000,000	$ 47,000,000
Common units \| Subsequent Events
Partners' Equity
Per Unit Distribution, paid (in dollars per unit)	$ 0.65
Cash distribution	$ 46,000,000
Class B units
Partners' Equity
Cash distribution		$ 0	$ 0	$ 0	$ 8,000,000	$ 0	$ 0	$ 0	$ 13,000,000	$ 0	$ 0	$ 0	$ 15,000,000
Total Cash Distribution															$ 0	$ 0	$ 0	$ 8,000,000	$ 0	$ 0	$ 0	$ 13,000,000
Class B units \| Subsequent Events
Partners' Equity
Cash distribution	$ 0
GTN \| Class B units \| TC Energy \| Distributions
Partners' Equity
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)														30.00%									30.00%
General Partner \| Common units \| T C Pipelines L
Partners' Equity
Ownership interest in the partnership																							2.00%	2.00%	2.00%

CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) in Operating Capital [Abstract]
Change in accounts receivable and other	$ 1	$ 9	$ (6)
Change in inventory	(1)	(2)	0
Change in other current assets	0	0	(1)
Change in accounts payable and accrued liabilities	5	(11)	3
Change in accounts payable to affiliates	(1)	2	1
Change in accrued interest	0	(1)	0
Change in operating working capital	$ 4	$ (3)	$ (3)

TRANSACTIONS WITH MAJOR CUSTOMERS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019
Transactions with major customers
Trade accounts receivable		$ 36	$ 37
Trade accounts receivable \| Credit Concentration Risk \| Tenaska
Transactions with major customers
Trade accounts receivable	$ 4
Concentration percentage	10.00%
Revenues \| Credit Concentration Risk \| Anadarko/Tenaska customer group
Transactions with major customers
Concentration percentage	36.00%
Revenues	$ 144

RELATED PARTY TRANSACTIONS (Details) MMBTU / d in Thousands		1 Months Ended	12 Months Ended
RELATED PARTY TRANSACTIONS (Details) MMBTU / d in Thousands	Aug. 01, 2020 USD ($)	Sep. 21, 2017 Bcf	Dec. 31, 2020 USD ($) MMBTU / d	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Mar. 31, 2020 USD ($)
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable			$ 7,000,000	$ 8,000,000
Amount included in receivables from related party			1,000,000	0
General Partner \| Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			4,000,000	4,000,000	$ 4,000,000
ANR Pipeline Company \| Technology-Based Intangible Assets [Member]
Capital and operating costs charged to the pipeline systems and amount payable
Finite-lived intangible assets acquired	$ 51,000,000
TC Energy \| ANR Pipeline Company \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Contract term		10 years
Great Lakes \| TransCanada's subsidiaries
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party			17,000,000	19,000,000
Great Lakes \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable			3,000,000	5,000,000
Great Lakes \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			66,000,000	47,000,000	44,000,000
Impact on the Partnership's net income attributable to controlling interests			16,000,000	20,000,000	19,000,000
Amount included in receivables from related party			27,000,000	34,000,000
Great Lakes \| TC Energy \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Revenues			$ 75,000,000	$ 76,000,000	$ 76,000,000
Great Lakes \| TC Energy \| Transportation contracts \| Total net revenues \| Customer concentration risk
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues			73.00%	73.00%	73.00%
Great Lakes \| TC Energy \| Affiliated rental revenue \| Maximum
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues				1.00%	1.00%
Great Lakes \| ANR Pipeline Company \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Contract term			20 years		15 years
Transportation capacity per day \| Bcf		0.711
Total contract value			$ 182,000,000		$ 1,300,000,000
Contract capacity \| MMBTU / d			168
Contract value terminated						$ 1,100,000,000
Northern Border \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable			$ 2,000,000	$ 4,000,000
Northern Border \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			39,000,000	39,000,000	36,000,000
Impact on the Partnership's net income attributable to controlling interests			16,000,000	18,000,000	16,000,000
Northern Border \| Affiliates \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party			0	0
Revenues from related party			800,000	0	0
PNGTS \| TransCanada's subsidiaries \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party			0	0
Revenues from related party				1,000,000	1,000,000
PNGTS \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable			1,000,000	1,000,000
PNGTS \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			6,000,000	7,000,000	9,000,000
Impact on the Partnership's net income attributable to controlling interests			$ 3,000,000	4,000,000	5,000,000
PNGTS \| Affiliates \| Portland XPress expansion project (PXP), Phase III
Capital and operating costs charged to the pipeline systems and amount payable
Phase in period			3 years
GTN \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable			$ 4,000,000	5,000,000
GTN \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			68,000,000	45,000,000	34,000,000
Impact on the Partnership's net income attributable to controlling interests			$ 29,000,000	$ 33,000,000	$ 28,000,000
Percentage of capital and operating costs charged			100.00%	100.00%	100.00%
Bison \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable			$ 0	$ 0
Bison \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			2,000,000	2,000,000	$ 6,000,000
Impact on the Partnership's net income attributable to controlling interests			2,000,000	2,000,000	6,000,000
North Baja \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable			0	1,000,000
North Baja \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			7,000,000	5,000,000	4,000,000
Impact on the Partnership's net income attributable to controlling interests			3,000,000	4,000,000	4,000,000
Tuscarora \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable			1,000,000	0
Tuscarora \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			6,000,000	4,000,000	4,000,000
Impact on the Partnership's net income attributable to controlling interests			$ 3,000,000	$ 4,000,000	$ 4,000,000
TC Pipelines, LP \| ANR Pipeline Company \| Technology-Based Intangible Assets [Member]
Capital and operating costs charged to the pipeline systems and amount payable
Finite-lived intangible assets acquired	$ 38,000,000

QUARTERLY FINANCIAL DATA (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions													3 Months Ended								12 Months Ended
	Nov. 13, 2020	Aug. 14, 2020	May 12, 2020	Feb. 14, 2020	Nov. 14, 2019	Aug. 14, 2019	May 13, 2019	Feb. 11, 2019	Nov. 14, 2018	Aug. 15, 2018	May 15, 2018	Feb. 13, 2018	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Limited Partners' Capital Account [Line Items]
Transmission revenues													$ 104	$ 99	$ 95	$ 101	$ 104	$ 93	$ 93	$ 113	$ 399	$ 403	$ 549
Equity earnings (Note 5)													47	39	29	55	45	31	30	54	$ 170	$ 160	$ 173
Net income (loss)													78	68	61	94	82	59	57	100
Net income (loss) attributable to controlling interests													$ 74	$ 65	$ 57	$ 88	$ 76	$ 56	$ 55	$ 93
Net income (loss) per common unit - basic and diluted (in dollars per unit)													$ 1.01	$ 0.90	$ 0.78	$ 1.21	$ 0.95	$ 0.76	$ 0.75	$ 1.28	$ 3.90	$ 3.74	$ (2.68)
Total Cash Distribution	$ 47	$ 47	$ 47	$ 55	$ 47	$ 47	$ 47	$ 60	$ 47	$ 47	$ 47	$ 91									$ 189	$ 189	$ 218
TC Pipelines, LP
Limited Partners' Capital Account [Line Items]
Ownership interest in the partnership																					2.00%
Common units
Limited Partners' Capital Account [Line Items]
Net income (loss) per common unit - basic and diluted (in dollars per unit)																					$ 3.90	$ 3.74	$ (2.68)
Total Cash Distribution													$ 47	$ 47	$ 47	$ 47	$ 47	$ 47	$ 47	$ 47
Class B units
Limited Partners' Capital Account [Line Items]
Total Cash Distribution													$ 0	$ 0	$ 0	$ 8	$ 0	$ 0	$ 0	$ 13

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Millions		12 Months Ended
FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Millions	Jun. 26, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Interest rate derivatives
Change in fair value of cash flow hedges (Notes 11 and 19)		$ (16.0)	$ (13.0)	$ (2.0)
Amortization of Derivatives Loss		0.0	0.0	$ 1.0
Accounts receivable
Interest rate derivatives
Maximum counterparty credit exposure		$ 0.0
2013 Term Loan Facility
Interest rate derivatives
Repayments of secured debt	$ 50.0
Unwind rate of interest rate swap (as a percent)	2.81%
Secured debt \| PNGTS 5.90% Senior Secured Notes due 2018
Interest rate derivatives
Stated interest rate				5.90%
Interest rate swaps \| Term loan \| TC PipeLines, LP 2013 Term Loan Facility due 2022
Interest rate derivatives
Weighted average fixed interest rate (as a percent)		3.26%
Hedges of cash flows \| Interest rate swaps \| Financial charges and other
Interest rate derivatives
Net realized gain related to the interest rate swaps included in financial charges and other		$ (7.0)	1.0	$ 2.0
Hedges of cash flows \| Recurring fair value measurement \| Level 2 \| Interest rate swaps
Interest rate derivatives
Fair value of derivative liability, gross		15.0	6.0
Fair value of derivative liability, net		15.0	6.0
PNGTS
Interest rate derivatives
Amortization of Derivatives Loss				$ 1.0
PNGTS
Interest rate derivatives
Ownership interest (as a percent)				61.71%
PNGTS
Interest rate derivatives
Payments for derivative instruments				$ 20.9
Change in fair value of cash flow hedges (Notes 11 and 19)				$ 20.9
Fair Value \| Level 2
Interest rate derivatives
Fair value of debt		$ 2,388.0	$ 2,111.0

ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Receivables [Abstract]
Trade accounts receivable, net of immaterial allowance for doubtful accounts	$ 36	$ 37
Receivable from affiliates	1	0
Other	3	6
Accounts receivable and other	$ 40	$ 43

SUBSEQUENT EVENTS - Distributions (Details) - USD ($)																						1 Months Ended	3 Months Ended	12 Months Ended
SUBSEQUENT EVENTS - Distributions (Details) - USD ($)	Mar. 24, 2021	Feb. 26, 2021	Feb. 18, 2021	Feb. 16, 2021	Feb. 12, 2021	Jan. 29, 2021	Jan. 19, 2021	Jan. 15, 2021	Jan. 13, 2021	Nov. 13, 2020	Aug. 14, 2020	May 12, 2020	Feb. 14, 2020	Nov. 14, 2019	Aug. 14, 2019	May 13, 2019	Feb. 11, 2019	Nov. 14, 2018	Aug. 15, 2018	May 15, 2018	Feb. 13, 2018	Jun. 30, 2019	Dec. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Distributions
Cash distribution																								$ 8,000,000	$ 13,000,000	$ 15,000,000
Partnership's share of distributions																								196,000,000	200,000,000	188,000,000
TC PipeLines, LP Senior Credit Facility due 2021
Distributions
Debt and credit facilities																							$ 0	0	0
Maximum borrowing capacity																							500,000,000	500,000,000
TC PipeLines, LP Senior Credit Facility due 2021 \| Revolving Credit Facility
Distributions
Maximum borrowing capacity																							500,000,000	500,000,000
TC PipeLines, LP 4.65% Senior Notes due 2021
Distributions
Debt and credit facilities																							$ 350,000,000	$ 350,000,000	$ 350,000,000
Stated interest rate																							4.65%	4.65%	4.65%
TC Pipelines, LP
Distributions
Ownership interest in the partnership																								2.00%
Northern Border
Distributions
Ownership interest																							50.00%	50.00%
Great Lakes
Distributions
Ownership interest																							46.45%	46.45%
Equity contribution																								$ 10,000,000	$ 10,000,000	$ 9,000,000
General Partner
Distributions
Total cash distribution																							$ 0
Northern Border
Distributions
Cash distribution																						$ 100,000,000
Northern Border \| Revolving Credit Facility
Distributions
Maximum borrowing capacity																						$ 200,000,000
Subsequent Events
Distributions
Total cash distribution					$ 47,000,000
Subsequent Events \| TC PipeLines, LP 4.65% Senior Notes due 2021
Distributions
Redemption price					100.00%
Subsequent Events \| Northern Border
Distributions
Ownership interest				50.00%				50.00%
Partnership's share of distributions		$ 9,000,000				$ 8,000,000
Subsequent Events \| Great Lakes
Distributions
Ownership interest									46.45%
Partnership's share of distributions						11,000,000
Subsequent Events \| Iroquois
Distributions
Ownership interest			49.34%
Partnership's share of distributions	$ 11,000,000
Subsequent Events \| Northern Border
Distributions
Cash distribution								$ 16,000,000
Limited partners, Distribution declared				$ 18,000,000
Subsequent Events \| Great Lakes
Distributions
Limited partners, Distribution declared									$ 23,000,000
Subsequent Events \| Iroquois
Distributions
Limited partners, Distribution declared			$ 22,000,000
Subsequent Events \| Iroquois \| Forecast
Distributions
Equity contribution	$ 1,000,000
Subsequent Events \| PNGTS
Distributions
Limited partners, Distribution declared									$ 12,000,000
Share of distributions to its non-controlling interest owner						$ 5,000,000
TC Pipelines, LP \| Subsequent Events \| Two Percent interest
Distributions
General partnership distribution paid					$ 1,000,000
Common units
Distributions
Cash distribution										$ 46,000,000	$ 46,000,000	$ 46,000,000	$ 46,000,000	$ 46,000,000	$ 46,000,000	$ 46,000,000	$ 46,000,000	$ 46,000,000	$ 46,000,000	$ 46,000,000	$ 71,000,000
Number of units (in units)																							71,300,000	71,300,000	71,300,000	71,300,000
Common units \| General Partner \| TC Pipelines, LP
Distributions
Ownership interest in the partnership																								2.00%	2.00%	2.00%
Common units \| Subsequent Events
Distributions
Per Unit Distribution, declared (in dollars per unit)							$ 0.65
Cash distribution					46,000,000
Common units \| Limited Partners
Distributions
Number of units (in units)																							71,306,396	71,306,396
Common units \| TC Pipelines, LP \| Subsequent Events
Distributions
Cash distribution					$ 4,000,000
Common units \| TC Pipelines, LP \| Limited Partners
Distributions
Number of units (in units)																							5,797,106	5,797,106
Common units \| TC Pipelines, LP \| Limited Partners \| Subsequent Events
Distributions
Number of units (in units)					5,797,106
Common units \| TC Energy \| Subsequent Events
Distributions
Cash distribution					$ 7,000,000
Common units \| TC Energy \| Limited Partners
Distributions
Number of units (in units)																							11,287,725	11,287,725
Common units \| TC Energy \| Limited Partners \| Subsequent Events
Distributions
Number of units (in units)					11,287,725