View Filing Data

PROPERTY, PLANT AND EQUIPMENT (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
PROPERTY, PLANT AND EQUIPMENT
Cost	$ 2,715	$ 2,639
Accumulated Depreciation	(1,187)	(1,110)
Net Book Value	1,528	1,529
Pipeline
PROPERTY, PLANT AND EQUIPMENT
Cost	1,907	1,901
Accumulated Depreciation	(929)	(876)
Net Book Value	978	1,025
Compression
PROPERTY, PLANT AND EQUIPMENT
Cost	584	550
Accumulated Depreciation	(202)	(182)
Net Book Value	382	368
Metering and other
PROPERTY, PLANT AND EQUIPMENT
Cost	180	176
Accumulated Depreciation	(56)	(52)
Net Book Value	124	124
Construction in progress
PROPERTY, PLANT AND EQUIPMENT
Cost	44	12
Net Book Value	$ 44	$ 12

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 83	$ 33
Accounts receivable and other (Note 21)	43	48
Distribution receivable from Iroquois (Note 5)	14
Inventories	10	8
Other	6	8
Total current assets	156	97
Equity investments (Note 5)	1,098	1,196
Property, plant and equipment, net (Note 7)	1,528	1,529
Goodwill (Note 4)	71	71
Other assets		6
TOTAL ASSETS	2,853	2,899
Current Liabilities
Accounts payable and accrued liabilities	28	36
Accounts payable to affiliates (Note 18)	8	6
Accrued interest	11	12
Current portion of long-term debt (Note 9)	123	36
Total current liabilities	170	90
Long-term debt (Note 9)	1,880	2,072
Deferred state income taxes (Note 2)	7	9
Other liabilities (Note 10)	36	29
Total liabilities	2,093	2,200
Partners' Equity (Note 11)
General partner	14	13
Accumulated other comprehensive income (loss) (AOCI) (Note 12)	(5)	8
Controlling interests	656	591
Non-controlling interest	104	108
Total partners' equity	760	699
TOTAL LIABILITIES AND PARTNERS' EQUITY	2,853	2,899
Common Units
Partners' Equity (Note 11)
Limited partner	544	462
Class B Units
Partners' Equity (Note 11)
Limited partner	$ 103	$ 108

CONSOLIDATED STATEMENT OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash Generated from Operations
Net income (loss)	$ 298.0	$ (165.0)	$ 263.0
Depreciation	78.0	97.0	97.0
Impairment of long lived assets (Note 7)		537.0
Impairment of goodwill (Note 4)		59.0
Amortization of debt issue costs reported as interest expense (Note 13)	2.0	2.0	2.0
Amortization of realized loss on derivative instrument (Note 20)		1.0	1.0
Equity earnings from equity investments (Note 5)	(160.0)	(173.0)	(124.0)
Distributions received from operating activities of equity investments (Note 5)	200.0	188.0	140.0
Change in other long-term liabilities	(1.0)	(2.0)
Equity allowance for funds used during construction	(2.0)	(1.0)	(1.0)
Change in operating working capital (Note 16)	(3.0)	(3.0)	(2.0)
Cash generated from operations	412.0	540.0	376.0
Investing Activities
Distribution received from return of investment (Note 5)	58.0	10.0	5.0
Capital expenditures	(75.0)	(40.0)	(29.0)
Other	(1.0)	4.0	1.0
Investing activities	(32.0)	(35.0)	(761.0)
Financing Activities
Distributions paid (Note 15)	(189.0)	(218.0)	(284.0)
Distributions paid to non-controlling interests	(22.0)	(14.0)	(5.0)
Distributions paid to former parent of PNGTS			(1.0)
Common unit issuance, net (Note 11)		40.0	176.0
Long-term debt issued, net of discount (Note 9)	30.0	219.0	802.0
Long-term debt repaid (Note 9)	(136.0)	(516.0)	(310.0)
Debt issuance costs		(1.0)	(2.0)
Financing activities	(330.0)	(505.0)	354.0
Increase/(decrease) in cash and cash equivalents	50.0		(31.0)
Cash and cash equivalents, beginning of year	33.0	33.0	64.0
Cash and cash equivalents, end of year	83.0	33.0	33.0
Interest payments paid	87.0	94.0	79.0
State income taxes paid	2.0	1.0	2.0
Supplemental information about non-cash investing and financing activities
Accrued capital expenditures	12.0	7.0	9.0
Class B Units
Financing Activities
Distributions paid to Class B units (Notes 11 and 15)	(13.0)	(15.0)	(22.0)
Portland Natural Gas Transmission System And Iroquois Acquisition
Investing Activities
Investment of interests			(646.0)
Great Lakes
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	(51.0)	(59.0)	(31.0)
Investing Activities
Investment of interests	(10.0)	(9.0)	(9.0)
Iroquois
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	(40.0)	(46.0)	(26.0)
Investing Activities
Investment of interests	(4.0)
Distribution received from return of investment (Note 5)	8.0	10.0	5.0
Northern Border
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	(69.0)	$ (68.0)	(67.0)
Investing Activities
Investment of interests			$ (83.0)
Distribution received from return of investment (Note 5)	$ 50.0

CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CHANGE IN OPERATING WORKING CAPITAL
Change in accounts receivable and other	$ 9	$ (6)	$ 4
Change in inventory	(2)
Change in other current assets		(1)	2
Change in accounts payable and accrued liabilities	(11)	3	(7)
Change in accounts payable to affiliates	2	1	(3)
Change in accrued interest	(1)		2
Change in operating working capital	$ (3)	$ (3)	$ (2)

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
Gain (losses) related to cash flow hedges in AOCI expected to be reclassified to Net income in the next 12 months	$ 2

CASH DISTRIBUTIONS - Quarterly Distributions (Details)	12 Months Ended
CASH DISTRIBUTIONS - Quarterly Distributions (Details)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash distributions
Period after the end of each quarter within which quarterly cash distributions to partners are to be paid	45 days
General Partner \| TC Pipelines, LP \| Common Units
Cash distributions
General partner interest (as a percent)	2.00%	2.00%	2.00%

PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2019

PROPERTY, PLANT AND EQUIPMENT

Schedule of property, plant and equipment


	2019			2018
		Accumulated	Net Book		Accumulated	Net Book
December 31 (millions of dollars)	Cost	Depreciation	Value	Cost	Depreciation	Value
Pipeline	1,907	(929)	978	1,901	(876)	1,025
Compression	584	(202)	382	550	(182)	368
Metering and other	180	(56)	124	176	(52)	124
Construction in progress	44	-	44	12	—	12
	2,715	1,187	1,528	2,639	(1,110)	1,529

TRANSACTIONS WITH MAJOR CUSTOMERS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Transactions with major customers
Trade accounts receivable	$ 44		$ 37
Revenues \| Credit Concentration Risk \| Anadarko Energy Services Company
Transactions with major customers
Revenues		$ 48
Concentration percentage		10.00%
Revenues \| Credit Concentration Risk \| Anadarko/Tenaska customer group
Transactions with major customers
Revenues	144
Trade accounts receivable \| Credit Concentration Risk \| Anadarko Energy Services Company
Transactions with major customers
Trade accounts receivable		$ 4
Concentration percentage		10.00%
Trade accounts receivable \| Credit Concentration Risk \| Tenaska
Transactions with major customers
Trade accounts receivable	$ 4
Concentration percentage	10.00%

VARIABLE INTEREST ENTITIES (VIEs) (Tables)

12 Months Ended

Dec. 31, 2019

VARIABLE INTEREST ENTITIES (VIEs)

Schedule of assets and liabilities held through VIEs whose assets cannot be used for purposes other settlement of their obligations


	December 31,		December 31,
(millions of dollars)	2019		2018(a)

ASSETS (LIABILITIES)
Cash and cash equivalents	—		16
Accounts receivable and other	—		39
Inventories	—		8
Other current assets	—		6
Equity investments	491	^(b)	1,196
Property, plant and equipment	—		1,240
Other assets	—		1
Accounts payable and accrued liabilities	—		(33)
Accounts payable to affiliates, net	—		(40)
Distributions payable	—		—
Accrued interest	—		(2)
Current portion of long-term debt	—		(36)
Long-term debt	—		(341)
Other liabilities	—		(27)
Deferred state income tax	—		(9)

(a)	Bison, an asset held through our consolidated VIEs, is excluded at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations.

(b)	Equity investment on Great Lakes (Refer to Note 5)

- Definition

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

+ References + Details

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Changes in accumulated other comprehensive income (loss) (AOCI) by component
Partners' Equity at beginning of year	$ 591
Change in fair value of interest rate derivative instruments recognized in other comprehensive income	(13)	$ (2)	$ 5
PNGTS' amortization of realized loss on derivative instrument (Note 20)		1	1
Net other comprehensive income	(13)	3	7
Partners' Equity at end of year	656	591
Accumulated Other Comprehensive Income (Loss)
Changes in accumulated other comprehensive income (loss) (AOCI) by component
Partners' Equity at beginning of year	8	5	(2)
Change in fair value of interest rate derivative instruments recognized in other comprehensive income	(13)	(2)	5
Amounts reclassified from AOCI	(1)	5
PNGTS' amortization of realized loss on derivative instrument (Note 20)	1	1	1
Other comprehensive income (loss) - effects of Iroquois' retirement benefit plans		(1)	1
Net other comprehensive income	(13)	3	7
Partners' Equity at end of year	(5)	8	5
Cash flow hedges
Changes in accumulated other comprehensive income (loss) (AOCI) by component
Partners' Equity at beginning of year	8	4	(2)
Change in fair value of interest rate derivative instruments recognized in other comprehensive income	(13)	(2)	5
Amounts reclassified from AOCI	(1)	5
PNGTS' amortization of realized loss on derivative instrument (Note 20)		1	1
Net other comprehensive income	(14)	4	6
Partners' Equity at end of year	(6)	8	4
Equity Investments
Changes in accumulated other comprehensive income (loss) (AOCI) by component
Partners' Equity at beginning of year		1
PNGTS' amortization of realized loss on derivative instrument (Note 20)	1
Other comprehensive income (loss) - effects of Iroquois' retirement benefit plans		(1)	1
Net other comprehensive income	1	$ (1)	1
Partners' Equity at end of year	$ 1		$ 1

ACCOUNTS RECEIVABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2019

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other


December 31 (millions of dollars)	2019	2018
Trade accounts receivable, net of allowance of nil	37	44
Imbalance receivable from affiliates	—	2
Other	6	2
	43	48

CASH DISTRIBUTIONS - General Partner Distribution Incentives (Details)	12 Months Ended
	Dec. 31, 2019 $ / shares
Minimum Quarterly Distribution
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.45
Minimum Quarterly Distribution \| Limited Partners \| Common Units
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	98.00%
Minimum Quarterly Distribution \| General Partner
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	2.00%
First Target Distribution \| Minimum
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.45
First Target Distribution \| Maximum
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.81
First Target Distribution \| Limited Partners \| Common Units
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	98.00%
First Target Distribution \| General Partner
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	2.00%
Second Target Distribution \| Minimum
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.81
Second Target Distribution \| Maximum
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.88
Second Target Distribution \| Limited Partners \| Common Units
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	85.00%
Second Target Distribution \| General Partner
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	15.00%
Thereafter
Partners' Equity
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit)	$ 0.88
Thereafter \| Limited Partners \| Common Units
Partners' Equity
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent)	75.00%
Thereafter \| General Partner
Partners' Equity
Marginal Percentage Interest in Distribution, General Partner (includes IDRs)	25.00%

QUARTERLY FINANCIAL DATA (unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions													3 Months Ended								12 Months Ended
	Nov. 14, 2019	Aug. 14, 2019	May 13, 2019	Feb. 11, 2019	Nov. 14, 2018	Aug. 15, 2018	May 15, 2018	Feb. 13, 2018	Nov. 14, 2017	Aug. 11, 2017	May 15, 2017	Feb. 14, 2017	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Nov. 30, 2018	Oct. 16, 2018
Quarterly financial data (unaudited)
Transmission revenues													$ 104	$ 93	$ 93	$ 113	$ 220	$ 103	$ 111	$ 115	$ 403	$ 549	$ 422
Equity earnings													45	31	30	54	44	34	36	59	160	173	124
Net income (loss)													82	59	57	100	(406)	65	75	102
Net income (loss) attributable to controlling interests													$ 76	$ 56	$ 55	$ 93	$ (413)	$ 62	$ 73	$ 96
Net income (loss) per common unit (in dollars per unit)													$ 0.95	$ 0.76	$ 0.75	$ 1.28	$ (5.80)	$ 0.79	$ 1.00	$ 1.32
Cash distribution paid	$ 47	$ 47	$ 47	$ 60	$ 47	$ 47	$ 47	$ 91	$ 74	$ 74	$ 68	$ 90									$ 189	218	$ 284
Provision for revenue sharing																						$ 10
Common Units
Quarterly financial data (unaudited)
Net income (loss) per common unit (in dollars per unit)																					$ 3.74	$ (2.68)	$ 3.16
Cash distribution paid													$ 47	$ 47	$ 47	$ 47	$ 47	$ 47	$ 47	$ 76
Class B Units
Quarterly financial data (unaudited)
Cash distribution paid																$ 13				$ 15
General Partner \| TC Pipelines, LP \| Common Units
Quarterly financial data (unaudited)
General partner interest (as a percent)																					2.00%	2.00%	2.00%
GTN \| FERC
Quarterly financial data (unaudited)
Provision for revenue sharing																	$ 1	$ 9
Amount agreed to issue as refund to customers from January 1 to October 31, 2018																								$ 10	$ 10
Bison
Quarterly financial data (unaudited)
Contract Termination Proceeds																						$ 97

FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value \| Level 2
Financial Instruments
Fair value of debt	$ 2,111	$ 2,101

NET INCOME PER COMMON UNIT - General Partner Interest (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
General Partner \| Common Units \| TC Pipelines, LP
PARTNERS' EQUITY
General partner interest (as a percent)	2.00%	2.00%	2.00%

OTHER LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2019

OTHER LIABILITIES

Schedule of other liabilities


December 31 (millions of dollars)	2019	2018

Regulatory liabilities	29	27
Other liabilities	7	2
	36	29

NET INCOME PER COMMON UNIT- Determination of Net Income (Loss) per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended								12 Months Ended
	Apr. 01, 2015	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net income (loss) per common unit
Net income (loss) attributable to controlling interests										$ 280	$ (182)	$ 252
Net income attributable to PNGTS' former parent												(2)
Net income (loss) attributable to General and Limited Partners										280	(182)	250
Incentive distributions attributable to the General Partner												(12)
Net income attributable to the General Partner and common units										272	(195)	223
Net income (loss) attributable to General Partner's two percent interest										(5)	4	(4)
Net income (loss) per common unit - basic and diluted (in dollars per unit)		$ 0.95	$ 0.76	$ 0.75	$ 1.28	$ (5.80)	$ 0.79	$ 1.00	$ 1.32
Distributions
Net income attributable to controlling interests		$ 76	$ 56	$ 55	$ 93	$ (413)	$ 62	$ 73	$ 96
Class B Units
Net income (loss) per common unit
Net income (loss) attributable to common units or Class B units										8	13	15
Common Units
Net income (loss) per common unit
Net income (loss) attributable to common units or Class B units										$ 267	$ (191)	$ 219
Weighted average common units outstanding (millions) - basic and diluted										71.3	71.3	69.2
Net income (loss) per common unit - basic and diluted (in dollars per unit)										$ 3.74	$ (2.68)	$ 3.16
General Partner \| TC Pipelines, LP \| Common Units
Net income (loss) per common unit
General partner interest (as a percent)										2.00%	2.00%	2.00%
GTN \| Class B Units \| TC Energy
Distributions
Threshold of GTN's distributions for payment to Class B units										$ 20
Percentage applied to GTN's distributable cash flow										30.00%
GTN \| Class B Units \| TC Energy \| Distributions
Net income (loss) per common unit
Net income (loss) attributable to controlling interests										$ (8)	$ (13)	$ (15)
Distributions
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		$ 20	$ 20
Percentage applied to GTN's distributable cash flow										30.00%
Class B reduction										$ 4	$ 7

GOODWILL AND REGULATORY (Tables)

12 Months Ended

Dec. 31, 2019

GOODWILL AND REGULATORY

Summary of adjustments as a result of the FERC Actions


	Form 501-G Filing Option	Impact on Maximum Rates	Moratorium, Mandatory Filing Requirements and Other Considerations
Great Lakes	Option 1; reflected an elimination of income tax allowance and ADIT; Limited Section 4 accepted by FERC; 501-G Docket remains open	2.0% rate reduction effective February 1, 2019	No moratorium in effect; comeback provision with new rates to be effective by October 1, 2022
GTN	Settlement approved by FERC on November 30, 2018 eliminated the requirement to file Form 501-G	A refund of $10 million to its firm customers in 2018; 10.0% rate reduction effective January 1, 2019; additional rate reduction of 6.6% effective January 1, 2020 through December 31, 2021; these reductions will replace the 8.3% rate reduction in 2020 agreed to as part of the last settlement in 2015	Moratorium on rate changes until December 31, 2021; comeback provision with new rates to be effective by January 1, 2022; Settlement agreement reflected an elimination of income tax allowance and ADIT
Northern Border	Option 1; reflected an elimination of income tax allowance and ADIT; subsequent settlement approved by FERC on May 24, 2019; 501-G docket closed	2.0% rate reduction effective February 1, 2019 to December 31, 2019 extended until July 1, 2024 unless superseded by a subsequent rate case or settlement	No moratorium in effect; comeback provision with new rates to be effective by July 1, 2024
Bison	Option 3; reflected an elimination of income tax allowance and ADIT; accepted by FERC; 501-G docket closed	No rate changes proposed	No moratorium or comeback provisions
Iroquois	Option 3; reflected an elimination of income tax allowance and ADIT; subsequent settlement approved by FERC on May 2, 2019; 501-G docket closed	3.25% rate reduction effective March 1, 2019; additional 3.25% rate reduction effective April 1, 2020	Moratorium on rate changes until September 1, 2020; comeback provision with new rates to be effective by March 1, 2023
PNGTS	Option 3; reflected an elimination of income tax allowance and ADIT; accepted by FERC; 501-G docket closed	No rate changes	No moratorium or comeback provisions
North Baja	Option 1; reflected an elimination of income tax allowance and ADIT; accepted by FERC; 501-G docket closed	10.8% rate reduction effective December 1, 2018	No moratorium or comeback provisions; approximately 90 percent of North Baja’s contracts are negotiated; 10.8% reduction is on maximum rate contracts only
Tuscarora	Option 1; reflected an elimination of income tax allowance and ADIT; subsequent settlement approved by FERC on May 2, 2019; 501-G docket closed	1.7% rate reduction effective February 1, 2019; additional rate reduction of 10.8% effective August 1, 2019	Moratorium on rate changes until January 31, 2023; comeback provision with new rates to be effective by February 1, 2023; Settlement agreement reflected an elimination of income tax allowance and ADIT

CHANGE IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2019

CHANGE IN OPERATING WORKING CAPITAL

Schedule of change in operating working capital


Year Ended December 31 (millions of dollars)	2019	2018	2017
Change in accounts receivable and other	9	(6)	4
Change in inventory	(2)	—	—
Change in other current assets	—	(1)	2
Change in accounts payable and accrued liabilities ^(a)	(11)	3	(7)
Change in accounts payable to affiliates	2	1	(3)
Change in accrued interest	(1)	—	2
Change in operating working capital	(3)	(3)	(2)

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

EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2019

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees


	Ownership
	Interest at		Equity Earnings ^(b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2019		2019	2018	2017	2019	2018
Northern Border^(a)	50.00	%	69	68	67	422	497
Great Lakes	46.45	%	51	59	31	491	489
Iroquois	49.34	%	40	46	26	185	210
			160	173	124	1,098	1,196

(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 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.

Northern Border

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees


December 31 (millions of dollars)	2019	2018
Assets
Cash and cash equivalents	21	10
Other current assets	37	36
Property, plant and equipment, net	989	1,037
Other assets	12	13
	1,059	1,096
Liabilities and Partners’ Equity
Current liabilities	42	34
Deferred credits and other	39	35
Long-term debt, net ^(a)	364	264
Partners’ equity
Partners’ capital	615	764
Accumulated other comprehensive loss	(1)	(1)
	1,059	1,096


Year ended December 31 (millions of dollars)	2019	2018	2017

Transmission revenues	300	289	291
Operating expenses	(82)	(78)	(78)
Depreciation	(62)	(60)	(59)
Financial charges and other	(18)	(15)	(18)
Net income	138	136	136

(a)	No current maturities as of December 31, 2019 or 2018.

Great Lakes

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees


December 31 (millions of dollars)	2019	2018
Assets
Current assets	72	75
Property, plant and equipment, net	685	689
	757	764
Liabilities and Partners’ Equity
Current liabilities	33	26
Long-term debt, net ^(a)	219	240
Other long-term liabilities	6	4
Partners’ equity	499	494
	757	764


Year ended December 31 (millions of dollars)	2019	2018	2017

Transmission revenues	238	246	181
Operating expenses	(79)	(68)	(66)
Depreciation	(32)	(32)	(29)
Financial charges and other	(16)	(18)	(20)
Net income	111	128	66

(a)	Includes current maturities of $21 million as of December 31, 2019 and December 31, 2018.

RELATED PARTY TRANSACTIONS (Details) $ in Millions			1 Months Ended	12 Months Ended
RELATED PARTY TRANSACTIONS (Details) $ in Millions	Oct. 31, 2019 USD ($)	Nov. 01, 2017	Sep. 21, 2017 Bcf	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Nov. 01, 2020 USD ($)
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				$ 8.0	$ 6.0
Amount included in receivables from related party					2.0
General Partner \| Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				4.0	4.0	$ 4.0
Great Lakes \| TransCanada's subsidiaries
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party				19.0	18.0
Great Lakes \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				5.0	3.0
Termination options beginning		3 years
Great Lakes \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				47.0	44.0	36.0
Impact on the Partnership's net income attributable to controlling interests				20.0	19.0	15.0
Amount included in receivables from related party				34.0	36.0
Great Lakes \| TC Energy \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Contract term		10 years
Total revenue earned				$ 76.0	$ 76.0	$ 13.0
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%	57.00%
Great Lakes \| TC Energy \| Affiliated rental revenue
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues						1.00%
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					15 years
Total contract value					$ 1,300.0
Transportation capacity per day \| Bcf			0.711
Northern Border \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				$ 4.0	3.0
Northern Border \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				39.0	36.0	$ 43.0
Impact on the Partnership's net income attributable to controlling interests				18.0	16.0	16.0
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	0.0
Revenues from related party				1.0	1.0	1.0
PNGTS \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				1.0	1.0
PNGTS \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				7.0	9.0	9.0
Impact on the Partnership's net income attributable to controlling interests				4.0	5.0	5.0
PNGTS \| TC Energy \| Portland XPress expansion project (PXP), Phase III \| PXP Phase III
Capital and operating costs charged to the pipeline systems and amount payable
Costs reimbursable at reporting date				$ 0.6
PNGTS \| TC Energy \| Portland XPress expansion project (PXP), Phase III \| PXP Phase III \| Forecast
Capital and operating costs charged to the pipeline systems and amount payable
Costs reimbursable at reporting date							$ 8.0
PNGTS \| Affiliates \| Construction of facilities \| Minimum
Capital and operating costs charged to the pipeline systems and amount payable
Reimbursement of costs	$ 140.0
PNGTS \| Affiliates \| Portland XPress expansion project (PXP), Phase III
Capital and operating costs charged to the pipeline systems and amount payable
Expansion Project, Phase In Period				3 years
GTN \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				$ 5.0	4.0
GTN \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				45.0	34.0	34.0
Impact on the Partnership's net income attributable to controlling interests				$ 33.0	$ 28.0	$ 29.0
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					$ 1.0
Bison \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				$ 2.0	6.0	$ 6.0
Impact on the Partnership's net income attributable to controlling interests				2.0	6.0	6.0
North Baja \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				1.0
North Baja \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				5.0	4.0	4.0
Impact on the Partnership's net income attributable to controlling interests				4.0	4.0	4.0
Tuscarora \| TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable					1.0
Tuscarora \| TC Energy \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				4.0	4.0	4.0
Impact on the Partnership's net income attributable to controlling interests				$ 4.0	$ 4.0	$ 4.0

DEBT AND CREDIT FACILITIES - Principal Repayments Required (Details) $ in Millions	Dec. 31, 2019 USD ($)
Principal repayments required on debt
2020	$ 123
2021	400
2022	450
2023	39
Thereafter	1,000
Total debt	$ 2,012

REVENUES - Disaggregation of Revenues (Details) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2018 USD ($) customer	Dec. 31, 2018 USD ($)	Dec. 31, 2019 USD ($)
Disaggregation of Revenues
Provision for revenue sharing		$ 10.0
Contract balances	$ 44.0	44.0	$ 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

PARTNERS' EQUITY - Ownership (Details) - shares	12 Months Ended
PARTNERS' EQUITY - Ownership (Details) - shares	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Common Units
PARTNERS' EQUITY
Common units outstanding, end of year (millions)	71,300,000	71,300,000	70,600,000
Common Units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (millions)	71,306,396
TC Pipelines, LP \| General Partner \| Common Units
PARTNERS' EQUITY
Ownership interest in the Partnership (as a percent)	2.00%	2.00%	2.00%
TC Energy \| Class B Units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (millions)	1,900,000
Ownership interest (as a percent)	100.00%
Non-affiliates \| Common Units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (millions)	54,221,565
TC Pipelines, LP \| General Partner
PARTNERS' EQUITY
IDRs ownership (as a percent)	100.00%
TC Pipelines, LP \| Common Units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (millions)	5,797,106
TransCanada Corporation and subsidiaries \| Common Units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (millions)	17,084,831
TC Energy \| Common Units \| Limited Partners
PARTNERS' EQUITY
Common units outstanding, end of year (millions)	11,287,725
TC Energy \| TC Energy \| Class B Units
PARTNERS' EQUITY
Ownership interest (as a percent)	24.00%

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
Document and Entity Information - USD ($) $ in Billions	Dec. 31, 2019	Feb. 19, 2020	Jun. 30, 2019
Document and Entity Information
Document Type	10-K
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Dec. 31, 2019
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
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
Entity Shell Company	false
Title of 12(b) Security	Common units representing limited partner interests
Trading Symbol	TCP
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding		71,306,396
Entity Central Index Key	0001075607
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 2.7

ACCOUNTING PRONOUNCEMENTS - Leases (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019
ACCOUNTING PRONOUNCEMENTS
Operating ROU assets	$ 0.4	$ 0.6
Operating lease liabilities	$ 0.4	$ 0.6
Weighted average remaining term (in years)	1 year 11 months 15 days
Discount rate (in percent)	3.57%

CASH DISTRIBUTIONS (Tables)

12 Months Ended

Dec. 31, 2019

CASH DISTRIBUTIONS

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


		Marginal Percentage
		Interest in Distribution
	Total Quarterly Distribution	Common		General
	Per Unit Target Amount	Unitholders		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


				Limited Partners				General Partner
		Per Unit		Common		Class B						Total Cash
Declaration Date	Payment Date	Distribution		Units		Units^(b)		2%		IDRs^(a)		Distribution
1/23/2017	2/14/2017	$	0.94	$	64	$	22	$	2	$	2	$	90
4/25/2017	5/15/2017	$	0.94	$	65	$	—	$	1	$	2	$	68
7/20/2017	8/11/2017	$	1.00	$	69	$	—	$	2	$	3	$	74
10/24/2017	11/14/2017	$	1.00	$	70	$	—	$	1	$	3	$	74
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 ^(c)	2/14/2020 ^(c)	$	0.65	$	46	$	8	$	1	$	—	$	55

(a)	The distributions paid during the year ended December 31, 2019 included no incentive distributions to the General Partner (2018 - $3 million, 2017 - $10 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 11)

(c)	On February 14, 2020, 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 31, 2020 (refer to Note 24).

CONSOLIDATED STATEMENTS OF OPERATIONS shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) $ / shares shares	Dec. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2017 USD ($) $ / shares shares
Transmission revenues	$ 403	$ 549	$ 422
Equity earnings (Note 5)	160	173	124
Impairment of long-lived assets (Note 7)		(537)
Impairment of goodwill (Note 4)		(59)
Operation and maintenance expenses	(71)	(67)	(67)
Property taxes	(26)	(28)	(28)
General and administrative	(8)	(6)	(8)
Depreciation	78	97	97
Financial charges and other (Note 13)	(83)	(92)	(82)
Net income (loss) before taxes	297	(164)	264
Income taxes (Note 2)	1	(1)	(1)
Net Income (loss)	298	(165)	263
Net income attributable to non-controlling interests	18	17	11
Net income (loss) attributable to controlling interests	280	(182)	252
Net income (loss) attributable to controlling interest allocation (Note 14)
General Partner	5	(4)	16
TC Energy and its subsidiaries	8	13	17
Net income (loss) attributable to controlling interests	280	(182)	252
Common Units
Net income (loss) attributable to controlling interest allocation (Note 14)
Net income (loss) attributable to common units or Class B units	$ 267	$ (191)	$ 219
Net income (loss) per common unit (Note 14) - basic and diluted (in dollars per unit) \| $ / shares	$ 3.74	$ (2.68)	$ 3.16
Weighted average common units outstanding (millions) - basic and diluted \| shares	71.3	71.3	69.2
Common units outstanding, end of year (millions) \| shares	71.3	71.3	70.6

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - USD ($) shares in Millions, $ in Millions	ATM Equity Issuance Program Limited Partners Common Units	ATM Equity Issuance Program General Partner	ATM Equity Issuance Program	Limited Partners PNGTS Common Units	Limited Partners Common Units	Limited Partners Class B Units	General Partner PNGTS	General Partner	Accumulated Other Comprehensive Income (Loss)	PNGTS Equity of former parent of PNGTS	PNGTS	Non-Controlling Interest	Equity of former parent of PNGTS	Total
Partners' Equity at beginning of period at Dec. 31, 2016					$ 1,002	$ 117		$ 27	$ (2)			$ 97	$ 31	$ 1,272
Partners' Equity at beginning of period (in units) at Dec. 31, 2016					67.4	1.9
Increase (Decrease) in Partners' Equity
Net income (loss)					$ 219	$ 15		16				11	2	263
Other comprehensive income (loss)									7					7
ATM equity issuances, net (Note 11)	$ 173	$ 3	$ 176
ATM equity issuances, net (Note 11) (in units)	3.2
Reclassification of common unit issuance subject to rescission, net (Note 11)					81			2						83
Acquisition of interests (note 8)				$ (383)			$ (8)			$ (32)	$ (423)
Distributions (Note 10)					(268)	(22)		(16)				(3)	$ (1)	(310)
Partners' Equity at end of period at Dec. 31, 2017					$ 824	$ 110		24	5			105		1,068
Partners' Equity at end of period (in units) at Dec. 31, 2017					70.6	1.9
Increase (Decrease) in Partners' Equity
Net income (loss)					$ (191)	$ 13		(4)				17		(165)
Other comprehensive income (loss)									3					3
ATM equity issuances, net (Note 11)	$ 39	$ 1	$ 40
ATM equity issuances, net (Note 11) (in units)	0.7
Distributions (Note 10)					(210)	(15)		(8)				(14)		(247)
Partners' Equity at end of period at Dec. 31, 2018					$ 462	$ 108		13	8			108		699
Partners' Equity at end of period (in units) at Dec. 31, 2018					71.3	1.9
Increase (Decrease) in Partners' Equity
Net income (loss)					$ 267	$ 8		5				18		298
Other comprehensive income (loss)									(13)					(13)
Distributions (Note 10)					(185)	(13)		(4)				(22)		(224)
Partners' Equity at end of period at Dec. 31, 2019					$ 544	$ 103		$ 14	$ (5)			$ 104		$ 760
Partners' Equity at end of period (in units) at Dec. 31, 2019					71.3	1.9

DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details) - USD ($) $ in Millions					12 Months Ended
	Jun. 26, 2019	Apr. 05, 2018	Sep. 29, 2017	May 25, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 19, 2018
Credit facilities, short-term loan facility and long-term debt
Total credit facilities, short-term loan facility and long-term debt					$ 2,012	$ 2,118
Less: unamortized debt issuance costs and debt discount					9	10
Less: current portion					123	36
Long-term debt					1,880	2,072
2013 Term Loan Facility
Credit facilities, short-term loan facility and long-term debt
Repayments of secured debt	$ 50
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
Debt and credit facilities						$ 40
Weighted average interest rate (as a percent)						3.14%
Maximum borrowing capacity					500
Amount outstanding under credit facility					0	$ 40
Remaining borrowing capacity					$ 500
Effective interest rate (as a percent)					3.77%
Increase in credit facility					$ 500
TC PipeLines, LP 2013 Term Loan Facility due 2022
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities					$ 450	$ 500
Weighted average interest rate (as a percent)					3.52%	3.23%
Effective interest rate (as a percent)					2.94%	3.60%
Leverage ratio, actual (as a percent)					3.41%
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, covenant (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
Additional period immediately following the fiscal quarter in which a specified material acquisition occurs					6 months
Leverage ratio, covenant (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 4.65% Senior Notes due 2021
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities					$ 350	$ 350
Stated interest rate (as a percent)					4.65%	4.65%
Weighted average interest rate (as a percent)					4.65%	4.65%
TC PipeLines, LP 4.375% Senior Notes due 2025
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities					$ 350	$ 350
Stated interest rate (as a percent)					4.375%	4.375%
Weighted average interest rate (as a percent)					4.375%	4.375%
TC PipeLines, LP 3.90% Senior Notes due 2027
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities					$ 500	$ 500
Stated interest rate (as a percent)				3.90%	3.90%	3.90%
Weighted average interest rate (as a percent)					3.90%	3.90%
Amount of debt				$ 500
Net proceeds				$ 497
GTN 5.29% Senior Notes due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities					$ 100	$ 100
Stated interest rate (as a percent)					5.29%	5.29%
Weighted average interest rate (as a percent)					5.29%	5.29%
GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities					$ 150	$ 150
Stated interest rate (as a percent)					5.69%	5.69%
Weighted average interest rate (as a percent)					5.69%	5.69%
GTN Unsecured Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities						$ 35
Weighted average interest rate (as a percent)						2.93%
Effective interest rate (as a percent)						3.30%
PNGTS Revolving Credit Facility due 2023
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities					$ 39	$ 19
Weighted average interest rate (as a percent)					3.47%	3.55%
Maximum borrowing capacity		$ 125
Amount outstanding under credit facility					$ 39
Leverage ratio, covenant (as a percent)		5.00%
Leverage ratio, actual (as a percent)					0.70%
Interest rate (as a percent)					2.99%	3.60%
Tuscarora Term Loan due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities					$ 23	$ 24
Weighted average interest rate (as a percent)					3.39%	3.10%
Effective interest rate (as a percent)					2.82%	3.47%
Debt service coverage, covenant (as a percent)					3.00%
Debt service coverage, actual (as a percent)					8.72%
North Baja Term Loan Due 2021
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities					$ 50	$ 50
Weighted average interest rate (as a percent)					3.34%	3.54%
Effective interest rate (as a percent)					2.77%	3.54%
Percentage of debt to total capitalization, covenant					70.00%
Percentage of debt to total capitalization, actual					39.80%
Amount of debt							$ 50
GTN Unsecured Senior Notes
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant					70.00%
Percentage of debt to total capitalization, actual					39.10%

ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)		12 Months Ended
	Oct. 31, 2019	Dec. 31, 2019 mi	Dec. 31, 2018 LimitedPartnership	Jan. 06, 2020	Aug. 01, 2017	Jun. 01, 2017
Organization
Number of intermediate limited partnerships through which pipeline assets are owned \| LimitedPartnership			3
PNGTS
Organization
Ownership interest (as a percent)						11.81%
Northern Border
Organization
Ownership interest (as a percent)		50.00%
Great Lakes
Organization
Ownership interest (as a percent)		46.45%
Iroquois
Organization
Ownership interest (as a percent)		49.34%		49.34%	49.34%	49.34%
GTN
Organization
Length of pipeline owned (in miles)		1,377
Ownership interest (as a percent)	100.00%	100.00%
Bison
Organization
Length of pipeline owned (in miles)		303
Ownership interest (as a percent)		100.00%
North Baja
Organization
Length of pipeline owned (in miles)		86
Ownership interest (as a percent)		100.00%
Tuscarora
Organization
Length of pipeline owned (in miles)		305
Ownership interest (as a percent)		100.00%
Northern Border
Organization
Length of pipeline owned (in miles)		1,412
Ownership interest (as a percent)		50.00%
Northern Border \| Northern Border
Organization
Ownership interest (as a percent)		50.00%
Northern Border \| ONEOK Partners, L.P.
Organization
Remaining ownership interest (as a percent)		50.00%
PNGTS
Organization
Length of pipeline owned (in miles)		295
Ownership interest (as a percent)		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 (as a percent)		32.00%
Great Lakes
Organization
Length of pipeline owned (in miles)		2,115
Ownership interest (as a percent)		46.45%
Great Lakes \| TC Energy
Organization
Remaining noncontrolling ownership interest (as a percent)		53.55%
Iroquois Gas
Organization
Length of pipeline owned (in miles)		416
Ownership interest (as a percent)		49.34%
Iroquois Gas \| TC Energy
Organization
Ownership interest (as a percent)		0.66%
Iroquois Gas \| TC Energy
Organization
Remaining ownership interest (as a percent)		50.66%
Northern New England Investment \| PNGTS
Organization
Remaining noncontrolling ownership interest (as a percent)		38.29%

EQUITY INVESTMENTS (Details) - USD ($) $ in Millions					1 Months Ended			3 Months Ended								7 Months Ended	12 Months Ended
EQUITY INVESTMENTS (Details) - USD ($) $ in Millions	Jan. 06, 2020	Nov. 01, 2019	Sep. 01, 2017	Jun. 01, 2017	Aug. 31, 2019	Jun. 30, 2019	Apr. 30, 2006	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 01, 2017
EQUITY INVESTMENTS
Equity Earnings								$ 45.0	$ 31.0	$ 30.0	$ 54.0	$ 44.0	$ 34.0	$ 36.0	$ 59.0		$ 160.0	$ 173.0	$ 124.0
Equity Investments								1,098.0				1,196.0					1,098.0	1,196.0
Distributions from Equity Investments
Distributions received from equity investments																	258.0	198.0	145.0
Distributions from equity investments																	200.0	188.0	140.0
Return on investment distribution classified as investing activities																	58.0	10.0	5.0
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt (Note 9)								123.0				$ 36.0					$ 123.0	36.0
Revenues (expenses)
Transmission revenues																		194.0
Operating expenses																		(57.0)
Depreciation																		(29.0)
Financial charges and other																		(14.0)
Net income																		$ 94.0
Northern Border
EQUITY INVESTMENTS
Partnership interest held (as a percent)																	50.00%
Great Lakes
EQUITY INVESTMENTS
Partnership interest held (as a percent)																	46.45%
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill								$ 260.0									$ 260.0
Great Lakes \| Minimum
EQUITY INVESTMENTS
Excess of estimated fair value over carrying value (as a percent)												10.00%						10.00%
ONEOK Partners, L.P. \| Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)								50.00%									50.00%
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)			50.00%
Equity contribution			$ 83.0
Capital contribution to reduce the outstanding balance of revolver debt			$ 166.0
Cash distribution						$ 100.0
Distribution financed by borrowings (as a percent)						100.00%				100.00%
Northern Border \| Revolving credit facility
EQUITY INVESTMENTS
Maximum borrowing capacity						$ 200.0				$ 200.0
Great Lakes
EQUITY INVESTMENTS
Total cash call issued to fund debt repayment												$ 10.0			$ 11.0
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt (Note 9)								$ 21.0				21.0					$ 21.0	$ 21.0
Iroquois
EQUITY INVESTMENTS
Ownership interest (as a percent)								49.34%									49.34%
Total cash call issued to fund debt repayment																		7.0
Distributions from Equity Investments
Return on investment distribution classified as investing activities																	$ 8.0	10.0
Limited partners, Distribution declared		$ 28.0
ASSETS
Cash and cash equivalents								$ 43.0									43.0
Other current assets								36.0									36.0
Property, plant and equipment, net								570.0									570.0
Other assets								16.0									16.0
Assets, total								665.0									665.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities								34.0									34.0
Net long-term debt, including current maturities								317.0									317.0
Current portion of long-term debt (Note 9)								3.0				146.0					3.0	146.0
Other non-current liabilities								20.0									20.0
Partners' capital								294.0									294.0
Liabilities and Partners' Equity, total								$ 665.0									665.0
Revenues (expenses)
Transmission revenues																$ 110.0	180.0
Operating expenses																(32.0)	(58.0)
Depreciation																(17.0)	(29.0)
Financial charges and other																(9.0)	(11.0)
Net income																52.0	$ 82.0
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)								50.00%									50.00%
Equity Earnings																	$ 69.0	68.0	67.0
Equity Investments								$ 422.0				497.0					422.0	497.0
Amortization period of transaction fee							12 years
Transaction fee							$ 10.0
Additional ownership interest acquired (as a percent)							20.00%
Equity contribution																			83.0
Undistributed earnings																		0.0	0.0	$ 0.0
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill								115.0								$ 115.0	115.0		115.0
Distributions from Equity Investments
Distributions received from equity investments																	144.0	83.0	83.0
Return on investment distribution classified as investing activities																	50.0
ASSETS
Cash and cash equivalents								21.0				10.0					21.0	10.0
Other current assets								37.0				36.0					37.0	36.0
Property, plant and equipment, net								989.0				1,037.0					989.0	1,037.0
Other assets								12.0				13.0					12.0	13.0
Assets, total								1,059.0				1,096.0					1,059.0	1,096.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities								42.0				34.0					42.0	34.0
Deferred credits and other								39.0				35.0					39.0	35.0
Net long-term debt, including current maturities								364.0				264.0					364.0	264.0
Current portion of long-term debt (Note 9)								0.0									0.0
Partners' capital								615.0				764.0					615.0	764.0
Accumulated other comprehensive loss								(1.0)				(1.0)					(1.0)	(1.0)
Liabilities and Partners' Equity, total								$ 1,059.0				1,096.0					1,059.0	1,096.0
Revenues (expenses)
Transmission revenues																	300.0	289.0	291.0
Operating expenses																	(82.0)	(78.0)	(78.0)
Depreciation																	(62.0)	(60.0)	(59.0)
Financial charges and other																	(18.0)	(15.0)	(18.0)
Net income																	$ 138.0	136.0	$ 136.0
Northern Border \| Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)								50.00%									50.00%
Great Lakes
EQUITY INVESTMENTS
Ownership interest (as a percent)								46.45%									46.45%
Percentage less than of which fair value exceeded carrying value																10.00%			10.00%
Equity Earnings																	$ 51.0	59.0	$ 31.0
Equity Investments								$ 491.0				489.0					491.0	489.0
Equity contribution								4.6			$ 5.1						10.0	9.0	9.0
Undistributed earnings																	0.0	0.0	0.0
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill												260.0						260.0
Distributions from Equity Investments
Distributions received from equity investments																	(59.0)	58.0	35.0
ASSETS
Current assets								72.0				75.0					72.0	75.0
Property, plant and equipment, net								685.0				689.0					685.0	689.0
Assets, total								757.0				764.0					757.0	764.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities								33.0				26.0					33.0	26.0
Net long-term debt, including current maturities								219.0				240.0					219.0	240.0
Other non-current liabilities								6.0				4.0					6.0	4.0
Partners' capital								499.0				494.0					499.0	494.0
Liabilities and Partners' Equity, total								$ 757.0				764.0					757.0	764.0
Revenues (expenses)
Transmission revenues																	238.0	246.0	181.0
Operating expenses																	(79.0)	(68.0)	(66.0)
Depreciation																	(32.0)	(32.0)	(29.0)
Financial charges and other																	(16.0)	(18.0)	(20.0)
Net income																	111.0	128.0	66.0
Great Lakes \| Iroquois
Distributions from Equity Investments
Distributions received from equity investments																	$ 55.0
Iroquois
EQUITY INVESTMENTS
Ownership interest (as a percent)	49.34%			49.34%				49.34%									49.34%				49.34%
Equity Earnings																	$ 40.0	46.0	26.0
Equity Investments								$ 185.0				210.0					185.0	210.0
Equity contribution				$ 710.0	$ 4.0												4.0
Undistributed earnings																$ 0.0	0.0	0.0
Additional consideration on surplus cash				$ 28.0
Distributions from Equity Investments
Distributions received from equity investments																		56.0
Distributions from equity investments	$ 14.0
Return on investment distribution classified as investing activities																	$ 8.0	10.0	$ 5.0
ASSETS
Cash and cash equivalents												80.0						80.0
Other current assets												32.0						32.0
Property, plant and equipment, net												581.0						581.0
Other assets												8.0						8.0
Assets, total												701.0						701.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities												19.0						19.0
Net long-term debt, including current maturities												325.0						325.0
Other non-current liabilities												14.0						14.0
Partners' capital												343.0						343.0
Liabilities and Partners' Equity, total												$ 701.0						$ 701.0

DEBT AND CREDIT FACILITIES (Tables)

12 Months Ended

Dec. 31, 2019

DEBT AND CREDIT FACILITIES

Schedule of debt and credit facilities


			Weighted Average			Weighted Average
			Interest Rate for the			Interest Rate for the
			Year Ended			Year Ended
(millions of dollars)	2019		December 31, 2019		2018	December 31, 2018
TC PipeLines, LP
Senior Credit Facility due 2021	—		—		40	3.14	%
2013 Term Loan Facility due 2022	450		3.52	%	500	3.23	%
4.65% Unsecured Senior Notes due 2021	350		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)	100	5.29	%^(a)
5.69% Unsecured Senior Notes due 2035	150		5.69	%^(a)	150	5.69	%^(a)
Unsecured Term Loan Facility due 2019	—		—		35	2.93	%
PNGTS
Revolving Credit Facility due 2023	39		3.47	%	19	3.55	%
Tuscarora
Unsecured Term Loan due 2020	23		3.39	%	24	3.10	%
North Baja
Unsecured Term Loan due 2021	50		3.34	%	50	3.54	%
	2,012				2,118
Less:unamortized debt issuance costs and debt discount	9				10
Less: current portion	123	^(b)			36
	1,880				2,072

(a)	Fixed interest rate.

(b)	Includes GTN’s 5.29% Unsecured Senior Notes due June 1, 2020 and Tuscarora’s Unsecured Term Loan due August 21, 2020.

Schedule of principal repayments required on debt


(millions of dollars)
2020		123
2021		400
2022		450
2023		39
2024		—
Thereafter		1,000
		2,012

ORGANIZATION - Capitalization (Details) - shares	12 Months Ended
ORGANIZATION - Capitalization (Details) - shares	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Common Units
Partners' Equity
Number of units	71,300,000	71,300,000	70,600,000
Common Units \| General Partner \| TC Pipelines, LP
Partners' Equity
Ownership interest in the Partnership (as a percent)	2.00%	2.00%	2.00%
Class B Units \| TC Energy \| TC Energy
Partners' Equity
Limited partner interest (as a percent)	24.00%
General Partner \| TC Pipelines, LP
Partners' Equity
IDRs ownership (as a percent)	100.00%
Limited Partners \| Common Units
Partners' Equity
Number of units	71,306,396
Limited Partners \| Common Units \| TC Pipelines, LP
Partners' Equity
Number of units	5,797,106
Limited Partners \| Common Units \| TC Energy
Partners' Equity
Number of units	11,287,725
Limited Partners \| Class B Units \| TC Energy
Partners' Equity
Number of units	1,900,000
Limited partner interest (as a percent)	100.00%

ACQUISITION (Tables)

12 Months Ended

Dec. 31, 2019

Schedule of purchase price allocation


(millions of dollars)
Current assets		25
Property, plant and equipment, net		294
Current liabilities		(4)
Deferred state income taxes		(10)
Long-term debt, including current portion		(41)
		264
Non-controlling interest		(100)
Carrying value of pre-existing Investment in PNGTS		(132)
TC Energy’s carrying value of the acquired 11.81 percent interest at June 1, 2017		32
Excess purchase price over net assets acquired ^(a)		21
Total cash consideration ^(b)		53

(a)	The excess purchase price of $21 million was recorded as a reduction in Partners’ Equity.

(b)	Total purchase price of $55 million plus the final working capital adjustment of $3 million less the assumption of $5 million of proportional PNGTS debt by the Partnership.

Iroquois

Schedule of purchase price


(millions of dollars)
Net Purchase Price^(a)		593
Less: TC Energy’s carrying value of Iroquois at June 1, 2017		223
Excess purchase price^(b)		370

(a)	Total purchase price of $710 million plus final working capital adjustment of $19 million and the additional consideration on Iroquois surplus cash amounting to approximately $28 million less the assumption of $164 million of proportional Iroquois debt by the Partnership.

(b)	The excess purchase price of $370 million was recorded as a reduction in Partners’ Equity.

RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2019

RELATED PARTY TRANSACTIONS

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


Year ended December 31 (millions of dollars)	2019	2018	2017
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes ^(a)	47	44	36
Northern Border^(a)	39	36	43
PNGTS ^(a)	7	9	9
GTN	45	34	34
Bison	2	6	6
North Baja	5	4	4
Tuscarora	4	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	20	19	15
Northern Border	18	16	16
PNGTS	4	5	5
GTN	33	28	29
Bison	2	6	6
North Baja	4	4	4
Tuscarora	4	4	4

Summary of amount payable to related party for costs charged


December 31 (millions of dollars)	2019	2018
Amount payable to TC Energy’s subsidiaries for costs charged in the year by:
Great Lakes ^(a)	5	3
Northern Border^(a)	4	3
PNGTS ^(a)	1	1
GTN	5	4
Bison	—	1
North Baja	1	—
Tuscarora	—	1

(a)	Represents 100 percent of the costs.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income (loss)	$ 298	$ (165)	$ 263
Other comprehensive income (loss)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, after Tax	(13)	(2)	5
Reclassification to net income of gains and losses on cash flow hedges (Notes 12 and 20)	(1)	5
Amortization of realized loss on derivative instrument (Notes 12 and 20)		1	1
Other comprehensive income (loss) on equity investments (Note 12)	1	(1)	1
Comprehensive income (loss)	285	(162)	270
Comprehensive income attributable to non-controlling interests	18	17	11
Comprehensive income (loss) attributable to controlling interests	$ 267	$ (179)	$ 259

ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
ACCOUNTS RECEIVABLE AND OTHER
Trade accounts receivable, net of allowance of nil	$ 37	$ 44
Imbalance receivable from affiliates		2
Other	6	2
Accounts receivable and other	43	48
Trade accounts receivable, allowance

NET INCOME (LOSS) PER COMMON UNIT (Tables)

12 Months Ended

Dec. 31, 2019

NET INCOME (LOSS) PER COMMON UNIT

Schedule of net income per common unit


(millions of dollars, except per common unit amounts)	2019		2018		2017

Net income (loss) attributable to controlling interests		280		(182)		252
Net income attributable to PNGTS' former parent ^(a)		—		—		(2)
Net income (loss) allocable to General Partner and Limited Partners		280		(182)		250
Incentive distributions attributable to the General Partner^(b)		—		—		(12)
Net income attributable to the Class B units ^(c)		(8)		(13)		(15)
Net income (loss) allocable to the General Partner and common units		272		(195)		223
Net (income) loss allocable to the General Partner's two percent interest		(5)		4		(4)
Net income (loss) attributable to common units		267		(191)		219
Weighted average common units outstanding (millions) – basic and diluted		71.3		71.3		69.2
Net income (loss) per common unit – basic and diluted	$	3.74	$	(2.68)	$	3.16

(a)	Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated to TC Energy and was not allocable to either the general partner, common units or Class B units.

(b)

Under the terms of the Partnership Agreement, for any quarterly period, the participation of the IDRs is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership’s available cash during the current reporting period, but declared and paid in the subsequent reporting period.

(c)

As discussed in Note 11, 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. 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 and 2017 - less $20 million) and less the Class B Reduction (2019 - $4 million, 2018 - $7 million. The Class B Reduction did not apply during 2017).

SUBSEQUENT EVENTS - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions																					1 Months Ended	12 Months Ended
	Mar. 31, 2020	Feb. 28, 2020	Feb. 18, 2020	Feb. 14, 2020	Jan. 31, 2020	Jan. 21, 2020	Jan. 15, 2020	Jan. 10, 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	Nov. 14, 2017	Aug. 11, 2017	May 15, 2017	Feb. 14, 2017	Jun. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Sep. 01, 2017
Distributions
Partnership's share of distributions																						$ 200.0	$ 188.0	$ 140.0
Return on investment distribution classified as investing activities																						$ 58.0	$ 10.0	$ 5.0
Northern Border
Distributions
Ownership interest (as a percent)																						50.00%
Return on investment distribution classified as investing activities																						$ 50.0
Great Lakes
Distributions
Ownership interest (as a percent)																						46.45%
Northern Border
Distributions
Cash distribution																					$ 100.0
Ownership interest (as a percent)																									50.00%
Subsequent Events
Distributions
Total cash distribution				$ 47.0
Subsequent Events \| Northern Border
Distributions
Ownership interest (as a percent)		50.00%			50.00%
Partnership's share of distributions		$ 9.0			$ 9.0
Subsequent Events \| Great Lakes
Distributions
Ownership interest (as a percent)					46.45%
Partnership's share of distributions					$ 16.0
Subsequent Events \| Iroquois
Distributions
Ownership interest (as a percent)			49.34%
Partnership's share of distributions	$ 13.0
Return on investment distribution classified as investing activities	$ 2.6
Subsequent Events \| Northern Border
Distributions
Cash distribution								$ 18.0
Limited partners, Distribution declared				19.0
Subsequent Events \| Great Lakes
Distributions
Limited partners, Distribution declared								$ 34.0
Subsequent Events \| Iroquois
Distributions
Limited partners, Distribution declared			$ 27.0
Subsequent Events \| PNGTS
Distributions
Limited partners, Distribution declared							$ 18.0
Share of distributions to its non-controlling interest owner							$ 7.0
TC Pipelines, LP \| Subsequent Events \| Two Percent interest
Distributions
Cash distribution				1.0
Common Units
Distributions
Cash distribution									$ 46.0	$ 46.0	$ 46.0	$ 46.0	$ 46.0	$ 46.0	$ 46.0	$ 71.0	$ 70.0	$ 69.0	$ 65.0	$ 64.0
Number of units																						71,300,000	71,300,000	70,600,000
Common Units \| General Partner \| TC Pipelines, LP
Distributions
Ownership interest in the Partnership (as a percent)																						2.00%	2.00%	2.00%
Common Units \| Subsequent Events
Distributions
Per Unit Distribution, declared (in dollars per unit)						$ 0.65
Cash distribution				46.0
Common Units \| Limited Partners
Distributions
Number of units																						71,306,396
Common Units \| TC Pipelines, LP \| Subsequent Events
Distributions
Cash distribution				$ 4.0
Common Units \| TC Pipelines, LP \| Limited Partners
Distributions
Number of units																						5,797,106
Common Units \| TC Pipelines, LP \| Limited Partners \| Subsequent Events
Distributions
Number of units				5,797,106
Common Units \| TC Energy \| Subsequent Events
Distributions
Cash distribution				$ 7.0
Common Units \| TC Energy \| Limited Partners
Distributions
Number of units																						11,287,725
Common Units \| TC Energy \| Limited Partners \| Subsequent Events
Distributions
Number of units				11,287,725
Class B Units
Distributions
Cash distribution												$ 13.0				$ 15.0				$ 22.0		$ 13.0	$ 15.0	$ 22.0
Class B Units \| Subsequent Events
Distributions
Cash distribution				$ 8.0
Limited partners, Distribution declared						$ 13.0
Class B Units \| TC Energy \| GTN
Distributions
Threshold of GTN's distributions for payment to Class B units																						$ 20.0

SIGNIFICANT ACCOUNTING POLICIES - Useful Lives of Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2019
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	77 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

ORGANIZATION

12 Months Ended

Dec. 31, 2019

ORGANIZATION

ORGANIZATION

NOTE 1 ORGANIZATION

TC PipeLines, LP and its subsidiaries are collectively referred to herein as the Partnership. The Partnership 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.

At December 31, 2018, the Partnership owned its pipeline assets through an intermediate general partnership, TC PipeLines Intermediate GP, LLC (Intermediate GP) and three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership. During the fourth quarter of 2019, the Partnership initiated the dissolution of the ILPs and Intermediate GP. Effective October 31, 2019, the Intermediate GP and ILPs transferred 100 percent of the ownership of their pipeline assets to the Partnership. As a result, the Partnership owns its pipeline assets directly which creates a more efficient partnership structure with no economic impact to the general and limited partners of the Partnership.


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), Dominion Energy (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, 2019. 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 Classs B units at December 31, 2019 (Refer to Note 11).

ORGANIZATION (Tables)

12 Months Ended

Dec. 31, 2019

ORGANIZATION

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), Dominion Energy (50 percent). Iroquois is maintained and operated by a subsidiary of Iroquois.	49.34 percent

VARIABLE INTEREST ENTITIES (VIEs) - Consolidated VIEs (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
ASSETS (LIABILITIES)
Cash and cash equivalents	$ 83	$ 33
Accounts receivable and other	43	48
Inventories	10	8
Other current assets	6	8
Equity investments	1,098	1,196
Property, plant and equipment	1,528	1,529
Other assets		6
Accounts payable and accrued liabilities	(28)	(36)
Accounts payable to affiliates, net	(8)	(6)
Accrued interest	(11)	(12)
Current portion of long-term debt	(123)	(36)
Long-term debt	(1,880)	(2,072)
Other liabilities	(36)	(29)
Restricted VIEs \| Consolidated VIEs
ASSETS (LIABILITIES)
Cash and cash equivalents		16
Accounts receivable and other		39
Inventories		8
Other current assets		6
Equity investments	$ 491	1,196
Property, plant and equipment		1,240
Other assets		1
Accounts payable and accrued liabilities		(33)
Accounts payable to affiliates, net		(40)
Accrued interest		(2)
Current portion of long-term debt		(36)
Long-term debt		(341)
Other liabilities		(27)
Deferred state income tax		$ (9)

FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
FINANCIAL CHARGES AND OTHER
Interest expense	$ 88	$ 95	$ 83
Net realized gain related to the interest rate swaps	(1)	(2)
PNGTS' amortization of loss on derivative instruments		1	1
Other	(4)	(2)	(2)
Financial charges and other	$ 83	$ 92	$ 82

SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
State income tax benefit (expense)
Total state income taxes	$ 1	$ (1)	$ (1)
PNGTS
Income Taxes
Effective income tax rate (as a percent)	2.60%	3.50%	3.80%
State income tax benefit (expense)
Current	$ 1	$ 2	$ 1
Deferred	(2)	(1)
Total state income taxes	$ (1)	$ 1	$ 1

FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - USD ($) $ in Millions		12 Months Ended
	Jun. 26, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest rate derivatives
Net realized gain related to the interest rate swaps included in financial charges and other			$ 1.0	$ 1.0
Amortization of Derivatives Loss			1.0	1.0
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, after Tax		$ (13.0)	$ (2.0)	5.0
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 (as a percent)		5.90%	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		$ 1.0		0.0
Hedges of cash flows \| Recurring fair value measurement \| Level 2 \| Interest rate swaps
Interest rate derivatives
Fair value of derivative asset, gross			$ 8.0
Fair value of derivative liability, gross		6.0
Fair value of derivative asset, net			8.0
Fair value of derivative liability, net		6.0
PNGTS
Interest rate derivatives
Amortization of Derivatives Loss			$ 1.0	$ 1.0
PNGTS
Interest rate derivatives
Ownership interest (as a percent)			61.71%	61.71%
PNGTS
Interest rate derivatives
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, after Tax			$ 20.9
Payments for derivative instruments		$ 20.9

SIGNIFICANT ACCOUNTING POLICIES - Ownership Interests Acquired (Details)	Jun. 01, 2017
PNGTS
Acquisitions
Interest acquired (as a percent)	11.81%
Ownership interest (as a percent)	11.81%
Iroquois
Acquisitions
Interest acquired (as a percent)	49.34%
PNGTS
Acquisitions
Ownership interest, including acquired interest (as a percent)	61.71%

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Jan. 06, 2020	Dec. 31, 2019	Aug. 01, 2017	Jun. 01, 2017
Iroquois
Interest acquired (as a percent)	49.34%	49.34%	49.34%	49.34%
PNGTS
Interest acquired (as a percent)				11.81%

OTHER LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
OTHER LIABILITIES
Regulatory liabilities	$ 29	$ 27
Other liabilities	7	2
Other liabilities, total	$ 36	$ 29

GOODWILL AND REGULATORY (Details) $ in Millions			3 Months Ended		5 Months Ended	12 Months Ended		18 Months Ended	24 Months Ended	36 Months Ended	42 Months Ended	44 Months Ended	48 Months Ended	65 Months Ended
GOODWILL AND REGULATORY (Details) $ in Millions	Dec. 06, 2018	Dec. 01, 2018	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 01, 2020	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 01, 2020 item	Dec. 31, 2021	Dec. 31, 2021	Jan. 31, 2023	Oct. 01, 2022	Jan. 31, 2023	Jul. 01, 2024	Nov. 30, 2018 USD ($)	Oct. 16, 2018 USD ($)	Dec. 31, 2017 USD ($)
REGULATORY
Provision for revenue sharing							$ 10
Goodwill impairment charge							59
Goodwill			$ 71			$ 71	71										$ 130
Great Lakes \| FERC
REGULATORY
Decrease in rate (as a percent)												2.00%
GTN \| FERC
REGULATORY
Decrease in rate (as a percent)									6.60%	10.00%
Amount agreed to issue as refund to customers from January 1 to October 31, 2018															$ 10	$ 10
Rate reduction replaced (as a percent)															(8.30%)
Provision for revenue sharing			1	$ 9
Northern Border \| FERC
REGULATORY
Decrease in rate (as a percent)														2.00%
Iroquois \| FERC
REGULATORY
Decrease in rate (as a percent)					3.25%			3.25%
Iroquois \| 2016 Settlement \| FERC
REGULATORY
Decrease in rate (as a percent)								6.50%
Iroquois \| 2019 Settlement \| FERC
REGULATORY
Decrease in rate (as a percent)								6.50%
Number phases of reduction of rates \| item								2
North Baja
REGULATORY
Goodwill						48
North Baja \| FERC
REGULATORY
Decrease in rate (as a percent)		10.80%
Tuscarora
REGULATORY
Decrease in rate (as a percent)	1.70%
Goodwill						23
Tuscarora \| FERC
REGULATORY
Decrease in rate (as a percent)											10.80%		1.70%
Tuscarora
REGULATORY
Goodwill impairment charge						59
Goodwill			$ 82			$ 23	$ 82

PARTNERS' EQUITY - ATM Equity Issuance Program (Details) - ATM Equity Issuance Program - USD ($) shares in Millions, $ in Millions	2 Months Ended	12 Months Ended
	May 19, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Aug. 31, 2016	Aug. 31, 2014
Common Units
PARTNERS' EQUITY
Aggregate gross sales limit					$ 400	$ 200
Units sold		0.7	3.2
Net proceeds from issuance of common units		$ 39	$ 173
Sales agent commissions			2
Reclassification of common unit issuance subject to rescission, net (in units)	1.6
Common units subject to rescission				$ 0
TC Pipelines, LP \| General Partner
PARTNERS' EQUITY
Equity contribution		$ 1	$ 3

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, 2018
Schedule of Investments [Line Items]
Impairment of long-lived assets		$ 537
Bison
Schedule of Investments [Line Items]
Reduction in future revenue	$ 537

CASH DISTRIBUTIONS - Distributions by Payment Date (Details) - USD ($) $ / shares in Units, $ in Millions																3 Months Ended								12 Months Ended
	Feb. 14, 2020	Jan. 21, 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	Nov. 14, 2017	Aug. 11, 2017	May 15, 2017	Feb. 14, 2017	Apr. 01, 2015	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Partners' Equity
Per Unit Distribution, paid (in dollars per unit)			$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 0.65	$ 1.00	$ 1.00	$ 1.00	$ 0.94	$ 0.94
General Partner 2% paid			$ 1	$ 1	$ 1	$ 1	$ 1	$ 1	$ 1	$ 2	$ 1	$ 2	$ 1	$ 2
General Partner IDRs paid										3	3	3	2	2										$ 0	$ 3	$ 10
Total cash distributions			47	47	47	60	47	47	47	91	74	74	68	90										189	218	284
Common Units
Partners' Equity
Per Unit Distribution, paid (in dollars per unit)	$ 0.65
Cash distribution			$ 46	$ 46	$ 46	46	$ 46	$ 46	$ 46	71	$ 70	$ 69	$ 65	64
Total cash distributions																$ 47	$ 47	$ 47	$ 47	$ 47	$ 47	$ 47	$ 76
Class B Units
Partners' Equity
Cash distribution						$ 13				$ 15				$ 22										$ 13	$ 15	$ 22
Total cash distributions																			$ 13				$ 15
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%
Subsequent Events
Partners' Equity
Per Unit Distribution, paid (in dollars per unit)	$ 0.65
General Partner 2% paid	$ 1
Total cash distributions	55
Total Cash Distribution	47
Subsequent Events \| Common Units
Partners' Equity
Per Unit Distribution, declared (in dollars per unit)		$ 0.65
Cash distribution	46
Subsequent Events \| Class B Units
Partners' Equity
Cash distribution	$ 8

SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2019

SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation - Consolidation and equity method of accounting

(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.

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.

On June 1, 2017, the Partnership acquired from a subsidiary of TC Energy an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 8). This acquisition was accounted for as transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TC Energy's carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TC Energy a 49.34 percent interest in Iroquois (Refer to Note 8). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to a pooling of interest, whereby the equity investment in Iroquois was recorded at TC Energy's carrying value and was accounted for prospectively.

Use of Estimates

(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.

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.

Trade Accounts Receivable

(d) 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.

Natural gas imbalances

(e) 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.

Inventories

(f) Inventories

Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost and net realizable value.

Property, plant and Equipment

(g) 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. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from five 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. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized.

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. Amounts included in construction work in progress are not depreciated until transferred into service.

Impairment of Equity Method Investments

(h) 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

(i) 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.

Partners' Equity

(j) Partners’ Equity

Costs incurred in connection with the issuance of units are deducted from the proceeds received.

Revenue Recognition

(k) 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 Federal Energy Regulatory Commission (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

(l) 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.

Income Taxes

(m) 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 on PNGTS

The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) 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, 2019, 2018 and 2017 relate primarily to utility plant. The NH BPT effective tax rate was 2.6 percent for the year ended December 31, 2019 (2018 – 3.5 percent, 2017 - 3.8 percent) and was applied to PNGTS’ taxable income.

The state income taxes of PNGTS are broken out as follows:


Year ended December 31 (millions of dollars)	2019	2018	2017
State income tax benefit (expense)
Current	(1)	(2)	(1)
Deferred	2	1	—
	1	(1)	(1)

Acquisitions and Goodwill

(n) 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 and 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 of 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 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

(o) 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.

Derivative Financial Instruments and Hedging Activities

(p) 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

(q) 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, 2019 and 2018.

Government Regulation

(r) Government Regulation

The Partnership's subsidiaries are subject to regulation by FERC. Under 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, 2019, the Partnership had nil amount of regulatory assets reported as part of other current assets in the balance sheet and nil amount of regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities. At December 31, 2018, the Partnership had regulatory assets amounting to $2 million reported as part of other current assets in the balance sheet and $2 million regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities both representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually. 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 10).

ACQUISITIONS - 2017 Acquisition and 2016 PNGTS Acquisition (Details)			1 Months Ended	12 Months Ended
	Aug. 01, 2017 USD ($) item	Jun. 01, 2017 USD ($)	Aug. 31, 2019 USD ($)	Dec. 31, 2019 USD ($)	Feb. 20, 2020 USD ($)	Jan. 06, 2020
PNGTS
ACQUISITIONS
Ownership interest, including acquired interest (as a percent)		61.71%
Outstanding debt		$ 5,000,000
PNGTS purchase price
Current assets		25,000,000
Property, plant and equipment, net		294,000,000
Current liabilities		(4,000,000)
Deferred state income taxes		(10,000,000)
Long-term debt, including current portion		(41,000,000)
Net assets		264,000,000
Non-controlling interest		(100,000,000)
Carrying value of pre-existing Investment in PNGTS		(132,000,000)
TransCanada's carrying value of the acquired 11.81 percent interest at June 1, 2017		32,000,000
Excess purchase price over net assets acquired		21,000,000
Total cash consideration		53,000,000
Purchase price before assumption of debt		55,000,000
Final working capital adjustment		3,000,000
Reduction in partner's equity due to excess purchase price		$ 21,000,000
Iroquois
ACQUISITIONS
Interest acquired (as a percent)	49.34%	49.34%		49.34%		49.34%
Option to acquire (as a percent)		0.66
Amount of final purchase price adjustments		$ 19,000,000
Additional consideration on surplus cash		28,000,000
Purchase price before assumption of debt		710,000,000
Outstanding debt		164,000,000
Payment for option to acquire		1,000
Net purchase price
Net Purchase Price		593,000,000
Less: TransCanada's carrying value of Iroquois at June 1, 2017		223,000,000
Excess purchase price		370,000,000
Net purchase price		710,000,000	$ 4,000,000	$ 4,000,000
Reduction in partner's equity under equity method investments		370,000,000
Iroquois \| PNGTS
ACQUISITIONS
Purchase price		765,000,000
Amount of final purchase price adjustments		$ 50,000,000
Iroquois \| Investing Activities
ACQUISITIONS
Expected return on investment distribution classified as investing activities	$ 28,400,000
Number of quarters for distribution of surplus cash \| item	11
Iroquois \| TC Energy
ACQUISITIONS
Expected return on investment distribution classified as investing activities	$ 28,000,000
Iroquois \| Cash Distribution Paid
ACQUISITIONS
Distributions received to date					$ 25,800,000
PNGTS
ACQUISITIONS
Interest acquired (as a percent)		11.81%
Interest acquired by Partnership (as a percent)		11.81%
Purchase price		$ 55,000,000
Amount of final purchase price adjustments		3,000,000
Outstanding debt		$ 5,000,000

SIGNIFICANT ACCOUNTING POLICIES - Asset Retirement Obligation and Regulatory Assets (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Other current assets
Regulatory assets and liabilities
Regulatory assets	$ 0	$ 2,000,000
Accounts payable and accrued liabilities
Regulatory assets and liabilities
Regulatory liabilities	0	2,000,000
Pipeline
Asset Retirement Obligation
Asset retirement liabilities	$ 0	$ 0

SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2019

SIGNIFICANT ACCOUNTING POLICIES

Schedule of state income taxes of PNGTS


Year ended December 31 (millions of dollars)	2019	2018	2017
State income tax benefit (expense)
Current	(1)	(2)	(1)
Deferred	2	1	—
	1	(1)	(1)

PARTNERS' EQUITY - Class B Units (Details) - USD ($) $ / shares in Units, $ in Millions														3 Months Ended	12 Months Ended
	Nov. 14, 2019	Aug. 14, 2019	May 13, 2019	Feb. 11, 2019	Nov. 14, 2018	Aug. 15, 2018	May 15, 2018	Feb. 13, 2018	Nov. 14, 2017	Aug. 11, 2017	May 15, 2017	Feb. 14, 2017	Apr. 01, 2015	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Common Units
PARTNERS' EQUITY
Cash distribution	$ 46	$ 46	$ 46	$ 46	$ 46	$ 46	$ 46	$ 71	$ 70	$ 69	$ 65	$ 64
Net income (loss) attributable to common units															$ 267	$ (191)	$ 219
Class B Units
PARTNERS' EQUITY
Cash distribution				$ 13				$ 15				$ 22			13	15	22
Net income (loss) attributable to common units															$ 8	$ 13	15
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
Threshold of GTN's distributions for payment to Class B units															$ 20
Percentage applied to GTN's distributable cash flow															30.00%
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 December 31, 2019															100.00%
Threshold of GTN's total distributable cash flows for payment to Class B units for the year ending December 31, 2019															$ 20
Percentage applied to 30 percent of GTN's distributions above threshold thereafter															25.00%
Threshold of GTN's distributions for payment to Class B units															$ 20		$ 20	$ 20
Percentage applied to GTN's distributable cash flow															30.00%