TC Pipelines (TCP) 10-Q1 Aug 192019 Q2 Quarterly reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
Document and Entity Information - shares	Jun. 30, 2019	Aug. 01, 2019
Document and Entity Information
Document Type	10-Q
Document Quarterly Report	true
Document Transition Report	false
Document Period End Date	Jun. 30, 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	Q2
Amendment Flag	false

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Transmission revenues	$ 93	$ 111	$ 206	$ 226
Equity earnings (Note 5)	30	36	84	95
Operation and maintenance expenses	(17)	(17)	(33)	(33)
Property taxes	(6)	(7)	(13)	(14)
General and administrative	(2)	(1)	(4)	(2)
Depreciation and amortization	(19)	(24)	(39)	(48)
Financial charges and other (Note 15)	(21)	(23)	(43)	(46)
Net income before taxes	58	75	158	178
Income taxes	(1)		(1)	(1)
Net Income	57	75	157	177
Net income attributable to non-controlling interests	2	2	9	8
Net income attributable to controlling interests	55	73	148	169
Net income attributable to controlling interest allocation (Note 9)
General Partner	1	1	3	3
Net income attributable to controlling interests	55	73	148	169
Common Units
Net income attributable to controlling interest allocation (Note 9)
Net income attributable to common units	$ 54	$ 72	$ 145	$ 166
Net income per common unit (Note 9) - basic and diluted (in dollars per unit)	$ 0.75	$ 1	$ 2.03	$ 2.33
Weighted average common units outstanding - basic and diluted (in units)	71.3	71.3	71.3	71.2
Common units outstanding, end of period (in units)	71.3	71.3	71.3	71.3

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income	$ 57	$ 75	$ 157	$ 177
Other comprehensive income
Change in fair value of cash flow hedges (Note 13)	(9)	(1)	(14)	6
Amortization of realized loss on derivative financial instruments		2		2
Reclassification of net income of gains and losses on cash flow hedges	1	3	1	3
Comprehensive income	49	79	144	188
Comprehensive income attributable to non-controlling interests	2	3	9	9
Comprehensive income attributable to controlling interests	$ 47	$ 76	$ 135	$ 179

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 45	$ 33
Accounts receivable and other (Note 14)	33	48
Inventories	9	8
Other	3	8
Total current assets	90	97
Equity investments (Note 5)	1,118	1,196
Property, plant and equipment (Net of $1,145 accumulated depreciation; 2018 - $1,110)	1,520	1,529
Goodwill	71	71
Other assets		6
TOTAL ASSETS	2,799	2,899
Current Liabilities
Accounts payable and accrued liabilities	26	36
Accounts payable to affiliates (Note 12)	6	6
Accrued interest	11	12
Current portion of long-term debt (Note 7)	101	36
Total current liabilities	144	90
Long-term debt, net (Note 7)	1,892	2,072
Deferred state income taxes	9	9
Other liabilities	34	29
Total liabilities	2,079	2,200
Partners' Equity
General partner	14	13
Accumulated other comprehensive income (loss) (AOCI)	(5)	8
Controlling interests	618	591
Non-controlling interests	102	108
Total partners' equity	720	699
TOTAL LIABILITIES AND PARTNERS' EQUITY	2,799	2,899
Common Units
Partners' Equity
Limited partner	514	462
Class B Units
Partners' Equity
Limited partner	$ 95	$ 108

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
CONSOLIDATED BALANCE SHEETS
Accumulated depreciation	$ 1,145	$ 1,110

CONSOLIDATED STATEMENT OF CASH

CONSOLIDATED STATEMENT OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Cash Generated from Operations
Net income	$ 57	$ 75	$ 157	$ 177
Depreciation and amortization	19	24	39	48
Amortization of debt issue costs reported as interest expense			1	1
Amortization of realized losses				2
Equity earnings from equity investments (Note 5)	(30)	(36)	(84)	(95)
Distributions received from operating activities of equity investments (Note 5)			112	96
Change in other long term liabilities				(1)
Equity allowance for funds used during construction (AFUDC equity)			(1)
Change in operating working capital (Note 11)			4	(5)
Cash generated from operations			228	223
Investing Activities
Investment in Great Lakes (Note 5)			(5)	(4)
Distribution received from return of investment (Note 5)	52.6		55.2
Capital expenditures			(29)	(9)
Customer advances for construction			1
Investing activities			22	(8)
Financing Activities
Distributions paid to common units, including the general partner (Note 10)			(95)	(123)
Distributions paid to Class B units (Note 8)			(13)	(15)
Distributions paid to non-controlling interests			(15)	(3)
Common unit issuance, net				40
Long-term debt issued, net of discount (Note 7)			20	130
Long-term debt repaid (Note 7)			(135)	(225)
Debt issuance costs				(1)
Financing activities			(238)	(197)
Increase in cash and cash equivalents			12	18
Cash and cash equivalents, beginning of period			33	33
Cash and cash equivalents, end of period	45	51	45	51
Iroquois
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	(7)	(9)	(20)	(27)
Investing Activities
Distribution received from return of investment (Note 5)			5	5
Northern Border
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	$ (14)	$ (15)	(35)	$ (32)
Investing Activities
Distribution received from return of investment (Note 5)			$ 50

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - 6 months ended Jun. 30, 2019 - USD ($) shares in Millions, $ in Millions	Limited PartnersCommon Units	Limited PartnersClass B Units	General Partner	Accumulated Other Comprehensive Income (Loss)	[1]	Non-Controlling Interest	Total
Partners' Equity at beginning of period at Dec. 31, 2018	$ 462	$ 108	$ 13	$ 8		$ 108	$ 699
Partners' Equity at beginning of period (in units) at Dec. 31, 2018	71.3	1.9
Increase (Decrease) in Partners' Equity
Net income	$ 145		3			9	157
Other comprehensive income (loss)				(13)			(13)
Distributions (Note 10)	(93)	$ (13)	(2)			(15)	(123)
Partners' Equity at end of period at Jun. 30, 2019	$ 514	$ 95	$ 14	$ (5)		$ 102	$ 720
Partners' Equity at end of period (in units) at Jun. 30, 2019	71.3	1.9

[1]	Gain (loss) related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months is estimated to be $2 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

CONSOLIDATED STATEMENT OF CHA_2

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	6 Months Ended
	Jun. 30, 2019USD ($)
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
Gain (Loss) related to cash flow hedges in AOCI expected to be reclassified to Net income in the next 12 months	$ 2

ORGANIZATION

ORGANIZATION	6 Months Ended
ORGANIZATION	Jun. 30, 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. The Partnership owns its pipeline assets through an intermediate general partnership, TC PipeLines Intermediate GP, LLC and three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES	6 Months Ended
SIGNIFICANT ACCOUNTING POLICIES	Jun. 30, 2019
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 SIGNIFICANT ACCOUNTING POLICIES The accompanying consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three and six months ended June 30, 2019 and 2018 are not necessarily indicative of the results that may be expected for the full fiscal year. The accompanying consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2018 included in our Annual Report on Form 10-K. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying consolidated financial statements contain all of the appropriate adjustments, which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018, except as described in Note 3, Accounting Pronouncements. 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 as 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. Acquisitions by the Partnership from TC Energy are considered common control transactions. If businesses are acquired from TC Energy that will be consolidated by the Partnership, the historical consolidated financial statements are required to be recast, except net income per common unit, to include the acquired entities for all periods presented. If 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. 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. In instances where the Partnership’s consolidated entities are subject to state income taxes, the asset-liability method is used to account for taxes. This method requires 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 consolidated balance sheets. 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, if any, 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.

ACCOUNTING PRONOUNCEMENTS

ACCOUNTING PRONOUNCEMENTS	6 Months Ended
ACCOUNTING PRONOUNCEMENTS	Jun. 30, 2019
ACCOUNTING PRONOUNCEMENTS
ACCOUNTING PRONOUNCEMENTS	NOTE 3 ACCOUNTING PRONOUNCEMENTS Changes in Accounting Policies effective January 1, 2019 Leases In February 2016, the Financial Accounting Standards Board (FASB) issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than twelve months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the consolidated statements of income. The new guidance does not make extensive changes to previous lessor accounting. Under the new guidance, the Partnership determines if an arrangement is a lease at inception. Operating leases are recognized as ROU assets and included in Property, plant and equipment while corresponding liabilities are included in “Accounts payable and other”, and “Other long-term liabilities” on the consolidated balance sheet. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. As the Partnership’s leases do not provide an implicit rate, the Partnership uses an incremental borrowing rate that approximates its borrowing cost based on the information available at commencement date in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and initial direct costs incurred and excludes lease incentives. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Partnership will exercise that option. Operating lease expense is recognized on a straight-line basis over the lease term and included in “Operation and maintenance expenses” in the consolidated statements of income. The new guidance was effective January 1, 2019 and was applied using optional transition relief which allowed entities to initially apply the new lease standard at adoption and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This transition option allowed us to not apply the new guidance, including disclosure requirements, to the comparative periods presented. We elected available practical expedients and exemptions upon adoption which allowed us: ● not to reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard; ● to carry forward the historical lease classification and our accounting treatment for land easements on existing agreements; ● to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption; ● to not separate lease and non-lease components for all leases for which we are the lessee; and ● to use hindsight in determining the lease term and assessing ROU assets for impairment. In the application of the new guidance, assumptions and judgments are used to determine the following: ● whether a contract contains a lease and the duration of the lease term including exercising lease renewal options. The lease term for all of the Partnership’s leases includes the non-cancellable period of the lease plus any additional periods covered by either the Partnership’s option to extend (or not to terminate) the lease that the Partnership is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor; and ● the discount rate for the lease. The standard did not impact our previously reported results and did not have a material impact on the Partnership's consolidated balance sheets, consolidated statements of income or consolidated statement of cash flows at the date of adoption. The most significant change as a result of the adoption was the recognition of ROU assets and lease liabilities for operating leases which was approximately $0.6 million at January 1, 2019 and $0.5 million at June 30, 2019. For the three and six months ended June 30, 2019, the Partnership’s operating lease cost was not material to the Partnership’s consolidated results. The weighted average remaining term and discount rate of the Partnership’s operating leases was approximately 2.41 years and 3.57 percent, respectively. Fair Value Measurement In August 2018, the FASB issued new guidance that amends certain disclosure requirements for the fair value measurements as part of its disclosure framework project. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Partnership elected to adopt this guidance effective first quarter 2019. The guidance was applied retrospectively and did not have a material effect on the Partnership’s consolidated financial statements. Future accounting changes Measurement of credit losses on financial instruments In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income (loss). The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. We have determined which of our assets are within the scope of the new standard and have started to compile historical credit loss information. We are also assessing our current process to determine if any changes are required as a result. We continue to evaluate the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements. Consolidation In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied on a retrospective basis, however early adoption is permitted. The Partnership has determined that there is no impact to its consolidated financial statements as a result of this new guidance.

REGULATORY

REGULATORY	6 Months Ended
REGULATORY	Jun. 30, 2019
REGULATORY
REGULATORY	NOTE 4 REGULATORY Iroquois, Tuscarora, and Northern Border took the actions listed below to conclude the issues impacting their pipelines as contemplated by the 2017 Tax Act and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by an MLP (collectively “2018 FERC Actions”). Iroquois On February 28, 2019, Iroquois filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (2019 Iroquois Settlement). Among the terms of the 2019 Iroquois Settlement, Iroquois agreed to reduce its existing maximum system rates by 6.5 percent to be implemented in two phases, (i) effective March 1, 2019, a 3.25 percent rate reduction and (ii) effective April 1, 2020, an additional 3.25 percent rate reduction, which will conclude the total 6.5 percent rate reduction from the 2016 settlement rates. The 2019 Iroquois Settlement, which was approved by FERC on May 2, 2019, preserved the 2016 settlement moratorium on further rate changes until September 1, 2020. Unless superseded by a subsequent rate case or settlement, Iroquois will be required to have new rates in effect on March 1, 2023. Tuscarora On March 15, 2019, Tuscarora filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (2019 Tuscarora Settlement). Among the terms of the 2019 Tuscarora Settlement, Tuscarora agreed to reduce its existing maximum system rates by 1.7 percent effective February 1, 2019 through to July 31, 2019. The existing maximum rates will decrease by an additional 10.8 percent for the period August 1, 2019 through the term of the settlement. Tuscarora is required to have new rates in effect on February 1, 2023. Tuscarora and its customers also agreed on a moratorium on further rate changes until January 31, 2023. The 2019 Tuscarora Settlement, which was approved by FERC on May 2, 2019, will also reflect an elimination of the tax allowance previously recovered in rates along with accumulated deferred income taxes (ADIT) for rate-making purposes. Northern Border On May 24, 2019, Northern Border's amended settlement agreement filed with the FERC for approval on April 4, 2019, was approved and its 501-G proceeding was terminated. Until superseded by a subsequent rate case or settlement, effective January 1, 2020, the amended settlement agreement extends the two percent rate reduction implemented on February 1, 2019 to July 1, 2024.

EQUITY INVESTMENTS

EQUITY INVESTMENTS	6 Months Ended
EQUITY INVESTMENTS	Jun. 30, 2019
EQUITY INVESTMENTS
EQUITY INVESTMENTS	NOTE 5 EQUITY INVESTMENTS The Partnership has equity interests in Northern Border, Great Lakes and Iroquois. The pipeline systems owned by these entities are regulated by FERC. The pipeline systems of Northern Border and Great Lakes are operated by subsidiaries of TC Energy. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s equity investments are held through our ILPs that are considered to be variable interest entities (VIEs) (Refer to Note 16). Ownership Equity Earnings Equity Investments Interest at Three months ended Six months ended (unaudited) June 30, June 30, June 30, June 30, December 31, (millions of dollars) 2019 2019 2018 2019 2018 2019 2018 Northern Border 50 % 14 15 35 32 431 497 Great Lakes 46.45 % 9 12 29 36 484 489 Iroquois 49.34 % 7 9 20 27 203 210 30 36 84 95 1,118 1,196 Distributions from Equity Investments Distributions received from equity investments in the three and six months ended June 30, 2019 were $108 million and $167 million, respectively (June 30, 2018 - $56 million and $101 million, respectively), of which $52.6 million and $55.2 million, respectively (June 30, 2018 - $2.6 million and $5.2 million, respectively), were considered return of capital and included in “Investing Activities” in the Partnership’s consolidated statement of cash flows. The return of capital was related to our investment in Northern Border and Iroquois (see further discussion below). Northern Border During the three and six months ended June 30, 2019, the Partnership received distributions from Northern Border amounting to $72 million and $100 million, respectively (June 30, 2018 - $17 million and $39 million, respectively) which includes the Partnership’s 50 percent share of the Northern Border’s $100 million distribution on June 26, 2019. The $100 million was 100 percent financed by borrowing on its $200 million revolving credit facility. The $50 million cash the Partnership received did not represent a distribution of operating cash flow during the period and therefore it was reported as a return of investment in the Partnership’s consolidated statement of cash flows. The Partnership did not have undistributed earnings from Northern Border for the three and six months ended June 30, 2019 and 2018. The summarized financial information provided to us by Northern Border is as follows: (unaudited) (millions of dollars) June 30, 2019 December 31, 2018 ASSETS Cash and cash equivalents 26 10 Other current assets 33 36 Property, plant and equipment, net 1,008 1,037 Other assets 13 13 1,080 1,096 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 46 34 Deferred credits and other 37 35 Long-term debt, net (a) 365 264 Partners’ equity Partners’ capital 633 764 Accumulated other comprehensive loss (1) (1) 1,080 1,096 Three months ended Six months ended (unaudited) June 30, June 30, (millions of dollars) 2019 2018 2019 2018 Transmission revenues 67 68 148 140 Operating expenses (20) (19) (40) (38) Depreciation (16) (15) (31) (30) Financial charges and other (4) (4) (8) (7) Net income 27 30 69 65 (a) No current maturities as of June 30, 2019 and December 31, 2018. At June 30, 2019, Northern Border is in compliance with all its financial covenants. Great Lakes The Partnership made an equity contribution to Great Lakes of $5 million in the first quarter of 2019 (June 30, 2018 - $4 million). This amount represents the Partnership’s 46.45 percent share of an $11 million cash call from Great Lakes to make a scheduled debt repayment. The Partnership did not have undistributed earnings from Great Lakes for the three and six months ended June 30, 2019 and 2018. The summarized financial information provided to us by Great Lakes is as follows: (unaudited) (millions of dollars) June 30, 2019 December 31, 2018 ASSETS Current assets 56 75 Property, plant and equipment, net 687 689 743 764 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 26 26 Net long-term debt, including current maturities (a) 229 240 Other long term liabilities 4 4 Partners' equity 484 494 743 764 Three months ended Six months ended (unaudited) June 30, June 30, (millions of dollars) 2019 2018 2019 2018 Transmission revenues 51 53 123 134 Operating expenses (19) (15) (35) (32) Depreciation (8) (8) (16) (16) Financial charges and other (5) (5) (9) (9) Net income 19 25 63 77 (a) Includes current maturities of $21 million as of June 30, 2019 and as of December 31, 2018. At June 30, 2019, Great Lakes is in compliance with all its financial covenants. Iroquois During the three and six months ended June 30, 2019, the Partnership received distributions from Iroquois amounting to $14 million and $28 million, respectively (June 30, 2018 - $14 million and $28 million, respectively), which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million and $5.2 million, respectively (June 30, 2018 - $2.6 million and $5.2 million, respectively). The unrestricted cash did not represent a distribution of Iroquois’ cash from operations during the period and therefore it was reported as a return of investment in the Partnership’s consolidated statement of cash flows. Iroquois declared its second quarter 2019 distribution of $28 million on July 24, 2019, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2019. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million. The Partnership did not have undistributed earnings from Iroquois for the three and six months ended June 30, 2019 and 2018. The summarized financial information provided to us by Iroquois is as follows: (unaudited) (millions of dollars) June 30, 2019 December 31, 2018 ASSETS Cash and cash equivalents 73 80 Other current assets 25 32 Property, plant and equipment, net 573 581 Other assets 14 8 685 701 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 15 19 Long-term debt, net (a) 319 325 Other non-current liabilities 21 14 Partners' equity 330 343 685 701 Three months ended Six months ended (unaudited) June 30, June 30, (millions of dollars) 2019 2018 2019 2018 Transmission revenues 40 44 92 105 Operating expenses (13) (14) (28) (28) Depreciation (8) (7) (15) (15) Financial charges and other (4) (4) (7) (7) Net income 15 19 42 55 (a) Includes current maturities of $4 million as of June 30, 2019 (December 31, 2018 - $146 million). At June 30, 2019, Iroquois is in compliance with all its financial covenants .

REVENUES

REVENUES	6 Months Ended
REVENUES	Jun. 30, 2019
REVENUES
REVENUES	NOTE 6 REVENUES Disaggregation of Revenues For the three and six months ended June 30, 2019 and 2018, effectively all of the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed in more detail below. Capacity Arrangements and Transportation Contracts The Partnership’s performance obligations in its contracts with customers consist primarily of capacity arrangements and natural gas transportation contracts. 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 has elected to utilize the practical expedient of recognizing revenue as invoiced. The Partnership's pipeline systems are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. As of June 30, 2019, the Partnership does not have any outstanding refund obligations related to any rate proceedings. 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. Contract Balances All of the Partnership’s contract balances pertain to receivables from contracts with customers amounting to $31 million at June 30, 2019 (December 31, 2018 - $44 million) and are recorded as Trade accounts receivable and reported as “Accounts receivable and other” in the Partnership’s consolidated balance sheet (Refer to Note 14). Additionally, our accounts receivable represent the Partnership’s unconditional right to consideration for services completed which includes billed and unbilled accounts. Future revenue from remaining performance obligations When the right to invoice practical expedient is applied, the guidance does not require disclosure of information related to future revenue from remaining performance obligations, therefore, no additional disclosure is required. Additionally, in the application of the right to invoice practical expedient, the Partnership’s revenues from regulated capacity arrangements are recognized based on rates specified in the contract. Therefore, the amount invoiced, which includes the capacity contracted and variable volume of natural gas transported, corresponds directly to the value the customer received. These revenues are recognized on a monthly basis once the Partnership’s performance obligation to provide capacity has been satisfied.

DEBT AND CREDIT FACILITIES

DEBT AND CREDIT FACILITIES	6 Months Ended
DEBT AND CREDIT FACILITIES	Jun. 30, 2019
DEBT AND CREDIT FACILITIES
DEBT AND CREDIT FACILITIES	NOTE 7 DEBT AND CREDIT FACILITIES Weighted Average Weighted Average Interest Rate for the Interest Rate for the (unaudited) Six Months Ended December 31, Year Ended (millions of dollars) June 30, 2019 June 30, 2019 2018 December 31, 2018 TC PipeLines, LP Senior Credit Facility due 2021 — 3.61 % 40 3.14 % 2013 Term Loan Facility due 2022 450 3.73 % 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 29 3.74 % 19 3.55 % Tuscarora Unsecured Term Loan due 2020 24 3.62 % 24 3.10 % North Baja Unsecured Term Loan due 2021 50 3.56 % 50 3.54 % 2,003 2,118 Less: unamortized debt issuance costs and debt discount 10 10 Less: current portion 101 36 1,892 2,072 (a) Fixed interest rate TC PipeLines, LP The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 10, 2021. In March 2019, the Partnership repaid all amounts outstanding under its Senior Credit Facility and there was no outstanding balance at June 30, 2019 (December 31, 2018 - $40 million). The LIBOR-based interest rate applicable to the Senior Credit Facility was 3.77 percent at December 31, 2018. On June 26, 2019, the Partnership repaid $50 million of the principal balance under its 2013 Term Loan Facility using proceeds from Northern Border's special distribution (see Note 5). Additionally, in conjunction with this repayment, the Partnership also terminated an equivalent amount in interest rate swaps that were used to hedge this facility at a rate of 2.81 percent. As of June 30, 2019, the variable interest rate exposure related to the 2013 Term Loan Facility was hedged using interest rate swaps at an average rate of 3.26 percent (December 31, 2018 –3.26 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was 3.69 percent at June 30, 2019 (December 31, 2018 - 3.60 percent). The Senior Credit Facility and the 2013 Term Loan Facility require the Partnership to maintain a certain leverage ratio (debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) of no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions have been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 2.78 to 1.00 as of June 30, 2019. GTN GTN’s Unsecured Senior Notes contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization. GTN’s total debt to total capitalization ratio at June 30, 2019 was During the three months ended June 30, 2019, GTN's Unsecured Term Loan Facility matured and was fully repaid using the Partnership's funds from operations. The LIBOR-based interest rate applicable to GTN’s Unsecured Term Loan Facility was 3.30 percent at December 31, 2018. PNGTS PNGTS’ Revolving Credit Facility requires PNGTS to maintain a leverage ratio not greater than 5.00 to 1.00. The leverage ratio was 0.5 to 1.00 as of June 30, 2019. The LIBOR-based interest rate applicable to PNGTS’ Revolving Credit Facility was 3.69 percent at June 30, 2019 (December 31, 2018 - 3.60 percent). Tuscarora Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of June 30, 2019, the ratio was 9.44 to 1.00. The LIBOR-based interest rate applicable to Tuscarora’s Unsecured Term Loan Facility was 3.57 percent at June 30, 2019 (December 31, 2018 - 3.47 percent). North Baja North Baja’s Term Loan Facility contains a covenant that limits total debt to no greater than 70 percent of North Baja’s total capitalization. North Baja’s total debt to total capitalization ratio at June 30, 2019 was 39.06 percent. The LIBOR-based interest rate applicable to North Baja’s Term Loan Facility was 3.52 percent at June 30, 2019 (December 31, 2018 - 3.54 percent). Partnership (TC PipeLines, LP and its subsidiaries) At June 30, 2019, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Fourth Amended and Restated Agreement of Limited Partnership (Partnership Agreement), incurring additional debt and distributions to unitholders. The principal repayments required of the Partnership on its debt are as follows: (unaudited) (millions of dollars) Principal Payments 2019 1 2020 123 2021 400 2022 450 2023 29 Thereafter 1,000 2,003

PARTNERS' EQUITY

PARTNERS' EQUITY	6 Months Ended
PARTNERS' EQUITY	Jun. 30, 2019
PARTNERS' EQUITY
PARTNERS' EQUITY	NOTE 8 PARTNERS’ EQUITY ATM equity issuance program (ATM program) During the six months ended June 30, 2019, no common units were issued under this program. Class B units issued to TC Energy The Class B units entitle TC Energy to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million for the year ending December 31, 2019; (ii) 43.75 percent of distributions above $20 million for the year ending December 31, 2020; and (iii) 25 percent of distributions above $20 million thereafter (Class B Distribution). Additionally, the Class B Distribution will be further reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018 (Class B Reduction). The Class B Reduction was implemented during the first quarter of 2018 following the Partnership’s common unit distribution reduction of 35 percent. The Class B Reduction will continue to apply to any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit. For the year ended December 31, 2019, the Class B units’ equity account will be increased by the Class B Distribution, less the Class B Reduction, until such amount is declared for distribution and paid in the first quarter of 2020. During the six months ended June 30, 2019, the Class B threshold was not exceeded. For the year ended December 31, 2018, the Class B distribution was $13 million and was declared and paid in the first quarter of 2019.

NET INCOME PER COMMON UNIT

NET INCOME PER COMMON UNIT	6 Months Ended
NET INCOME PER COMMON UNIT	Jun. 30, 2019
NET INCOME PER COMMON UNIT
NET INCOME PER COMMON UNIT	NOTE 9 NET INCOME PER COMMON UNIT Net income per common unit is computed by dividing net income attributable to controlling interests, after deduction of amounts attributable to the General Partner and Class B units, by the weighted average number of common units outstanding. The amount allocable to the General Partner equals an amount based upon the General Partner’s two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement . The amount allocable to the Class B units in 2019 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, 2019 less $20 million and is further reduced by the estimated Class B Reduction for 2019 (December 31, 2018-$20 million less Class B Reduction). During the three and six months ended June 30, 2019 and 2018, no amounts were allocated to the Class B units as the annual threshold was not exceeded. Net income per common unit was determined as follows: (unaudited) Three months ended June 30, Six months ended June 30, (millions of dollars, except per common unit amounts) 2019 2018 2019 2018 Net income attributable to controlling interests 55 73 148 169 Net income attributable to the General Partner (1) (1) (3) (3) Net income attributable to common units 54 72 145 166 Weighted average common units outstanding (millions) 71.3 71.3 71.3 71.2 Net income per common unit – basic and diluted $ 0.75 $ 1.00 $ 2.03 $ 2.33

CASH DISTRIBUTIONS PAID TO COMM

CASH DISTRIBUTIONS PAID TO COMMON UNITS	6 Months Ended
CASH DISTRIBUTIONS PAID TO COMMON UNITS	Jun. 30, 2019
CASH DISTRIBUTIONS PAID TO COMMON UNITS
CASH DISTRIBUTIONS PAID TO COMMON UNITS	NOTE 10 CASH DISTRIBUTIONS PAID TO COMMON UNITS 2019 During the three and six months ended June 30, 2019, the Partnership distributed $0.65 and $1.30 per common unit, respectively, for a total of $47 million and $95 million, respectively. The total distribution paid above includes our General Partner’s share during the three and six months ended June 30, 2019 for its two percent general partner interest, which was $1 million and $2 million, respectively. The General Partner did not receive any distributions in respect of its IDRs during the three and six months ended June 30, 2019. 2018 During the three and six months ended June 30, 2018, the Partnership distributed $0.65 and $1.65 per common unit, respectively, for a total of $47 million and $123 million, respectively. The total distribution paid above includes our General Partner’s share during the three and six months ended June 30, 2018 for its two percent general partner interest, which was $1 million and $3 million, respectively. The distributions paid to our General Partner in respect of IDRs during the three and six months ended June 30, 2018 were nil and $3 million, respectively.

CHANGE IN OPERATING WORKING CAP

CHANGE IN OPERATING WORKING CAPITAL	6 Months Ended
CHANGE IN OPERATING WORKING CAPITAL	Jun. 30, 2019
CHANGE IN OPERATING WORKING CAPITAL
CHANGE IN OPERATING WORKING CAPITAL	NOTE 11 CHANGE IN OPERATING WORKING CAPITAL (unaudited) Six months ended June 30, (millions of dollars) 2019 2018 Change in accounts receivable and other 15 2 Change in inventories (1) — Change in other current assets 3 (1) Change in accounts payable and accrued liabilities (12) (6) Change in accrued interest (1) — Change in operating working capital 4 (5)

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	6 Months Ended
RELATED PARTY TRANSACTIONS	Jun. 30, 2019
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS	NOTE 12 RELATED PARTY TRANSACTIONS The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to conduct the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. For both the three and six months ended June 30, 2019 and 2018, total costs charged to the Partnership by the General Partner were $1 million and $2 million, respectively. As operator of our pipelines, except Iroquois and a certain portion of the PNGTS facilities, TC Energy’s subsidiaries provide capital and operating services to our pipeline systems. TC Energy’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. Iroquois does not receive any capital and operating services from TC Energy (Refer to Note 5). Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three and six months ended June 30, 2019 and 2018 by TC Energy’s subsidiaries and amounts payable to TC Energy’s subsidiaries at June 30, 2019 and December 31, 2018 are summarized in the following tables: Three months ended Six months ended (unaudited) June 30, June 30, (millions of dollars) 2019 2018 2019 2018 Capital and operating costs charged by TC Energy’s subsidiaries to: Great Lakes (a) 12 16 23 24 Northern Border (a) 10 9 19 18 GTN 11 8 21 16 Bison — 1 1 3 North Baja 2 1 3 2 Tuscarora 1 1 2 2 PNGTS (a) 1 2 3 4 Impact on the Partnership’s net income: Great Lakes 5 7 10 11 Northern Border 5 4 9 8 GTN 8 7 16 14 Bison — 1 1 3 North Baja 1 1 2 2 Tuscarora 1 1 2 2 PNGTS 1 1 2 2 (unaudited) (millions of dollars) June 30, 2019 December 31, 2018 Net amounts payable to TC Energy’s subsidiaries are as follows: Great Lakes (a) 5 3 Northern Border (a) 4 3 GTN 4 4 Bison — 1 North Baja 1 — Tuscarora — 1 PNGTS (a) 1 1 (a) Represents 100 percent of the costs. Great Lakes Great Lakes earns significant transportation revenues from TC Energy and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the three and six months ended June 30, 2019, Great Lakes earned 73 percent of its transportation revenues from TC Energy and its affiliates (June 30, 2018 - 72 percent and 70 percent, respectively). At June 30, 2019, $13 million was included in Great Lakes’ receivables with regard to the transportation contracts with TC Energy and its affiliates (December 31, 2018 - $18 million). During the second quarter of 2018, Great Lakes reached an agreement on the terms of new long-term transportation capacity contracts with its affiliate, ANR Pipeline Company. The contracts are for a term of 15 years from November 2021 to October 31, 2036 with a total contract value of approximately $1.3 billion. The contracts contain reduction options (i) at any time on or before April 1, 2019 for any reason and (ii) any time before April 2021, if TC Energy is not able to secure the required regulatory approval related to anticipated expansion projects. During the first quarter of 2019, Great Lakes reached an agreement to amend volume reduction “for any reason” option by extending the period “on or before” April 1, 2019 to “on or before” April 1, 2020. All the other terms remained the same. PNGTS PNGTS earns transportation revenues from TC Energy and its affiliates. For the three and six months ended June 30, 2019, PNGTS earned approximately nil of its transportation revenues from TC Energy and its affiliates (June 30, 2018 - $1 million). At June 30, 2019, nil was included in PNGTS' outstanding receivables with regard to the transportation contracts with TC Energy and its affiliates (December 31, 2018 – nil). In connection with the Portland XPress expansion project, PNGTS has entered into an arrangement with its affiliates regarding the construction of certain facilities on their systems that will be required to fulfill future contracts on the PNGTS system. In the event the anticipated developments do not proceed, PNGTS will be required to reimburse its affiliates for any costs incurred related to the development of these facilities. At June 30, 2019, the total costs incurred by these affiliates was approximately $99 million.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	6 Months Ended
FAIR VALUE MEASUREMENTS	Jun. 30, 2019
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS	NOTE 13 FAIR VALUE MEASUREMENTS (a) Fair Value Hierarchy Under Accounting Standards Codification (ASC) 820, Fair Value Measurements and Disclosures ● Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date. ● Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. ● Level 3 inputs are unobservable inputs for the asset or liability. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. (b) Fair Value of Financial Instruments The carrying value of “cash and cash equivalents”, “accounts receivable and other”, ”accounts payable and accrued liabilities”, “accounts payable to affiliates” and “accrued interest” approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach, which uses period-end market rates and applies a discounted cash flow valuation model. The Partnership has classified the fair value of natural gas imbalances as a Level 2 of the fair value hierarchy for fair value disclosure purposes, as the valuation approach includes quoted prices in the market index and observable volumes for the imbalance. Long-term debt is recorded at amortized cost and classified as Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified as Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership’s debt as at June 30, 2019 and December 31, 2018 was $2,064 million and $2,101 million, respectively. Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. The Partnership’s floating rate debt is subject to LIBOR benchmark interest rate risk. The Partnership uses derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk. The Partnership’s interest rate swaps mature on October 2, 2022 and are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The fixed weighted average interest rate on these instruments is 3.26 percent. On June 26, 2019, in conjunction with the Partnership’s $50 million repayment on its 2013 Term Loan Facility, the Partnership also terminated an equivalent amount in interest rate swaps that were used to hedge this facility at an unwind rate of 2.81% (See also Note 7). At June 30, 2019, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $9 million and $14 million for the three and six months ended June 30, 2019, respectively (June 30, 2018 - loss of $1 million and gain of $6 million, respectively). During the three and six months ended June 30, 2019, a gain of $1 million was reclassified from other comprehensive income to net income (June 30, 2018 - gain of $3 million). For the three and six months ended June 30, 2019, the net realized gain related to the interest rate swaps was nil and $1 million, respectively, and was included in “financial charges and other” (June 30, 2018 - gain of $1 million and $2 million, respectively) (Refer to Note 15). The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the consolidated balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of June 30, 2019 and December 31, 2018.

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER	6 Months Ended
ACCOUNTS RECEIVABLE AND OTHER	Jun. 30, 2019
ACCOUNTS RECEIVABLE AND OTHER
ACCOUNTS RECEIVABLE AND OTHER	NOTE 14 ACCOUNTS RECEIVABLE AND OTHER (unaudited) (millions of dollars) June 30, 2019 December 31, 2018 Trade accounts receivable, net of allowance of nil 31 44 Imbalance receivable from affiliates 1 2 Other 1 2 33 48

FINANCIAL CHARGES AND OTHER

FINANCIAL CHARGES AND OTHER	6 Months Ended
FINANCIAL CHARGES AND OTHER	Jun. 30, 2019
FINANCIAL CHARGES AND OTHER
FINANCIAL CHARGES AND OTHER	NOTE 15 FINANCIAL CHARGES AND OTHER Three months ended Six months ended (unaudited) June 30, June 30, (millions of dollars) 2019 2018 2019 2018 Interest expense (a) 22 24 45 48 PNGTS' amortization of loss on derivative instruments — 2 — 2 Net realized gain related to the interest rate swaps — (1) (1) (2) Other income (1) (2) (1) (2) 21 23 43 46 (a) Includes amortization of debt issuance costs and discount costs.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	6 Months Ended
VARIABLE INTEREST ENTITIES	Jun. 30, 2019
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES	NOTE 16 VARIABLE INTEREST ENTITIES In the normal course of business, the Partnership must re-evaluate its legal entities under the current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for differently under GAAP. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. As a result of its analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but has a variable interest in the entity, are accounted for as equity investments. Consolidated VIEs The Partnership’s consolidated VIEs consist of the intermediate partnerships and mainly the Partnership’s ILPs that hold interests in the Partnership’s pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability it absorbs from the ILPs’ economic performance. The assets and liabilities held through these VIEs that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership are held through GTN, Tuscarora, Northern Border, Great Lakes, PNGTS, Iroquois and North Baja due to their third party debt. The following table presents the total assets and liabilities of these entities that are included in the Partnership’s consolidated balance sheets: (unaudited) (millions of dollars) June 30, 2019 December 31, 2018 ASSETS (LIABILITIES) (a) Cash and cash equivalents 14 16 Accounts receivable and other 29 39 Inventories 9 8 Other current assets 3 6 Equity investments 1,118 1,196 Property, plant and equipment, net 1,240 1,240 Other assets 1 1 Accounts payable and accrued liabilities (22) (33) Accounts payable to affiliates, net (87) (40) Accrued interest (2) (2) Current portion of long-term debt (101) (36) Long-term debt (251) (341) Other liabilities (28) (27) Deferred state income tax (9) (9) (a) Bison, an asset held through our consolidated VIEs, is excluded at June 30, 2019 and at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	6 Months Ended
SUBSEQUENT EVENTS	Jun. 30, 2019
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 17 SUBSEQUENT EVENTS Management of the Partnership has reviewed subsequent events through August 1, 2019, the date the consolidated financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes. On July 23, 2019, the board of directors of the General Partner declared the Partnership’s second quarter 2019 cash distribution in the amount of $0.65 per common unit payable on August 14, 2019 to unitholders of record as of August 2, 2019. The declared distribution totaled $47 million and is payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to the General Partner for its two percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the second quarter of 2019. Northern Border declared its June 2019 distribution of $15 million on July 8, 2019, of which the Partnership received its 50 percent share or $7 million on July 31, 2019. Great Lakes declared its second quarter 2019 distribution of $20 million on July 16, 2019, of which the Partnership received its 46.45 percent share or $9 million on August 1, 2019. Iroquois declared its second quarter 2019 distribution of $28 million on July 24, 2019, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2019. The $14 million includes our proportionate share of Iroquois’ unrestricted cash amounting to $2.6 million (Refer to Note 5). PNGTS declared its second quarter 2019 distribution of $7 million on July 12, 2019, of which $3 million was paid to its non-controlling interest owner on August 1, 2019.

SIGNIFICANT ACCOUNTING POLICI_2

SIGNIFICANT ACCOUNTING POLICIES (Policies)	6 Months Ended
SIGNIFICANT ACCOUNTING POLICIES (Policies)	Jun. 30, 2019
SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation - Consolidation and equity method of accounting	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 as 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. If businesses are acquired from TC Energy that will be consolidated by the Partnership, the historical consolidated financial statements are required to be recast, except net income per common unit, to include the acquired entities for all periods presented. If 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. 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. In instances where the Partnership’s consolidated entities are subject to state income taxes, the asset-liability method is used to account for taxes. This method requires 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 consolidated balance sheets.
Use of Estimates	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, if any, 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.

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	6 Months Ended
EQUITY INVESTMENTS (Tables)	Jun. 30, 2019
EQUITY INVESTMENTS
Schedule of equity investments and summarized financial information for equity investees	Ownership Equity Earnings Equity Investments Interest at Three months ended Six months ended (unaudited) June 30, June 30, June 30, June 30, December 31, (millions of dollars) 2019 2019 2018 2019 2018 2019 2018 Northern Border 50 % 14 15 35 32 431 497 Great Lakes 46.45 % 9 12 29 36 484 489 Iroquois 49.34 % 7 9 20 27 203 210 30 36 84 95 1,118 1,196
Northern Border
EQUITY INVESTMENTS
Schedule of equity investments and summarized financial information for equity investees	(unaudited) (millions of dollars) June 30, 2019 December 31, 2018 ASSETS Cash and cash equivalents 26 10 Other current assets 33 36 Property, plant and equipment, net 1,008 1,037 Other assets 13 13 1,080 1,096 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 46 34 Deferred credits and other 37 35 Long-term debt, net (a) 365 264 Partners’ equity Partners’ capital 633 764 Accumulated other comprehensive loss (1) (1) 1,080 1,096 Three months ended Six months ended (unaudited) June 30, June 30, (millions of dollars) 2019 2018 2019 2018 Transmission revenues 67 68 148 140 Operating expenses (20) (19) (40) (38) Depreciation (16) (15) (31) (30) Financial charges and other (4) (4) (8) (7) Net income 27 30 69 65 (a) No current maturities as of June 30, 2019 and December 31, 2018. At June 30, 2019, Northern Border is in compliance with all its financial covenants.
Great Lakes
EQUITY INVESTMENTS
Schedule of equity investments and summarized financial information for equity investees	(unaudited) (millions of dollars) June 30, 2019 December 31, 2018 ASSETS Current assets 56 75 Property, plant and equipment, net 687 689 743 764 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 26 26 Net long-term debt, including current maturities (a) 229 240 Other long term liabilities 4 4 Partners' equity 484 494 743 764 Three months ended Six months ended (unaudited) June 30, June 30, (millions of dollars) 2019 2018 2019 2018 Transmission revenues 51 53 123 134 Operating expenses (19) (15) (35) (32) Depreciation (8) (8) (16) (16) Financial charges and other (5) (5) (9) (9) Net income 19 25 63 77 (a) Includes current maturities of $21 million as of June 30, 2019 and as of December 31, 2018. At June 30, 2019, Great Lakes is in compliance with all its financial covenants.
Iroquois
EQUITY INVESTMENTS
Schedule of equity investments and summarized financial information for equity investees	(unaudited) (millions of dollars) June 30, 2019 December 31, 2018 ASSETS Cash and cash equivalents 73 80 Other current assets 25 32 Property, plant and equipment, net 573 581 Other assets 14 8 685 701 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 15 19 Long-term debt, net (a) 319 325 Other non-current liabilities 21 14 Partners' equity 330 343 685 701 Three months ended Six months ended (unaudited) June 30, June 30, (millions of dollars) 2019 2018 2019 2018 Transmission revenues 40 44 92 105 Operating expenses (13) (14) (28) (28) Depreciation (8) (7) (15) (15) Financial charges and other (4) (4) (7) (7) Net income 15 19 42 55 (a) Includes current maturities of $4 million as of June 30, 2019 (December 31, 2018 - $146 million). At June 30, 2019, Iroquois is in compliance with all its financial covenants .

DEBT AND CREDIT FACILITIES (Tab

DEBT AND CREDIT FACILITIES (Tables)	6 Months Ended
DEBT AND CREDIT FACILITIES (Tables)	Jun. 30, 2019
DEBT AND CREDIT FACILITIES
Schedule of debt and credit facilities	Weighted Average Weighted Average Interest Rate for the Interest Rate for the (unaudited) Six Months Ended December 31, Year Ended (millions of dollars) June 30, 2019 June 30, 2019 2018 December 31, 2018 TC PipeLines, LP Senior Credit Facility due 2021 — 3.61 % 40 3.14 % 2013 Term Loan Facility due 2022 450 3.73 % 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 29 3.74 % 19 3.55 % Tuscarora Unsecured Term Loan due 2020 24 3.62 % 24 3.10 % North Baja Unsecured Term Loan due 2021 50 3.56 % 50 3.54 % 2,003 2,118 Less: unamortized debt issuance costs and debt discount 10 10 Less: current portion 101 36 1,892 2,072 (a) Fixed interest rate
Schedule of principal repayments required on debt	(unaudited) (millions of dollars) Principal Payments 2019 1 2020 123 2021 400 2022 450 2023 29 Thereafter 1,000 2,003

NET INCOME PER COMMON UNIT (Tab

NET INCOME PER COMMON UNIT (Tables)	6 Months Ended
NET INCOME PER COMMON UNIT (Tables)	Jun. 30, 2019
NET INCOME PER COMMON UNIT
Schedule of net income per common unit	(unaudited) Three months ended June 30, Six months ended June 30, (millions of dollars, except per common unit amounts) 2019 2018 2019 2018 Net income attributable to controlling interests 55 73 148 169 Net income attributable to the General Partner (1) (1) (3) (3) Net income attributable to common units 54 72 145 166 Weighted average common units outstanding (millions) 71.3 71.3 71.3 71.2 Net income per common unit – basic and diluted $ 0.75 $ 1.00 $ 2.03 $ 2.33

CHANGE IN OPERATING WORKING C_2

CHANGE IN OPERATING WORKING CAPITAL (Tables)	6 Months Ended
CHANGE IN OPERATING WORKING CAPITAL (Tables)	Jun. 30, 2019
CHANGE IN OPERATING WORKING CAPITAL
Schedule of change in operating working capital	(unaudited) Six months ended June 30, (millions of dollars) 2019 2018 Change in accounts receivable and other 15 2 Change in inventories (1) — Change in other current assets 3 (1) Change in accounts payable and accrued liabilities (12) (6) Change in accrued interest (1) — Change in operating working capital 4 (5)

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	6 Months Ended
RELATED PARTY TRANSACTIONS (Tables)	Jun. 30, 2019
RELATED PARTY TRANSACTIONS
Summary of capital and operating costs charged to pipeline systems by related party	Three months ended Six months ended (unaudited) June 30, June 30, (millions of dollars) 2019 2018 2019 2018 Capital and operating costs charged by TC Energy’s subsidiaries to: Great Lakes (a) 12 16 23 24 Northern Border (a) 10 9 19 18 GTN 11 8 21 16 Bison — 1 1 3 North Baja 2 1 3 2 Tuscarora 1 1 2 2 PNGTS (a) 1 2 3 4 Impact on the Partnership’s net income: Great Lakes 5 7 10 11 Northern Border 5 4 9 8 GTN 8 7 16 14 Bison — 1 1 3 North Baja 1 1 2 2 Tuscarora 1 1 2 2 PNGTS 1 1 2 2 (a) Represents 100 percent of the costs.
Summary of amount payable to related party for costs charged	(unaudited) (millions of dollars) June 30, 2019 December 31, 2018 Net amounts payable to TC Energy’s subsidiaries are as follows: Great Lakes (a) 5 3 Northern Border (a) 4 3 GTN 4 4 Bison — 1 North Baja 1 — Tuscarora — 1 PNGTS (a) 1 1 (a) Represents 100 percent of the costs.

ACCOUNTS RECEIVABLE AND OTHER (

ACCOUNTS RECEIVABLE AND OTHER (Tables)	6 Months Ended
ACCOUNTS RECEIVABLE AND OTHER (Tables)	Jun. 30, 2019
ACCOUNTS RECEIVABLE AND OTHER
Schedule of accounts receivable and other	(unaudited) (millions of dollars) June 30, 2019 December 31, 2018 Trade accounts receivable, net of allowance of nil 31 44 Imbalance receivable from affiliates 1 2 Other 1 2 33 48

FINANCIAL CHARGES AND OTHER (Ta

FINANCIAL CHARGES AND OTHER (Tables)	6 Months Ended
FINANCIAL CHARGES AND OTHER (Tables)	Jun. 30, 2019
FINANCIAL CHARGES AND OTHER
Schedule of components of financial charges and other	Three months ended Six months ended (unaudited) June 30, June 30, (millions of dollars) 2019 2018 2019 2018 Interest expense (a) 22 24 45 48 PNGTS' amortization of loss on derivative instruments — 2 — 2 Net realized gain related to the interest rate swaps — (1) (1) (2) Other income (1) (2) (1) (2) 21 23 43 46 (a) Includes amortization of debt issuance costs and discount costs.

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	6 Months Ended
VARIABLE INTEREST ENTITIES (Tables)	Jun. 30, 2019
VARIABLE INTEREST ENTITIES
Schedule of assets and liabilities held through VIEs whose assets cannot be used for purposes other settlement of their obligations	(unaudited) (millions of dollars) June 30, 2019 December 31, 2018 ASSETS (LIABILITIES) (a) Cash and cash equivalents 14 16 Accounts receivable and other 29 39 Inventories 9 8 Other current assets 3 6 Equity investments 1,118 1,196 Property, plant and equipment, net 1,240 1,240 Other assets 1 1 Accounts payable and accrued liabilities (22) (33) Accounts payable to affiliates, net (87) (40) Accrued interest (2) (2) Current portion of long-term debt (101) (36) Long-term debt (251) (341) Other liabilities (28) (27) Deferred state income tax (9) (9) (a) Bison, an asset held through our consolidated VIEs, is excluded at June 30, 2019 and at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations.

ORGANIZATION - Ownership Intere

ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details)	6 Months Ended
	Jun. 30, 2019LimitedPartnership
ORGANIZATION
Number of intermediate limited partnerships through which pipeline assets are owned	3

ACCOUNTING PRONOUNCEMENTS - Lea

ACCOUNTING PRONOUNCEMENTS - Leases (Details) - USD ($) $ in Millions	Jun. 30, 2019	Jan. 01, 2019
ACCOUNTING PRONOUNCEMENTS
Operating ROU assets	$ 0.5	$ 0.6
Operating lease liabilities	$ 0.5	$ 0.6
Weighted average remaining term (in years)	2 years 4 months 28 days
Discount rate (in percent)	3.57%

REGULATORY (Details)

REGULATORY (Details) - FERC - item	Feb. 28, 2029	Apr. 04, 2019	Mar. 15, 2019	Feb. 28, 2019
Iroquois
REGULATORY
Reduction of existing maximum system rates (as a percent)	6.50%			6.50%
Number phases of reduction of rates				2
Reduction of existing maximum system rates effective March 1,2019 (as a percent)				3.25%
Reduction of existing maximum system rates effective April 1,2020 (as a percent)				3.25%
Tuscarora Settlement
REGULATORY
Reduction of existing maximum system rates (as a percent)			1.70%
Additional decrease of unit rate (as a percent)			10.80%
Northern Border
REGULATORY
Decrease in rate (as a percent)		2.00%

EQUITY INVESTMENTS (Details)

EQUITY INVESTMENTS (Details) - USD ($) $ in Millions	Aug. 31, 2019	Aug. 01, 2019	Jul. 31, 2019	Jun. 26, 2019	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 26, 2029	Dec. 31, 2018
EQUITY INVESTMENTS
Equity Earnings					$ 30		$ 36	$ 84	$ 95
Equity Investments					1,118			1,118			$ 1,196
Equity contribution								5	4
Distributions from Equity Investments
Distributions received from equity investments					108		56	167	101
Distributions from equity investments								112	96
Return on investment distribution classified as investing activities					52.6			55.2
Northern Border
EQUITY INVESTMENTS
Special distribution from equity investments								100
Borrowings under the revolving credit facility				$ 100
Distribution financed by borrowings (as a percent)										100.00%
Northern Border \| Revolving credit facility
EQUITY INVESTMENTS
Maximum borrowing capacity										$ 200
Great Lakes
EQUITY INVESTMENTS
Total cash call issued to fund debt repayment								11
Iroquois
Distributions from Equity Investments
Distributions from equity investments		$ 14			14		14	28	28
Return on investment distribution classified as investing activities	$ 2.6				$ 2.6		2.6	$ 5.2	5.2
Limited partners, Distribution declared			$ 28
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)					50.00%			50.00%
Equity Earnings					$ 14		15	$ 35	32
Equity Investments					431			431			497
ASSETS
Cash and cash equivalents					26			26			10
Other current assets					33			33			36
Property, plant and equipment, net					1,008			1,008			1,037
Other assets					13			13			13
Assets, total					1,080			1,080			1,096
LIABILITIES AND PARTNERS' EQUITY
Current liabilities					46			46			34
Deferred credits and other					37			37			35
Net long-term debt, including current maturities					365			365			264
Partners' capital					633			633			764
Accumulated other comprehensive loss					(1)			(1)			(1)
Liabilities and Partners' Equity, total					1,080			1,080			1,096
Revenues (expenses)
Transmission revenues					67		68	148	140
Operating expenses					(20)		(19)	(40)	(38)
Depreciation					(16)		(15)	(31)	(30)
Financial charges and other					(4)		(4)	(8)	(7)
Net income					27		30	69	65
Long-term debt current maturities					0			0			0
Distributions from Equity Investments
Distributions received from equity investments					$ 72		17	100	39
Return on investment distribution classified as investing activities								$ 50
Great Lakes
EQUITY INVESTMENTS
Ownership interest (as a percent)					46.45%			46.45%
Equity Earnings					$ 9		12	$ 29	36
Equity Investments					484			484			489
Equity contribution						$ 5			4
ASSETS
Current assets					56			56			75
Property, plant and equipment, net					687			687			689
Assets, total					743			743			764
LIABILITIES AND PARTNERS' EQUITY
Current liabilities					26			26			26
Net long-term debt, including current maturities					229			229			240
Other non-current liabilities					4			4			4
Partners' capital					484			484			494
Liabilities and Partners' Equity, total					743			743			764
Revenues (expenses)
Transmission revenues					51		53	123	134
Operating expenses					(19)		(15)	(35)	(32)
Depreciation					(8)		(8)	(16)	(16)
Financial charges and other					(5)		(5)	(9)	(9)
Net income					19		25	63	77
Long-term debt current maturities					$ 21			$ 21			21
Iroquois
EQUITY INVESTMENTS
Ownership interest (as a percent)	49.34%	49.34%			49.34%			49.34%
Equity Earnings					$ 7		9	$ 20	27
Equity Investments					203			203			210
ASSETS
Cash and cash equivalents					73			73			80
Other current assets					25			25			32
Property, plant and equipment, net					573			573			581
Other assets					14			14			8
Assets, total					685			685			701
LIABILITIES AND PARTNERS' EQUITY
Current liabilities					15			15			19
Net long-term debt, including current maturities					319			319			325
Other non-current liabilities					21			21			14
Partners' capital					330			330			343
Liabilities and Partners' Equity, total					685			685			701
Revenues (expenses)
Transmission revenues					40		44	92	105
Operating expenses					(13)		(14)	(28)	(28)
Depreciation					(8)		(7)	(15)	(15)
Financial charges and other					(4)		(4)	(7)	(7)
Net income					15		$ 19	42	55
Long-term debt current maturities					$ 4			4			$ 146
Distributions from Equity Investments
Return on investment distribution classified as investing activities								$ 5	$ 5

REVENUES - Contract Balances (D

REVENUES - Contract Balances (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Contract Balances
Receivables from contracts with customers	$ 31	$ 44

DEBT AND CREDIT FACILITIES - Am

DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details) - USD ($) $ in Millions	Jun. 26, 2019	Jun. 30, 2019	Jun. 30, 2019	Dec. 31, 2018
Credit facilities, short-term loan facility and long-term debt
Total credit facilities, short-term loan facility and long-term debt		$ 2,003	$ 2,003	$ 2,118
Less: unamortized debt issuance costs and debt discount		10	10	10
Less: current portion		101	101	36
Long-term debt		$ 1,892	$ 1,892	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%
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2022
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, actual (as a percent)		2.78%	2.78%
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2022 \| Each fiscal quarter except fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed \| Maximum
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, covenant (as a percent)			5.00%
Senior Credit Facility due in 2021 and the Term Loan Facilities due in 2022 \| Fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed \| Maximum
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, covenant (as a percent)			5.50%
Revolving credit facility \| TC PipeLines, LP Senior Credit Facility due 2021
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities		$ 0	$ 0	$ 40
Weighted average interest rate (as a percent)		3.61%		3.14%
Maximum borrowing capacity		$ 500	500
Amount outstanding under credit facility		0	0	$ 40
Revolving credit facility \| TC PipeLines, LP Senior Credit Facility due 2021 \| LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)				3.77%
Term loan \| TC PipeLines, LP 2013 Term Loan Facility due 2022
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities		$ 450	$ 450	$ 500
Weighted average interest rate (as a percent)		3.73%		3.23%
Term loan \| TC PipeLines, LP 2013 Term Loan Facility due 2022 \| LIBOR borrowings \| LIBOR
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)				3.60%
Debt interest rate, at period end (as a percent)		3.69%	3.69%
Term loan \| TC PipeLines, LP 2013 Term Loan Facility due 2022 \| LIBOR borrowings \| LIBOR \| Hedges of cash flows \| Interest rate swaps
Credit facilities, short-term loan facility and long-term debt
Weighted average interest rate (as a percent)			3.26%	3.26%
Unsecured debt \| 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	$ 350
Stated interest rate (as a percent)		4.65%	4.65%
Weighted average interest rate (as a percent)		4.65%		4.65%
Unsecured debt \| 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	$ 350
Stated interest rate (as a percent)		4.375%	4.375%
Weighted average interest rate (as a percent)		4.375%		4.375%
Unsecured debt \| 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	$ 500
Stated interest rate (as a percent)		3.90%	3.90%
Weighted average interest rate (as a percent)		3.90%		3.90%
Unsecured debt \| GTN 5.29% Senior Notes due 2020
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)		5.29%	5.29%
Unsecured debt \| GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Stated interest rate (as a percent)		5.69%	5.69%
Unsecured debt \| Tuscarora Term Loan due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities		$ 24	$ 24	$ 24
Weighted average interest rate (as a percent)		3.62%		3.10%
Unsecured debt \| North Baja Term Loan Due 2021
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities		$ 50	$ 50	$ 50
Weighted average interest rate (as a percent)		3.56%		3.54%
Unsecured debt \| North Baja Term Loan Due 2021 \| LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)		3.52%	3.52%	3.54%
GTN \| Unsecured debt \| GTN 5.29% Senior Notes due 2020
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities		$ 100	$ 100	$ 100
Weighted average interest rate (as a percent)		5.29%		5.29%
GTN \| Unsecured debt \| GTN 5.69% Senior Notes due 2035
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities		$ 150	150	$ 150
Weighted average interest rate (as a percent)		5.69%		5.69%
GTN \| Unsecured debt \| Term Loan Facility due 2019
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities		$ 0	$ 0	$ 35
Weighted average interest rate (as a percent)				2.93%
Percentage of debt to total capitalization, covenant			39.90%
GTN \| Unsecured debt \| Term Loan Facility due 2019 \| Maximum
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant			70.00%
GTN \| Unsecured debt \| Term Loan Facility due 2019 \| LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)				3.30%
PNGTS \| Secured debt \| PNGTS Revolving Credit Facility due 2023
Credit facilities, short-term loan facility and long-term debt
Debt and credit facilities		$ 29	$ 29	$ 19
Weighted average interest rate (as a percent)		3.74%		3.55%
Leverage ratio, covenant (as a percent)			0.50%
PNGTS \| Secured debt \| PNGTS Revolving Credit Facility due 2023 \| Maximum
Credit facilities, short-term loan facility and long-term debt
Leverage ratio, covenant (as a percent)			5.00%
PNGTS \| Secured debt \| PNGTS Revolving Credit Facility due 2023 \| LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)		3.69%	3.69%	3.60%
Tuscarora \| Unsecured debt \| Tuscarora Term Loan due 2020
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, covenant (as a percent)			9.44%
Tuscarora \| Unsecured debt \| Tuscarora Term Loan due 2020 \| Minimum
Credit facilities, short-term loan facility and long-term debt
Debt service coverage, covenant (as a percent)			3.00%
Tuscarora \| Unsecured debt \| Tuscarora Term Loan due 2020 \| LIBOR
Credit facilities, short-term loan facility and long-term debt
Debt interest rate, at period end (as a percent)		3.57%	3.57%	3.47%
North Baja \| Unsecured debt \| North Baja Term Loan Due 2021
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, actual		39.06%	39.06%
North Baja \| Unsecured debt \| North Baja Term Loan Due 2021 \| Maximum
Credit facilities, short-term loan facility and long-term debt
Percentage of debt to total capitalization, covenant			70.00%

DEBT AND CREDIT FACILITIES - Pr

DEBT AND CREDIT FACILITIES - Principal Repayments Required (Details) $ in Millions	Jun. 30, 2019USD ($)
Principal repayments required on debt
2019	$ 1
2020	123
2021	400
2022	450
2023	29
Thereafter	1,000
Total debt	$ 2,003

PARTNERS' EQUITY - ATM Equity I

PARTNERS' EQUITY - ATM Equity Issuance Program (Details)	6 Months Ended
PARTNERS' EQUITY - ATM Equity Issuance Program (Details)	Jun. 30, 2019shares
ATM Equity Issuance Program \| Common Units
PARTNERS' EQUITY
Units sold	0

PARTNERS' EQUITY - Class B Unit

PARTNERS' EQUITY - Class B Units (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended		12 Months Ended
	Mar. 31, 2019	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018
PARTNERS' EQUITY
Limited Partners, Distributions paid		$ 13	$ 15
Distributions \| Class B Units
PARTNERS' EQUITY
Limited Partners, Distributions paid	$ 13
TC Energy \| Distributions \| Class B Units
PARTNERS' EQUITY
Percentage of reduction in distributions payable		35.00%
TC Energy \| Distributions \| Common Units
PARTNERS' EQUITY
Percentage of reduction in distributions payable		35.00%
Minimum distribution payable per common unit		$ 3.94
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%
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 for the year ending December 31, 2020		43.75%
Threshold of GTN's total distributable cash flows for payment to Class B units for the year ending December 31, 2020		$ 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

NET INCOME PER COMMON UNIT - Ge

NET INCOME PER COMMON UNIT - General Partner Effective Interest and Allocated Incentive Distributions (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2029	Jun. 30, 2019	Jun. 30, 2018
General Partner \| General Partner
PARTNERS' EQUITY
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	2.00%

NET INCOME PER COMMON UNIT- Ter

NET INCOME PER COMMON UNIT- Terms of Class B Unit Distributions and Determination of Net Income (Loss) per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018
Net income per common unit
Net income attributable to controlling interests	$ 55	$ 73	$ 148	$ 169
Net income attributable to the General Partner	(1)	(1)	(3)	(3)
Class B Units
Net income per common unit
Net income attributable to common units	0	0	0	0
Common Units
Net income per common unit
Net income attributable to common units	$ 54	$ 72	$ 145	$ 166
Weighted average common units outstanding - basic and diluted (in units)	71.3	71.3	71.3	71.2
Net income (loss) per common unit - basic and diluted (in dollars per unit)	$ 0.75	$ 1	$ 2.03	$ 2.33
GTN \| Class B Units \| TC Energy \| Distributions
Distributions
Percentage applied to GTN's distributable cash flow			30.00%
GTN's distributions for payment to Class B units			$ 20		$ 20	$ 20

CASH DISTRIBUTIONS PAID TO CO_2

CASH DISTRIBUTIONS PAID TO COMMON UNITS (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2029	Jun. 30, 2019	Jun. 30, 2018
Common Units
Partners' Equity
Per Unit Distribution, paid (in dollars per unit)	$ 0.65	$ 0.65		$ 1.30	$ 1.65
Total cash distribution	$ 47	$ 47		$ 95	$ 123
General Partner \| General Partner
Partners' Equity
Total distribution for General Partner interest	$ 1	$ 1		$ 2	3
Incentive distribution paid to the General Partner					$ 3
General partner interest (as a percent)	2.00%	2.00%	2.00%	2.00%	2.00%
General Partner \| General Partner \| Incentive Distribution Rights
Partners' Equity
Incentive distribution paid to the General Partner		$ 0

CHANGE IN OPERATING WORKING C_3

CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
CHANGE IN OPERATING WORKING CAPITAL
Change in accounts receivable and other	$ 15	$ 2
Change in inventories	(1)
Change in other current assets	3	(1)
Change in accounts payable and accrued liabilities	(12)	(6)
Change in accrued interest	(1)
Change in operating working capital	$ 4	$ (5)

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 6		$ 6		$ 6
Amount included in receivables from related party	1		1		2
Great Lakes \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	12	$ 16
Impact on the Partnership's net income attributable to controlling interests	5	7
Northern Border \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	10	9
Impact on the Partnership's net income attributable to controlling interests	5	4
PNGTS \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1	2
Impact on the Partnership's net income attributable to controlling interests	1	1
GTN \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	11	8
Impact on the Partnership's net income attributable to controlling interests	8	7
Bison \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged		1
Impact on the Partnership's net income attributable to controlling interests		1
North Baja \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	2	1
Impact on the Partnership's net income attributable to controlling interests	1	1
Tuscarora \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1	1
Impact on the Partnership's net income attributable to controlling interests	1	1
General Partner \| Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged	1	$ 1	2	$ 2
TC Energy \| Great Lakes
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	5		$ 5		3
Percentage of capital and operating costs charged			100.00%	100.00%
Amount included in receivables from related party	$ 13		$ 13		18
TC Energy \| Great Lakes \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			23	$ 24
Impact on the Partnership's net income attributable to controlling interests			$ 10	$ 11
Percentage of capital and operating costs charged			100.00%	100.00%
TC Energy \| Great Lakes \| 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%	72.00%		70.00%
TC Energy \| Northern Border
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 4		$ 4		3
Percentage of capital and operating costs charged			100.00%	100.00%
TC Energy \| Northern Border \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			$ 19	$ 18
Impact on the Partnership's net income attributable to controlling interests			$ 9	$ 8
Percentage of capital and operating costs charged			100.00%	100.00%
TC Energy \| PNGTS
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	1		$ 1		1
Percentage of capital and operating costs charged			100.00%	100.00%
TC Energy \| PNGTS \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			$ 3	$ 4
Impact on the Partnership's net income attributable to controlling interests			$ 2	$ 2
Percentage of capital and operating costs charged			100.00%	100.00%
TC Energy \| PNGTS \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party	0		$ 0		0
Revenues from related party	0	$ 1	0
TC Energy \| GTN
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	4		4		4
TC Energy \| GTN \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			21	$ 16
Impact on the Partnership's net income attributable to controlling interests			16	14
TC Energy \| Bison
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable					1
TC Energy \| Bison \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			1	3
Impact on the Partnership's net income attributable to controlling interests			1	3
TC Energy \| North Baja
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable	$ 1		1
TC Energy \| North Baja \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			3	2
Impact on the Partnership's net income attributable to controlling interests			2	2
TC Energy \| Tuscarora
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable					$ 1
TC Energy \| Tuscarora \| Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged			2	2
Impact on the Partnership's net income attributable to controlling interests			2	2
ANR Pipeline Company \| Great Lakes \| Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Contract term		15 years
Total contract value		$ 1,300		$ 1,300
Affiliates \| PNGTS \| Construction of facilities
Capital and operating costs charged to the pipeline systems and amount payable
Reimbursement of costs			$ 99

FAIR VALUE MEASUREMENTS - Estim

FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Fair Value \| Level 2
Financial Instruments
Fair value of debt	$ 2,064	$ 2,101

FAIR VALUE MEASUREMENTS - Inter

FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - USD ($) $ in Millions	Jun. 26, 2019	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Interest rate derivatives
Change in fair value of interest rate derivative instruments recognized in other comprehensive income (loss)			$ (2)		$ (2)
Reclassification of net income of gains and losses on cash flow hedges		$ 1	3	$ 1	3
Net realized gain related to the interest rate swaps included in financial charges and other					2
Amortization of derivatives loss			2		2
Change in fair value of interest rate derivative instruments recognized in other comprehensive income		$ (9)	(1)	$ (14)	6
2013 Term Loan Facility
Interest rate derivatives
Repayments of secured debt	$ 50
Unwind rate of interest rate swap (as a percent)	2.81%
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%		3.26%
Hedges of cash flows \| Interest rate swaps
Interest rate derivatives
Change in fair value of interest rate derivative instruments recognized in other comprehensive income		$ (9)	(1)	$ (14)	6
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		0	$ 1	1	$ 2
Hedges of cash flows \| Recurring fair value measurement \| Level 2 \| Interest rate swaps
Interest rate derivatives
Fair value of derivative asset, gross						$ 8
Fair value of derivative liability, gross		5		5
Fair value of derivative asset, net						$ 8
Fair value of derivative liability, net		$ 5		$ 5

ACCOUNTS RECEIVABLE AND OTHER_2

ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
ACCOUNTS RECEIVABLE AND OTHER
Trade accounts receivable, net of allowance of nil	$ 31	$ 44
Imbalance receivable from affiliates	1	2
Other	1	2
Accounts receivable and other	$ 33	$ 48

FINANCIAL CHARGES AND OTHER (De

FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
FINANCIAL CHARGES AND OTHER
Interest expense	$ 22	$ 24	$ 45	$ 48
PNGTS' amortization of loss on derivative instruments		2		2
Net realized gain related to the interest rate swaps		(1)	(1)	(2)
Other income	(1)	(2)	(1)	(2)
Financial charges and other	$ 21	$ 23	$ 43	$ 46

VARIABLE INTEREST ENTITIES - Co

VARIABLE INTEREST ENTITIES - Consolidated VIEs (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
ASSETS (LIABILITIES)
Cash and cash equivalents	$ 45	$ 33
Accounts receivable and other	33	48
Inventories	9	8
Other current assets	3	8
Equity investments	1,118	1,196
Property, plant and equipment, net	1,520	1,529
Other assets		6
Accounts payable and accrued liabilities	(26)	(36)
Accounts payable to affiliates, net	(6)	(6)
Accrued interest	(11)	(12)
Current portion of long-term debt	(101)	(36)
Long-term debt	(1,892)	(2,072)
Other liabilities	(34)	(29)
Consolidated VIEs \| Restricted VIEs
ASSETS (LIABILITIES)
Cash and cash equivalents	14	16
Accounts receivable and other	29	39
Inventories	9	8
Other current assets	3	6
Equity investments	1,118	1,196
Property, plant and equipment, net	1,240	1,240
Other assets	1	1
Accounts payable and accrued liabilities	(22)	(33)
Accounts payable to affiliates, net	(87)	(40)
Accrued interest	(2)	(2)
Current portion of long-term debt	(101)	(36)
Long-term debt	(251)	(341)
Other liabilities	(28)	(27)
Deferred state income tax	$ (9)	$ (9)

SUBSEQUENT EVENTS - Distributio

SUBSEQUENT EVENTS - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions

Aug. 01, 2029

Aug. 14, 2019

Aug. 01, 2019

Jul. 31, 2019

Jul. 23, 2019

Jul. 16, 2019

Jul. 12, 2019

Jul. 08, 2019

Aug. 31, 2019

Jun. 30, 2019

Jun. 30, 2018

Jun. 30, 2029

Jun. 30, 2019

Jun. 30, 2018

Distributions

Limited Partners, Distributions paid

$ 13

$ 15

Partnership's share of distributions

$ 112

$ 96

Northern Border

Distributions

Ownership interest (as a percent)

50.00%

Great Lakes

Distributions

Ownership interest (as a percent)

46.45%

Subsequent Events | Northern Border

Distributions

Ownership interest (as a percent)

50.00%

Partnership's share of distributions

$ 7

Subsequent Events | Great Lakes

Distributions

Ownership interest (as a percent)

46.45%

Partnership's share of distributions

$ 9

Subsequent Events | Iroquois

Distributions

Ownership interest (as a percent)

49.34%

Partnership's share of distributions

$ 14

Interest in unrestricted cash

$ 2.6

Subsequent Events | Northern Border

Distributions

Limited partners, Distribution declared

$ 15

Subsequent Events | Great Lakes

Distributions

Limited partners, Distribution declared

$ 20

Subsequent Events | Iroquois

Distributions

Limited partners, Distribution declared

$ 28

Subsequent Events | PNGTS

Distributions

Limited partners, Distribution declared

$ 7

Share of distributions to its non-controlling interest owner

$ 3

General Partner | General Partner

Distributions

Ownership interest in the Partnership (as a percent)

2.00%

Incentive distribution paid to the General Partner

$ 3

Forecast | Subsequent Events

Distributions

Limited Partners, Distributions paid

$ 47

Distribution to General Partner

$ 1

Common Units | Subsequent Events

Distributions

Per Unit Distribution, declared (in dollars per unit)

$ 0.65

Common Units | Subsequent Events | General Partner

Distributions

Ownership interest in the Partnership (as a percent)

2.00%

Common Units | General Partner | Subsequent Events

Distributions

Number of units held by investor

5,797,106

Common Units | TC Energy | Subsequent Events

Distributions

Number of units held by investor

11,287,725

Common Units | Forecast | Subsequent Events

Distributions

Limited Partners, Distributions paid

$ 46

Common Units | Forecast | General Partner | Subsequent Events

Distributions

Limited Partners, Distributions paid

Common Units | Forecast | TC Energy | Subsequent Events

Distributions

Limited Partners, Distributions paid

$ 7