PHMSA			The Pipeline and Hazardous Materials Safety Administration
PNGTS			Portland Natural Gas Transmission System
PXP			Portland XPress Project
~~ROU~~ SEC			~~Right-of-use~~
~~SEC~~	Securities and Exchange Commission
Senior Credit Facility			TC PipeLines, ~~LP's~~LP’s senior facility under revolving credit agreement as amended and restated, dated September 29, 2017
TC Energy			TC Energy Corporation ~~formerly known as TransCanada Corporation~~
Tuscarora			Tuscarora Gas Transmission Company
Tuscarora XPress			Tuscarora's Expansion project to transport additional 15,000 Dth/Day of natural gas supplies through additional compression capability at Tuscarora's existing facility
U.S.			United States of America
~~VIEs~~			~~Variable Interest Entities~~
WCSB		Western Canadian Sedimentary Basin
Westbrook XPress			Westbrook XPress Project of PNGTS that is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility
Wholly-owned subsidiaries			GTN, Bison, North Baja, and Tuscarora
WHO		World Health Organization

Unless the context clearly indicates otherwise, TC PipeLines, LP and its subsidiaries are collectively referred to in this quarterly report as “we,” “us,” “our” and “the Partnership.” We use “our pipeline systems” and “our pipelines” when referring to the Partnership’s ownership interests in Gas Transmission Northwest LLC (GTN), Northern Border Pipeline Company (Northern Border), Bison Pipeline LLC (Bison), Great Lakes Gas Transmission Limited Partnership (Great Lakes), North Baja Pipeline, LLC (North Baja), Tuscarora Gas Transmission Company (Tuscarora), Portland Natural Gas Transmission System (PNGTS) and Iroquois Gas Transmission System, LP (Iroquois).

PART I

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This report includes certain forward-looking statements. Forward-looking statements are identified by words and phrases such as: “anticipate,” “assume,”“ “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “forecast,” “should,” “predict,” “could,” “will,” “may,” and other terms and expressions of similar meaning. The absence of these words, however, does not mean that the statements are not forward-looking. These statements are based on management’s beliefs and assumptions and on currently available information and include, but are not limited to, statements regarding anticipated financial performance, future capital expenditures, liquidity, ~~dropdown opportunities,~~ market or competitive conditions, regulations, organic or strategic growth opportunities, contract renewals and ability to market open capacity, business prospects, outcome of regulatory proceedings and cash distributions to unitholders.

Forward-looking statements involve risks and uncertainties that may cause actual results to differ materially from the results predicted. These risks and uncertainties include, among other things, factors like various risks and uncertainties associated with the current extraordinary market environment and impacts resulting from the Coronavirus 2019 (COVID-19) pandemic and market disruptions relating to global supply and demand for oil and natural gas.

Factors that could cause actual results and our financial condition to differ materially from those contemplated in forward-looking statements include, but are not limited to:

●

~~the ability of our pipeline systems to sell available capacity on favorable terms and renew expiring contracts which are affected by, among other factors:~~

●

~~demand for natural gas;~~

●

~~changes in relative cost structures and production levels of natural gas producing basins;~~

●

~~natural gas prices and regional differences;~~

●

~~weather conditions;~~

●

~~availability and location of natural gas supplies in Canada and the United States (U.S.) in relation to our pipeline systems;~~

●

~~competition from other pipeline systems;~~

●

~~natural gas storage levels;~~

●

~~rates and terms of service;~~

●

~~the performance by the shippers of their contractual obligations on our pipeline systems;~~

●

~~the outcome and frequency of rate proceedings or settlement negotiations on our pipeline systems;~~

●

~~other potential changes in the taxation of master limited partnership (MLP) investments by state or federal governments such as the elimination of pass-through taxation or tax deferred distributions;~~

●

increases in operational or compliance costs resulting from changes in laws and governmental regulations affecting our pipeline systems, particularly regulations issued by the Federal Energy Regulatory Commission (FERC), U.S. Environmental Protection Agency (EPA) and U.S. Department of Transportation (DOT);

●

~~the impact of downward changes in oil and natural gas prices, including the effects on the creditworthiness of our shippers;~~

●

~~our ongoing ability to grow distributions through acquisitions, accretive expansions or other growth opportunities, including the timing, structure and closure of further potential acquisitions;~~

●

~~potential conflicts of interest between TC PipeLines GP, Inc., our general partner (General Partner),TC Energy Corporation and us;~~

●

~~failure to comply with debt covenants, some of which are beyond our control;~~

●

~~the ability to maintain secure operation of our information technology including management of cybersecurity threats, acts of terrorism and related distractions;~~

●

~~the implementation of future accounting changes and ultimate outcome of commitments and contingent liabilities (if any);~~

●

~~the impact of any impairment charges;~~

●

~~changes in political environment;~~

●

~~operating hazards, casualty losses and other matters beyond our control;~~

●

~~the overall increase in the allocated management and operational expenses to our pipeline systems for services performed by TC Energy Corporation;~~

●

~~ability of our pipeline systems to renew rights-of-way at a reasonable cost; and~~

●

~~the level of our indebtedness, including the indebtedness of our pipeline systems, increase of interest rates, and the availability of capital.~~

•the ability of our pipeline systems to sell available capacity on favorable terms and renew expiring contracts which are affected by, among other factors:

▪demand for natural gas;

▪changes in relative cost structures and production levels of natural gas producing basins;

▪natural gas prices and regional differences;

▪weather conditions;

▪availability and location of natural gas supplies in Canada and the United States (U.S.) in relation to our pipeline systems;

▪competition from other pipeline systems;

▪natural gas storage levels;

▪rates and terms of service;

•the refusal or inability of our customers, shippers or counterparties to perform their contractual obligations with us, whether justified or not and whether due to financial constraints ( such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors;

•the outcome and frequency of rate proceedings or settlement negotiations on our pipeline systems;

•other potential changes in the taxation of master limited partnership (MLP) investments by state or federal governments such as the elimination of pass-through taxation or tax deferred distributions;

•increases in operational or compliance costs resulting from changes in laws and governmental regulations affecting our pipeline systems, particularly regulations issued by the Federal Energy Regulatory Commission (FERC), U.S. Environmental Protection Agency (EPA) and U.S. Department of Transportation (DOT);

•our ongoing ability to grow distributions through acquisitions, accretive expansions or other growth opportunities, including the timing, structure and closure of further potential acquisitions;

•potential conflicts of interest between TC PipeLines GP, Inc., our general partner (General Partner), TC Energy Corporation and us;

•failure of the Partnership or our pipeline systems to comply with debt covenants, some of which are beyond our control;

•the ability to maintain secure operation of our information technology including management of cybersecurity threats, acts of terrorism and related distractions;

•the implementation of future accounting changes and ultimate outcome of commitments and contingent liabilities, if any;

•the impact of any impairment charges;

•changes in political environment;

•operating hazards, casualty losses and other matters beyond our control;

•the overall increase in the allocated management and operational expenses to our pipeline systems for services performed by TC Energy Corporation;

~~Table~~•ability of ~~Contents~~our pipeline systems to renew rights-of-way at a reasonable cost;

•

the level of our indebtedness (including the indebtedness of our pipeline systems), increases in interest rates, our level of operating cash flows and the availability of capital;

•the impact of a potential slowdown in construction activities or a delay in the completion of our capital projects including increases in costs and availability of labor, equipment and materials;

•the impact of downward changes in oil and natural gas prices, including any effects on the creditworthiness of our shippers or the availability of associated gas in low oil price environment;

•the impact of litigation and other opposition proceedings on our ability to begin work on projects and the potential impact of an ultimate court or administrative ruling to a project schedule or viability; and

•uncertainty surrounding the impact of global health crises that reduce commercial and economic activity, including the COVID-19 pandemic, on our business.

These are not the only factors that could cause actual results to differ materially from those expressed or implied in any forward-looking statement. Other factors described elsewhere in this document, or factors that are unknown or unpredictable, could also have material adverse effects on future results. These and other risks are described in greater detail in Part II, Item 1A. “Risk Factors” of this report and in Part I, Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 (2019 Annual Report) as filed with the ~~SEC~~Securities and Exchange Commission (SEC) on February 21, ~~2019.~~2020. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. All forward-looking statements are made only as of the date made and except as required by applicable law, we undertake no obligation to update any forward-looking statements to reflect new information, subsequent events or other changes.

~~Table of Contents~~

PART I — FINANCIAL INFORMATION

Item 1.Financial Statements

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF INCOME

Three months ended

Nine months ended
(unaudited)

September 30,

September 30,
(millions of dollars, except per common unit amounts)

2019

2018

2019

2018
Transmission revenues

93

103

299

328
Equity earnings (Note 5)

31

34

115

129
Operation and maintenance expenses

(18)

(15)

(51)

(48)
Property taxes

(6)

(7)

(19)

(21)
General and administrative

(2)

(2)

(6)

(4)
Depreciation and amortization

(19)

(25)

(58)

(73)
Financial charges and other (Note 15)

(20)

(23)

(63)

(69)
Net income before taxes

59

65

217

242
Income taxes

—

—

(1)

(1)
Net income

59

65

216

241
Net income attributable to non-controlling interest

3

3

12

10
Net income attributable to controlling interests

56

62

204

231

Net income attributable to controlling interest allocation (Note 9)

Common units

54

57

199

222
General Partner

1

1

4

5
Class B units

1

4

1

4

56

62

204

231

Net income per common unit (Note 9) – basic and diluted

$
0.76

$
0.79

$
2.79

$
3.11
Weighted average common units outstanding – basic and diluted (millions)

71.3

71.3

71.3

71.3
Common units outstanding, end of period (millions)

71.3

71.3

71.3

71.3


	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars, except per common unit amounts)	2020	2019	2020	2019
Transmission revenues	95	93	196	206
Equity earnings (Note 5)	29	30	84	84
Operation and maintenance expenses	(16)	(17)	(32)	(33)
Property taxes	(7)	(6)	(13)	(13)
General and administrative	(2)	(2)	(3)	(4)
Depreciation and amortization	(19)	(19)	(39)	(39)
Financial charges and other (Note 15)	(18)	(21)	(37)	(43)
Net income before taxes	62	58	156	158
Income taxes	(1)	(1)	(1)	(1)
Net income	61	57	155	157
Net income attributable to non-controlling interest	4	2	10	9
Net income attributable to controlling interests	57	55	145	148
Net income attributable to controlling interest allocation (Note 9)
Common units	56	54	142	145
General Partner	1	1	3	3

	57	55	145	148

Net income per common unit (Note 9) — basic and diluted	$0.78	$0.75	$1.99	$2.03
Weighted average common units outstanding — basic and diluted (millions)	71.3	71.3	71.3	71.3
Common units outstanding, end of period (millions)	71.3	71.3	71.3	71.3

The accompanying notes are an integral part of these consolidated financial statements.

~~Table of Contents~~

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three months ended

Nine months ended
(unaudited)

September 30,

September 30,
(millions of dollars)

2019

2018

2019

2018
Net income

59

65

216

241
Other comprehensive income

Change in fair value of cash flow hedges (Note 13)

(1)

2

(15)

8
Amortization of realized loss on derivative financial instruments

—

—

—

2
Reclassification to net income of gains and losses on cash flow hedges

(2)

1

(1)

4
Comprehensive income

56

68

200

255
Comprehensive income attributable to non-controlling interests

3

2

12

11
Comprehensive income attributable to controlling interests

53

66

188

244


	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars)	2020	2019	2020	2019
Net income	61	57	155	157
Other comprehensive income
Change in fair value of cash flow hedges (Note 13)	(2)	(9)	(15)	(14)

Reclassification to net income of (gains) and losses on cash flow hedges (Note 13)	2	1	2	1
Comprehensive income	61	49	142	144
Comprehensive income attributable to non-controlling interests	4	2	10	9
Comprehensive income attributable to controlling interests	57	47	132	135

The accompanying notes are an integral part of these consolidated financial statements.

~~Table of Contents~~

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS


(unaudited)
(millions of dollars)	June 30, 2020	December 31, 2019
ASSETS
Current Assets
Cash and cash equivalents	215	83
Accounts receivable and other (Note 14)	34	43
Distribution receivable from Iroquois	—	14
Inventories	10	10
Other	3	6
	262	156
Equity investments (Note 5)	1,082	1,098
Property, plant and equipment (Net of $1,218 accumulated depreciation; 2019 - $1,187)	1,598	1,528
Goodwill	71	71

TOTAL ASSETS	3,013	2,853

LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	49	28
Accounts payable to affiliates (Note 12)	6	8
Accrued interest	10	11
Current portion of long-term debt (Note 7)	350	123
	415	170
Long-term debt, net (Note 7)	1,762	1,880
Deferred state income taxes	6	7
Other liabilities	43	36
	2,226	2,093
Partners’ Equity
Common units	593	544
Class B units (Note 8)	95	103
General partner	15	14
Accumulated other comprehensive income (loss) (AOCI)	(18)	(5)
Controlling interests	685	656
Non-controlling interests	102	104
	787	760
TOTAL LIABILITIES AND PARTNERS’ EQUITY	3,013	2,853

(unaudited)

(millions of dollars)

September 30, 2019

December 31, 2018
ASSETS

Current Assets

Cash and cash equivalents

90

33
Accounts receivable and other (Note 14)

39

48
Inventories

9

8
Other

2

8

140

97
Equity investments (Note 5)

1,094

1,196
Property, plant and equipment

(Net of $1,163 accumulated depreciation; 2018 - $1,110)

1,517

1,529
Goodwill

71

71
Other assets

—

6
TOTAL ASSETS

2,822

2,899

LIABILITIES AND PARTNERS' EQUITY

Current Liabilities

Accounts payable and accrued liabilities

31

36
Accounts payable to affiliates (Note 12)

6

6
Accrued interest

20

12
Current portion of long-term debt (Note 7)

123

36

180

90
Long-term debt, net (Note 7)

1,871

2,072
Deferred state income taxes

9

9
Other liabilities

36

29

2,096

2,200
Partners’ Equity

Common units

522

462
Class B units (Note 8)

96

108
General partner

14

13
Accumulated other comprehensive income (loss) (AOCI)

(8)

8
Controlling interests

624

591
Non-controlling interests

102

108

726

699
TOTAL LIABILITIES AND PARTNERS' EQUITY

2,822

2,899

Subsequent Events

~~Variable Interest Entities~~ (Note 16)

~~Subsequent Events~~ ~~(Note 17)~~

The accompanying notes are an integral part of these consolidated financial statements.

~~Table of Contents~~

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS

Nine months ended
(unaudited)

September 30,
(millions of dollars)

2019

2018
Cash Generated from Operations

Net income

216

241
Depreciation and amortization

58

73
Amortization of debt issue costs reported as interest expense

1

1
Amortization of realized losses

—

2
Equity earnings from equity investments (Note 5)

(115)

(129)
Distributions received from operating activities of equity investments (Note 5)

168

142
Change in other long-term liabilities

1

(1)
Equity allowance for funds used during construction (AFUDC equity)

(1)

—
Change in operating working capital (Note 11)

16

25

344

354
Investing Activities

Investment in Great Lakes (Note 5)

(5)

(4)
Investment in Iroquois (Note 5)

(4)

—
Distribution received from Iroquois as return of investment (Note 5)

8

8
Distribution received from Northern Border as return of investment (Note 5)

50

—
Capital expenditures

(48)

(28)

1

(24)
Financing Activities

Distributions paid to common units, including the General Partner (Note 10)

(142)

(171)
Distributions paid to Class B units (Note 8)

(13)

(15)
Distributions paid to non-controlling interests

(18)

(11)
Common unit issuance, net

—

40
Long-term debt issued, net of discount (Note 7)

21

159
Long-term debt repaid (Note 7)

(136)

(316)
Debt issuance costs

—

(1)

(288)

(315)
Increase in cash and cash equivalents

57

15
Cash and cash equivalents, beginning of period

33

33
Cash and cash equivalents, end of period

90

48


	Six months ended
(unaudited)	June 30,
(millions of dollars)	2020	2019
Cash Generated from Operations
Net income	155	157
Depreciation and amortization	39	39
Amortization of debt issue costs reported as interest expense	1	1

Equity earnings from equity investments (Note 5)	(84)	(84)
Distributions received from operating activities of equity investments (Note 5)	115	112
Equity allowance for funds used during construction	(3)	(1)
Change in operating working capital (Note 11)	6	4
Other	(1)	—
	228	228
Investing Activities
Investment in Great Lakes (Note 5)	(5)	(5)

Distribution received from Iroquois as return of investment (Note 5)	5	5
Distribution received from Northern Border as return of investment (Note 5)	—	50
Capital expenditures	(87)	(29)
Customer advances for construction	(1)	1
	(88)	22
Financing Activities
Distributions paid to common units, including the General Partner (Note 10)	(95)	(95)
Distributions paid to Class B units (Note 8)	(8)	(13)
Distributions paid to non-controlling interests	(12)	(15)

Long-term debt issued, net of discount (Note 7)	207	20
Long-term debt repaid (Note 7)	(100)	(135)

	(8)	(238)
Increase in cash and cash equivalents	132	12
Cash and cash equivalents, beginning of period	83	33
Cash and cash equivalents, end of period	215	45

The accompanying notes are an integral part of these consolidated financial statements.

~~Table of Contents~~

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY


	Limited Partners
	Common Units			Class B Units					General Partner	Accumulated Other Comprehensive Income(Loss) ^(a)	Non- Controlling Interest	Total Equity
(unaudited)	millions of units	millions of dollars	millions of units	millions of dollars	millions of dollars	millions of dollars	millions of dollars	millions of dollars
Partners’ Equity at December 31, 2019	71.3	544	1.9	103	14	(5)	104	760
Net income	—	142	—	—	3	—	10	155
Other comprehensive income (loss)	—	—	—	—	—	(13)	—	(13)
Distributions	—	(93)	—	(8)	(2)	—	(12)	(115)
Partners’ Equity at June 30, 2020	71.3	593	1.9	95	15	(18)	102	787

^(a)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 $(8) 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.

Accumulated

Other

Non-

Limited Partners

General

Comprehensive

Controlling

Total

Common Units

Class B Units

Partner

Income (Loss) ^(a)

Interest

Equity


millions

millions

millions

millions of

millions of

millions of

millions of

millions of
(unaudited)

of units

of dollars

of units

dollars

dollars

dollars

dollars

dollars
Partners' Equity at December 31, 2018

71.3

462

1.9

108

13

8

108

699
Net income

—

199

—

1

4

—

12

216
Other comprehensive income (loss)

—

—

—

—

—

(16)

—

(16)
Distributions (Note 10)

—

(139)

—

(13)

(3)

—

(18)

(173)
Partners' Equity at September 30, 2019

71.3

522

1.9

96

14

(8)

102

726

~~(a)~~

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 $3 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.

The accompanying notes are an integral part of these consolidated financial statements.

~~Table of Contents~~

TC PIPELINES, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1ORGANIZATION

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 (Intermediate GP) and 3 intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership. During the fourth quarter of 2019, the Partnership initiated the dissolution of the ILPs and Intermediate GP. Effective October 31, 2019, the Intermediate GP and ILPs transferred 100 percent of the ownership of their pipeline assets to the Partnership. As a result, the Partnership owns its pipeline assets directly which creates a more efficient partnership structure with no economic impact to the general and limited partners of the Partnership. The process of dissolving and unwinding is expected to be completed in the fourth quarter of 2019.

NOTE 2SIGNIFICANT 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 ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018~~2019 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~~2019 included in our 2019 Annual ~~Report on Form 10-K.~~Report. 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 2019 Annual Report, ~~on Form 10-K for the year ended December 31, 2018,~~ except those that became effective in 2020 as described in full under Note 3, ~~Accounting~~"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 limited partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its limited 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.

~~Table of Contents~~

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.

NOTE 3ACCOUNTING PRONOUNCEMENTS

Changes in Accounting Policies effective January 1, ~~2019~~

~~Leases~~

2020

Measurement of credit losses on financial instruments

In ~~February~~June 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

~~Table of Contents~~

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 $0.4 million at September 30, 2019. For the three and nine months ended September 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 ~~2.18 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 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 isbecame effective January 1, 2020 and ~~will be~~was applied using a modified retrospective approach. The ~~Partnership has substantially completed its analysis and does not expect the~~ adoption of this new guidance todid not have a material impact on ~~its~~the Partnership’s consolidated financial statements.

Consolidation

In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance isbecame effective January 1, 2020, and ~~will be~~was applied on a retrospective ~~basis, however early adoption is permitted.~~basis. The ~~Partnership does not expect the~~ adoption of this new guidance todid not have a material impact on ~~its~~the Partnership’s consolidated financial statements.

Reference rate reform

In March 2020, in response to the expected cessation of LIBOR, the FASB issued new optional guidance that eases the potential burden of accounting for reference rate reform. The new guidance provides optional expedients for contracts and hedging relationships that are affected by reference rate reform, if certain criteria are met. Each of the expedients can be applied as of January 1, 2020 through December 31, 2022. For eligible hedging relationships existing as of January 1, 2020 and prospectively, the Partnership has applied the optional expedient allowing an entity to assume that the hedged forecasted transaction in a cash flow hedge is probable of occurring. As reference rate reform is still an ongoing process, the Partnership will continue to evaluate the timing and potential impact of adoption of other optional expedients when deemed necessary.

NOTE 4 ~~REGULATORY~~

~~Iroquois,~~GOODWILL

Under U.S. GAAP, we evaluate our goodwill related to Tuscarora and ~~Northern Border took~~North Baja for impairment at least annually and if any indicators of impairment are evident.

In 2019, based on our analysis of Tuscarora and North Baja’s current market conditions, we believed there was a greater than 50 percent likelihood that Tuscarora and North Baja’s estimated fair value exceeded their carrying value. As a result, at December 31, 2019, we did not identify an impairment on the ~~actions listed below~~$71 million of goodwill related to ~~conclude~~ the ~~issues impacting their pipelines as contemplated by~~Tuscarora ($23 million) and North Baja ($48 million) reporting units.

On March 11, 2020, the ~~2017 Tax Act and certain FERC actions that began~~World Health Organization (WHO) declared COVID-19 a global pandemic. While there are continuing concerns around the decline 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 quantifiedenergy demand related to the ~~rate impact~~pandemic, we believe the current state of the ~~2017 Tax Act on FERC-regulated pipelines and~~macroeconomic environment does not represent a permanent shift. However, it is still difficult to predict with any certainty the severity of the impact of these events or how long any disruptions are likely to continue.

The following additional factors were considered in our analysis specific to the ~~Revised Policy Statement~~Partnership's Tuscarora and North Baja reporting units:

•the long-term natural gas price futures relevant to gas transported on ~~pipelines held by an MLP (collectively “2018 FERC Actions”).~~

Tuscarora and North Baja do not reflect material differences from what was forecast in 2019;

•

~~Iroquois~~

at least 90 percent of Tuscarora's and North Baja's revenue is tied to long-term take-or-pay, fixed-price contracts which have a low correlation to short-term changes in demand;

~~On February 28, 2019, Iroquois filed an uncontested settlement~~

•Tuscarora and North Baja have not experienced any material customer defaults to date and have significant collateral in support of their contracts;

•multiples and discount rate assumptions used in our quantitative model are reflective of the long-term outlook for Tuscarora and North Baja, in line with ~~FERC~~their underlying asset lives, versus the shorter-term nature of the current situation;

•Tuscarora's expansion project, Tuscarora XPress, is materially on track, and we do not anticipate any significant changes in outlook or delay or inability to ~~address~~proceed due to financing requirements; and

•Tuscarora and North Baja's businesses are broadly considered essential in the United States given the important role their infrastructures play in delivering energy to the market areas they serve.

As a result of these factors, we concluded during our first quarter 2020 analysis that there was a greater than 50 percent likelihood that both Tuscarora’s and North Baja’s estimated fair values would continue to exceed their carrying values. Therefore, no impairment exists on our goodwill. While the issues ~~contemplated by~~described above persist in the ~~2017 Tax Act~~current quarter, we continue to believe these conditions remain temporary and ~~2018 FERC Actions via an amendment~~are not aware of any other conditions or triggering events in the second quarter that would require us to ~~its prior 2016 settlement (2019 Iroquois Settlement). Among~~change the ~~terms of~~conclusion reached during the ~~2019 Iroquois Settlement, Iroquois agreed~~first quarter. Adverse changes to ~~reduce its existing maximum system rates by 6.5 percent to be implemented~~our key considerations could,however, result in 2 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

future impairments on our goodwill.

~~Table of Contents~~

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 2 percent rate reduction implemented on February 1, 2019 to July 1, 2024.

NOTE 5EQUITY 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 Federal Energy Regulatory Commission (FERC). The ~~pipeline systems of~~ Northern Border and Great Lakes pipeline systems 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

Nine months ended

(unaudited)

September 30,

September 30,

September 30,

September 30,

December 31,
(millions of dollars)

2019

2019

2018

2019

2018

2019

2018
Northern Border

50.00
%
15

16

50

49

426

497
Great Lakes

46.45
%
8

9

37

45

482

489
Iroquois

49.34
%
8

9

28

35

186

210

31

34

115

129

1,094

1,196

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) 2020 2020 2019 2020 2019 2020 2019
Northern Border 50.00% 13 14 35 35 412 422
Great Lakes 46.45% 9 9 29 29 489 491
Iroquois 49.34% 7 7 20 20 181 185
29 30 84 84 1,082 1,098

Distributions from Equity Investments

Distributions received from equity investments in the three and ~~nine~~six months ended ~~September~~June 30, ~~2019 were $59 million and $226 million, respectively (September 30, 2018 -~~2020 totaled $49 million and ~~$150~~$120 million, ~~respectively), of which $2.6~~respectively (June 30, 2019 - $108 million and ~~$57.8~~$167 million, respectively ~~(September~~).

During the six months ended June 30, ~~2018~~2020, $5 million of the total $120 million distributions received from equity investments (June 30, 2019 - ~~$2.6 million and $7.8 million, respectively)~~$55 million), ~~were~~was considered return of capital and included in ~~“Investing Activities”~~"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 ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, the Partnership received distributions from Northern Border amounting to ~~$21~~$18 million and ~~$121~~$45 million, respectively ~~(September~~(June 30, ~~2018~~2019 - ~~$21~~$72 million and ~~$60~~$100 million, respectively). The $121 million includes the Partnership’s 50 percent share of the Northern Border $100 million distribution in June 2019. The $100 million distribution was 100 percent financed by borrowing on Northern Border's $200 million revolving credit facility. The $50 million of cash the Partnership received did not represent a distribution of operating cash flow during the period and, therefore, it was reported as a return of investment in the Partnership’s consolidated statement of cash flows.

The Partnership did not have undistributed earnings from Northern Border for the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018.~~

2019.

~~Table of Contents~~

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

(unaudited)

(millions of dollars)

September 30, 2019

December 31, 2018
ASSETS

Cash and cash equivalents

38

10
Other current assets

34

36
Property, plant and equipment, net

1,000

1,037
Other assets

13

13

1,085

1,096

LIABILITIES AND PARTNERS’ EQUITY

Current liabilities

60

34
Deferred credits and other

37

35
Long-term debt, net ^(a)

365

264
Partners’ equity

Partners’ capital

624

764
Accumulated other comprehensive loss

(1)

(1)

1,085

1,096

Three months ended

Nine months ended
(unaudited)

September 30,

September 30,
(millions of dollars)

2019

2018

2019

2018
Transmission revenues

73

72

221

212
Operating expenses

(21)

(19)

(61)

(57)
Depreciation

(15)

(15)

(46)

(45)
Financial charges and other

(5)

(5)

(13)

(12)
Net income

32

33

101

98

~~(a)~~


(unaudited)
(millions of dollars)	June 30, 2020	December 31, 2019
ASSETS
Cash and cash equivalents	17	21
Other current assets	38	37
Property, plant and equipment, net	978	989
Other assets	12	12
	1,045	1,059
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	42	42
Deferred credits and other	41	39
Long-term debt, net ^(a)	369	364
Partners’ equity
Partners’ capital	594	615
Accumulated other comprehensive loss	(1)	(1)
	1,045	1,059


	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars)	2020	2019	2020	2019
Transmission revenues	66	67	149	148
Operating expenses	(19)	(20)	(39)	(40)
Depreciation	(16)	(16)	(31)	(31)
Financial charges and other	(5)	(4)	(9)	(8)
Net income	26	27	70	69

^(a)NaN current maturities as of June 30, 2020 and December 31, 2019. At June 30, 2020, Northern Border was in compliance with all its financial covenants.

~~NaN current maturities as of September 30, 2019 and December 31, 2018. At September 30, 2019, Northern Border was in compliance with all its financial covenants.~~

Great Lakes,

a variable interest entity

The Partnership is considered to have a variable interest in Great Lakes, which is accounted for as an equity investment as we are not its primary beneficiary. A variable interest entity is a legal entity that either does not have sufficient equity at risk to finance its activities without additional subordinated financial support, is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity.

The Partnership made an equity contribution to Great Lakes of $5 million induring the ~~first quarter of~~six months ended June 30, 2020 (June 30, 2019 ~~(September 30, 2018~~ - $4$5 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.

During the three and six months ended June 30, 2020, the Partnership received distributions from Great Lakes amounting to $21 million and $37 million, respectively (June 30, 2019 - $23 million and $39 million, respectively).

The Partnership did not have undistributed earnings from Great Lakes for the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018.~~

2019.

~~Table of Contents~~

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

(unaudited)

(millions of dollars)

September 30, 2019

December 31, 2018
ASSETS

Current assets

59

75
Property, plant and equipment, net

685

689

744

764

LIABILITIES AND PARTNERS’ EQUITY

Current liabilities

29

26
Net long-term debt, including current maturities ^(a)

229

240
Other long term liabilities

5

4
Partners' equity

481

494

744

764

Three months ended

Nine months ended
(unaudited)

September 30,

September 30,
(millions of dollars)

2019

2018

2019

2018

Transmission revenues

51

49

174

183
Operating expenses

(23)

(17)

(58)

(50)
Depreciation

(8)

(8)

(24)

(24)
Financial charges and other

(3)

(5)

(12)

(13)
Net income

17

19

80

96

~~(a)~~


(unaudited)
(millions of dollars)	June 30, 2020	December 31, 2019
ASSETS
Current assets	58	72
Property, plant and equipment, net	684	685
	742	757
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	34	33
Net long-term debt, including current maturities^(a)	208	219
Other long term liabilities	7	6
Partners’ equity	493	499
	742	757


	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars)	2020	2019	2020	2019
Transmission revenues	50	51	122	123
Operating expenses	(19)	(19)	(35)	(35)
Depreciation	(8)	(8)	(16)	(16)
Financial charges and other	(3)	(5)	(7)	(9)
Net income	20	19	64	63

^(a)Includes current maturities ~~of $21 million as of September 30, 2019 and as of December 31, 2018. At September 30, 2019, Great Lakes was in compliance with all its financial covenants.~~

~~Iroquois~~

~~The Partnership made an equity contribution to Iroquois~~ of $4$31 million as of June 30, 2020 (December 31, 2019 - $21 million). At June 30, 2020, Great Lakes was in ~~August 2019. This amount represents the Partnership’s 49.34 percent share of an $7 million cash call from~~ compliance with all its financial covenants.

Iroquois ~~to cover costs of regulatory approvals related to their capital project.~~

During the three and ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, the Partnership received distributions from Iroquois amounting to ~~$28~~$10 million and ~~$56~~$38 million, respectively ~~(September~~(June 30, ~~2018~~2019 - $14 million and ~~$42~~$28 million, respectively), which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately ~~$2.6~~NaN and $5.2 million, ~~and $7.8 million, respectively (September~~respectively. (June 30, ~~2018~~2019 - $2.6 million and ~~$7.8~~$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 third quarter 2019 distribution of $28 million on November 1, 2019, of which the Partnership will receive its 49.34 percent share or $14 million on December 30, 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 ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018.~~

2019.

~~Table of Contents~~

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


(unaudited)
(millions of dollars)	June 30, 2020	December 31, 2019
ASSETS
Cash and cash equivalents	35	43
Other current assets	72	36
Property, plant and equipment, net	513	570
Other assets	19	16
	639	665
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	14	34
Long-term debt, net^(a)	316	317
Other non-current liabilities	22	20
Partners’ equity	287	294
	639	665

(unaudited)

(millions of dollars)

September 30, 2019

December 31, 2018
ASSETS




Cash and cash equivalents

38

80
Other current assets

33

32
Property, plant and equipment, net

570

581
Other assets

14

8

655

701

LIABILITIES AND PARTNERS’ EQUITY

Current liabilities

21

19
Long-term debt, net ^(a)

320

325
Other non-current liabilities

20

14
Partners' equity

294

343

655

701

Three months ended

Nine months ended
(unaudited)

September 30,

September 30,
(millions of dollars)

2019

2018

2019

2018
Transmission revenues

39

42

131

147
Operating expenses

(15)

(13)

(43)

(41)
Depreciation

(7)

(7)

(22)

(22)
Financial charges and other

(2)

(4)

(9)

(11)
Net income

15

18

57

73

~~(a)~~


	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars)	2020	2019	2020	2019
Transmission revenues	41	40	93	92
Operating expenses	(14)	(13)	(29)	(28)
Depreciation	(7)	(8)	(15)	(15)
Financial charges and other	(6)	(4)	(9)	(7)
Net income	14	15	40	42

^(a) Includes current maturities of $4 million as of June 30, 2020 (December 31, 2019 - $3 million). At June 30, 2020, Iroquois was in compliance with all of its financial covenants.

~~Includes current maturities of $5 million as of September 30, 2019 (December 31, 2018 - $146 million). At September 30, 2019, Iroquois was in compliance with all its financial covenants.~~

NOTE 6REVENUES

Disaggregation of Revenues

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018,~~2019, 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 ~~September~~June 30, ~~2019,~~2020, 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.

~~Table of Contents~~

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 ~~$30~~$32 million at ~~September~~June 30, ~~2019~~2020 (December 31, ~~2018~~2019 - ~~$44~~$37 million) and are recorded as ~~Trade~~trade accounts receivable and reported as ~~“Accounts~~"Accounts receivable and ~~other”~~other" in the Partnership’s consolidated balance sheet (Refer to Note ~~14)~~14, "Accounts Receivable and Other").

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~~

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~~

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.

NOTE 7DEBT AND CREDIT FACILITIES

Weighted Average



Weighted Average

Interest Rate for the

Interest Rate for the
(unaudited)

Nine months ended

December 31,

Year Ended
(millions of dollars)

September 30, 2019

September 30, 2019

2018

December 31, 2018
TC PipeLines, LP

Senior Credit Facility due 2021

—

—

40

3.14
%

2013 Term Loan Facility due 2022

450

3.66
%

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

30

3.65
%

19

3.55
%

Tuscarora

Unsecured Term Loan due 2020

23

3.54
%

24

3.10
%

North Baja

Unsecured Term Loan due 2021

50

3.48
%

50

3.54
%

2,003

2,118

Less: unamortized debt issuance costs and debt discount

9

10

Less: current portion

123

36

1,871

2,072

~~(a)~~

~~Fixed interest rate~~


(unaudited) (millions of dollars)	June 30, 2020	Weighted Average Interest Rate for the Six Months Ended June 30, 2020		December 31, 2019	Weighted Average Interest Rate for the Year Ended December 31, 2019
TC PipeLines, LP
Senior Credit Facility due 2021	—	—		—	—
2013 Term Loan Facility due 2022	450	2.34%		450	3.52%
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
3.12% Series A Senior Notes due 2030	175	3.12%	^(a)	—	—
5.29% Unsecured Senior Notes due 2020	—	—	^(a)	100	5.29%	^(a)
5.69% Unsecured Senior Notes due 2035	150	5.69%	^(a)	150	5.69%	^(a)


PNGTS
Revolving Credit Facility due 2023	71	2.36%		39	3.47%

Tuscarora
Unsecured Term Loan due 2021	23	2.22%		23	3.39%

North Baja
Unsecured Term Loan due 2021	50	2.17%		50	3.34%
	2,119			2,012
Less: unamortized debt issuance costs and debt discount	7			9
Less: current portion ^(b)	350			123
	1,762			1,880

^(a) Fixed interest rate

^(b)~~Table of Contents~~ At June 30, 2020, this amount included TC PipeLines, LP's $350 million 4.65% Unsecured Senior Notes due in June 2021. At December 31, 2019, this amount included GTN's $100 million 5.29% Unsecured Senior Notes due in June 2020 and Tuscarora's $23 million Unsecured Term Loan that was due in August 2020.

TC PipeLines, LP

The Partnership’s ~~Senior~~senior facility under revolving credit agreement as amended and restated, dated September 29, 2017 (Senior Credit ~~Facility~~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 0 outstanding balance at ~~September~~either June 30, ~~2019 (December 31, 2018 - $40 million).~~

~~The LIBOR-based interest rate applicable to the Senior Credit Facility was 3.77 percent at~~2020 or 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. 2019.

As of ~~September~~June 30, ~~2019,~~2020, the variable interest rate exposure related to the ~~2013~~term loan facility under a term loan agreement, as amended, dated September 29, 2017 (2013 Term Loan ~~Facility~~Facility) was hedged using interest rate swaps at an average rate of 3.26 percent (December 31, ~~2018 –~~2019 - 3.26 percent). Prior to hedging activities, the ~~LIBOR-based~~London Interbank Offered Rate based (LIBOR) interest rate on the 2013 Term Loan Facility was ~~3.35~~1.42 percent at ~~September~~June 30, ~~2019~~2020 (December 31, ~~2018~~2019 - ~~3.60~~2.94 percent).

The Senior Credit Facility and the 2013 Term Loan Facility require the Partnership to maintain a debt to adjusted cash flow leverage ratio of no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions have been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was ~~2.79~~3.90 to 1.00 as of ~~September~~June 30, ~~2019.~~

2020.

GTN

On June 1, 2020, GTN’s $100 million 5.29% Unsecured Senior Notes became due and were refinanced through a Note Purchase and Private Shelf Agreement whereby GTN issued $175 million of 10-year Series A Senior Notes with a coupon of 3.12% per annum and entered into a 3-year private shelf agreement for an additional $75 million of Senior Notes (Private Shelf Facility). The new Series A Senior Notes do not require any principal payments until maturity on June 1, 2030. Proceeds from the Series A Senior Note issuance were used to repay the outstanding balance of the 5.29% Unsecured Senior Notes and the remaining proceeds will be used to fund the GTN XPress capital expenditures for the balance of 2020. GTN expects to draw the remaining $75 million available under the Private Shelf Facility by the end of 2023, the estimated completion date of GTN XPress. The Private Shelf Agreement and the Unsecured Senior Notes contain a covenant that limits total debt to no greater than 65 percent and 70 percent of GTN’s total ~~capitalization.~~capitalization, respectively. GTN’s total debt to total capitalization ratio at ~~September 30, 2019 was 39.8 percent.~~

~~During the three months ended~~ June 30, ~~2019, GTN's Unsecured Term Loan Facility matured and~~2020 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.~~

44.5 percent.

~~GTN's $100~~

PNGTS

PNGTS’ $125 million ~~5.29% Unsecured Senior Notes due June 1, 2020 are expected to be refinanced in full or at an amount based on the Partnership's preferred capitalization levels.~~

~~PNGTS~~

~~PNGTS’~~ Revolving Credit Facility requires PNGTS to maintain a leverage ratio ~~not~~of no greater than 5.00 to 1.00. The leverage ratio was ~~0.5~~1.15 to 1.00 as of ~~September~~June 30, ~~2019.~~

2020. During the six months ended June 30, 2020, PNGTS borrowed an additional $32 million on its Revolving Credit Facility to fund its expansion projects.

The LIBOR-based interest rate applicable to PNGTS’s Revolving Credit Facility was ~~3.35~~1.42 percent at ~~September~~June 30, ~~2019~~2020 (December 31, ~~2018~~2019 - ~~3.60~~2.99 percent).

Tuscarora

Tuscarora’s $23 million variable rate Unsecured Term Loan due August 21, 2020 (Unsecured Term Loan) contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by athe sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of ~~September~~June 30, ~~2019,~~2020, the ratio was ~~9.01~~9.14 to 1.00.

The LIBOR-based interest rate applicable to Tuscarora’s Unsecured Term Loan Facility was ~~3.23~~1.30 percent at ~~September~~June 30, ~~2019~~2020 (December 31, ~~2018~~2019 - ~~3.47~~2.82 percent).

On July 23, 2020, Tuscarora's ~~$23 million variable rate~~ Unsecured Term Loan ~~due~~was amended to extend the maturity date to August ~~21, 2020 is expected to be refinanced in full or at an amount based on~~20, 2021 under generally the ~~Partnership's preferred capitalization levels.~~

same terms.

~~Table of Contents~~

North Baja

North Baja’s $50 million 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 ~~September~~June 30, ~~2019~~2020 was ~~38.94~~40.50 percent.

The LIBOR-based interest rate applicable to North Baja’s Term Loan Facility was ~~3.18~~1.25 percent at ~~September~~June 30, ~~2019~~2020 (December 31, ~~2018~~2019 - ~~3.54~~2.77 percent).

Partnership ~~(TC PipeLines, LP and its subsidiaries)~~

At ~~September~~June 30, ~~2019,~~2020, the Partnership was in compliance with all terms and conditions including its financial covenants ~~in addition to the~~and its other covenants ~~which include~~including restrictions on entering into mergers, consolidations and sales of assets, granting of liens, material amendments to the Fourth Amended and Restated Agreement of Limited Partnership, as amended to date (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
2020			—
2021			423
2022			450
2023			71
2024			—
Thereafter			1,175
			2,119

(unaudited)

(millions of dollars)

Principal Payments
2019

—
2020

123
2021

400
2022

450
2023

30
Thereafter

1,000

2,003

NOTE 8PARTNERS’ EQUITY

~~ATM equity issuance program (ATM program)~~

~~During the nine months ended September 30, 2019, 0 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~~through March 31, ~~2019;~~2020 and (ii) 25 percent of distributions above $20 million thereafter, which equates to 43.75 percent of distributions above $20 million for the year ending December 31, ~~2020; and (iii) 25 percent of distributions above $20 million thereafter~~2020 (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 ending December 31, ~~2019,~~2020, 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.~~2021. During the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, the 2020 annual Class B ~~units' equity account was increased by $1 million after the 2019~~Distribution threshold was ~~exceeded and the estimated Class B Reduction for 2019 was applied.~~

not exceeded.

For the year ended December 31, ~~2018,~~2019, the Class B Distribution was ~~$13~~$8 million and was declared and paid in the first quarter of ~~2019.~~

2020.

~~Table of Contents~~

NOTE 9NET 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~~TC PipeLines GP., Inc. (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 2 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~~.

Agreement.

The amount allocable to the Class B units in ~~2019~~2020 will equal 30 percent of GTN’s distributable cash flow during the year ending December 31, ~~2019~~2020 less $20 million, ~~and~~the residual of which is further multiplied by 43.75 percent. This amount is further reduced by the estimated Class B Reduction for ~~2019~~2020, an approximately 35 percent reduction applied to the estimated annual Class B Distribution (December 31, ~~2018-$20~~2019 - $20 million less Class B Reduction). During the three and ~~nine~~six months ended ~~September~~June 30, 2020 and 2019, ~~$1 million was~~no amounts were allocated to the Class B units ~~(September 30, 2018 - $4 million).~~

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)	2020	2019	2020	2019
Net income attributable to controlling interests	57	55	145	148


Net income attributable to the General Partner	(1)	(1)	(3)	(3)
Net income attributable to common units	56	54	142	145
Weighted average common units outstanding (millions) — basic and diluted	71.3	71.3	71.3	71.3
Net income per common unit — basic and diluted	$0.78	$0.75	$1.99	$2.03

(unaudited)

Three months ended September 30,

Nine months ended September 30,
(millions of dollars, except per common unit amounts)

2019

2018

2019

2018
Net income attributable to controlling interests

56

62

204

231
Net income attributable to the Class B units^(a)

(1)

(4)

(1)

(4)
Net income attributable to the General Partner and common units

55

58

203

227
Net income attributable to the General Partner

(1)

(1)

(4)

(5)
Net income attributable to common units

54

57

199

222
Weighted average common units outstanding (millions) – basic and diluted

71.3

71.3

71.3

71.3
Net income per common unit – basic and diluted

$
0.76

$
0.79

$
2.79

$
3.11

^(a) During the nine months ended September 30, 2019, 30 percent of GTN’s total distributable cash flow was $25 million. After applying the $20 million annual threshold and the estimated Class B Reduction for 2019, $1 million of net income attributable to controlling interests was allocated to the Class B units for both the three and nine months ended September 30, 2019. During the nine months ended September 30, 2018, 30 percent of GTN’s total distributable cash flow was $31 million. After applying the $20 million annual threshold and the estimated Class B Reduction for 2018, $1 million of net income attributable to controlling interests was allocated to the Class B units for both the three and nine months ended September 30, 2018 (Refer to Note 8).

NOTE 10 CASH DISTRIBUTIONS PAID TO COMMON UNITS

~~2019~~

During both the three and ~~nine~~six months ended ~~September~~June 30, 2020 and 2019, the Partnership distributed $0.65 and ~~$1.95~~$1.30 per common unit, respectively for a total distribution of $47 million and ~~$142~~$95 million, respectively.

The total distribution paid ~~above~~ includes our General ~~Partner’s~~Partner's share ~~during the three and nine months ended September 30, 2019~~ for its 2 percent general partner interest ~~which was~~for both the three and six months ended June 30, 2020 and 2019 totaling $1 million and $3$2 million,respectively. The General Partner did not receive any

distributions in respect of its ~~IDRs during~~Incentive Distribution Rights (IDRs) in either of the three ~~and nine~~or six months ended ~~September~~June 30, ~~2019.~~

~~2018~~

~~During the three~~2020 and ~~nine months ended September 30, 2018, the Partnership distributed $0.65 and $2.30 per common unit, respectively, for a total of $47 million and $171 million, respectively.~~

The total distribution paid above includes our General Partner’s share during the three and nine months ended September 30, 2018, which totaled $1 million and $7 million, respectively. During the three and nine months ended September 30, 2018 the 2 percent general partner interest totaled $1 million and $4 million, respectively. The distributions paid to our General Partner in respect of IDRs during the three and nine months ended September 30, 2018 were NaN and $3 million, respectively.

2019.

~~Table of Contents~~

NOTE 11 CHANGE IN OPERATING WORKING CAPITAL


(unaudited)	Six months ended June 30,
(millions of dollars)	2020	2019
Change in accounts receivable and other ^(a)	6	15
Change in inventories	—	(1)
Change in other current assets	3	3
Change in accounts payable and accrued liabilities ^(a)	—	(12)
Change in accounts payable to affiliates	(2)	—
Change in accrued interest	(1)	(1)
Change in operating working capital	6	4

^(a)

(unaudited)

Nine months ended September 30,
(millions of dollars)

2019

2018
Change in accounts receivable and other ^(a)

16

3
Change in inventories

(1)

—
Change in other current assets

4

1
Change in accounts payable and accrued liabilities^(a)

(11)

13
Change in accrued interest

8

8
Change in operating working capital

16

25

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

~~(a)~~

~~Excludes certain non-cash items primarily related to capital accruals and credits.~~

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 ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018,~~2019, total costs charged to the Partnership by the General Partner were $1 million and $3$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)5, "Equity Investments").

Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2019~~2020 and ~~2018~~2019 by TC Energy’s subsidiaries and amounts payable to TC Energy’s subsidiaries at ~~September~~June 30, ~~2019~~2020 and December 31, ~~2018~~2019 are summarized in the following tables:

Three months ended

Nine months ended
(unaudited)

September 30,

September 30,
(millions of dollars)

2019

2018

2019

2018
Capital and operating costs charged by TC Energy’s subsidiaries to:

Great Lakes ^(a)

12

9

35

34
Northern Border ^(a)

10

8

29

26
GTN

11

8

32

25
Bison

1

2

2

5
North Baja

1

1

4

3
Tuscarora

1

1

3

3
PNGTS ^(a)

2

2

5

7
Impact on the Partnership’s income ^(b):

Great Lakes

4

4

14

14
Northern Border

4

4

13

12
GTN

9

7

25

21
Bison

—

2

1

5
North Baja

1

1

3

3
Tuscarora

1

1

3

3
PNGTS ^(b)

1

1

3

4


	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars)	2020	2019	2020	2019
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes^(a)	11	12	22	23
Northern Border^(a)	10	10	20	19
GTN	12	11	24	21
Bison	1	—	1	1
North Baja	1	2	2	3
Tuscarora	1	1	2	2
PNGTS^(a)	1	1	3	3
Impact on the Partnership’s income ^(b):
Great Lakes	5	5	9	10
Northern Border	4	5	8	9
GTN	7	8	15	16
Bison	1	—	1	1
North Baja	1	1	2	2
Tuscarora	1	1	2	2
PNGTS	1	1	2	2


(unaudited)
(millions of dollars)	June 30, 2020	December 31, 2019
Net amounts payable to TC Energy’s subsidiaries are as follows:
Great Lakes^(a)	4	5
Northern Border^(a)	4	4
GTN	4	5
Bison	—	—
North Baja	—	1
Tuscarora	—	—
PNGTS^(a)	1	1

^(a)~~Table~~Represents 100 percent of ~~Contents~~the costs.

(unaudited)

(millions of dollars)

September 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

^(b)Represents the Partnership's proportionate share based ownership percentage of these pipelines.

~~(a)~~

~~Represents 100 percent of the costs.~~

~~(b)~~

~~Represents the Partnership's proportionate share based ownership percentage of these pipelines~~

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 ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, Great Lakes earned 7375 percent and 74 percent, respectively of its transportation revenues from TC Energy and its affiliates ~~(September~~(June 30, ~~2018~~2019 - 7673 percent ~~and 71 percent, respectively)~~for both periods).

At ~~September~~June 30, ~~2019,~~2020, $13 million was included in Great Lakes’ receivables with regard to the transportation contracts with TC Energy and its affiliates (December 31, ~~2018~~2019 - ~~$18~~$19 million).

~~During the second quarter of~~

In 2018, Great Lakes ~~reached an agreement on the terms of new~~executed long-term transportation capacity contracts with its affiliate, ANR Pipeline ~~Company.~~Company (ANR) in anticipation of specific possible future needs. The ~~contracts are for a term of 15 years from November 2021 to October 31, 2036 with a~~original total contract value of these contracts was approximately $1.3 billion over a 15-year period. These contracts were subject to certain conditions and provisions, including a reduction option up to the full contract quantity if exercised up to a certain date. During the first quarter of 2020, several amendments were made to these contracts and ANR exercised the right to terminate a significant portion of the contracts amounting to approximately $1.1 billion. The ~~contracts contain~~remaining maximum rate contract, which has a total capacity of approximately 168,000 Dth/Day and total contract value of $182 million over a term of 20 years, is expected to begin in late 2022. This contract, which has a full quantity reduction ~~options (i)~~option at any time before October 1, 2022, is dependent on ~~or before April 1, 2019 for any reason and (ii) any time before April 2021, if TC Energy is not~~ANR being able to secure the required regulatory ~~approval related to anticipated expansion projects. During~~approvals and other requirements of the ~~first quarter of 2019,~~project associated with these volumes. Any remaining unsubscribed capacity on Great Lakes ~~reached an agreement~~will be available for contracting in response 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.~~

developing marketing conditions.

PNGTS

In connection with the Portland XPress expansion project (PXP), which was designed to be phased in over a three year time period, PNGTS has entered into an arrangement with ~~its~~ affiliates regarding the construction of certain facilities on their systems that ~~will be~~are required to fulfill future contracts on the PNGTS system. PXP Phases I and II were placed into service on November 1, 2018 and November 1, 2019, respectively. Phase III is ~~estimated~~anticipated to be in service on November 1, 2020. In the event the expansions ~~terminate~~are terminated prior to their in-service dates, PNGTS will be required to reimburse its affiliates for any costs incurred related to the development of ~~these~~their facilities. ~~At September 30, 2019, the total costs incurred by these affiliates was approximately $134 million, NaN of which amount related to Phase III costs.~~ As a result of placing the TC Energy facilities associated with the Phase II volumes in service, PNGTS' obligation ~~to reimburse most of these development costs with respect to~~for Phase II ~~terminated.~~

~~Going forward, the PNGTS will only be obligated~~costs has been extinguished. PNGTS' remaining potential obligation to reimburse costs incurred by TC Energy in relation to Phase III, which was ~~NaN~~approximately $3.8 million at ~~September~~June 30, ~~2019~~2020 and estimated to be approximately ~~$7.2~~$9.1 million by November 1, 2020, will be terminated when Phase III goes into service.

NOTE 13 FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

Under Accounting Standards Codification (ASC) 820, Fair Value Measurements andDisclosures, fair value measurements are characterized in one of three levels based upon the inputs used to arrive at the measurement. The three levels of the fair value hierarchy are as follows:

●

~~Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.~~

•Level 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.

~~Table of Contents~~•

Level 3 inputs are unobservable inputs for the asset or liability.

●

~~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~~"cash and cash ~~equivalents”, “accounts~~equivalents,""accounts receivable and ~~other”, ”accounts~~other,""accounts payable and accrued ~~liabilities”, “accounts~~liabilities,""accounts payable to ~~affiliates”~~affiliates" and ~~“accrued interest”~~"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 ~~September~~June 30, ~~2019~~2020 and December 31, ~~2018~~2019 was ~~$2,100~~$2,223 million and ~~$2,101~~$2,111 million, respectively.

Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. The Partnership’s floating rate debt is subject to LIBOR benchmark interest rate risk. The Partnership uses 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~~2022. The interest rate swaps were 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

At June 26, 2019, in conjunction with the Partnership’s $50 million repayment on its 2013 Term Loan Facility, the Partnership also terminated an equivalent amount in interest rate swaps that were used to hedge this facility at an unwind rate of 2.81 percent (See also Note 7).

~~At September~~ 30, ~~2019,~~2020, the fair value of the interest rate swaps accounted for as cash flow hedges was a liabilityof $8$19 million (both on a gross and net basis) (December 31, ~~2018~~2019 - ~~asset~~liability of $8$6 million), the net change of which is recognized in other comprehensive income. For both the three and ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, the net realized ~~gain~~loss related to the interest rate swaps was ~~NaN and $1~~$2 million ~~respectively,~~ and was included in "financial charges and other" ~~(September~~(June 30, ~~2018~~2019 - gain of NaN and gain of $2$1 million, respectively) (Refer to Note ~~15)~~15, "Financial Charges and Other').

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 ~~September~~June 30, ~~2019~~2020 and December 31, ~~2018.~~

2019.

NOTE 14 ACCOUNTS RECEIVABLE AND OTHER

(unaudited)

(millions of dollars)

September 30, 2019

December 31, 2018
Trade accounts receivable, net of allowance of nil

30

44
Imbalance receivable from affiliates

—

2
Other

9

2

39

48


(unaudited)
(millions of dollars)	June 30, 2020	December 31, 2019
Trade accounts receivable, net of allowance of nil	32	37

Other	2	6
	34	43

~~Table of Contents~~

NOTE 15 FINANCIAL CHARGES AND OTHER

Three months ended

Nine months ended
(unaudited)

September 30,

September 30,
(millions of dollars)

2019

2018

2019

2018
Interest expense ^(a)

22

23

67

71
PNGTS' amortization of loss on derivative instruments

—

—

—

2
Net realized gain related to the interest rate swaps

—

—

(1)

(2)
Other income

(2)

—

(3)

(2)

20

23

63

69

~~(a)~~


	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars)	2020	2019	2020	2019
Interest expense^(a)	20	22	40	45
Net realized loss (gain) related to the interest rate swaps	2	—	2	(1)
Other income	(4)	(1)	(5)	(1)
	18	21	37	43

^(a)Includes amortization of debt issuance costs and discount costs.

~~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 VIE’s 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 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

~~Table of Contents~~

~~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)

September 30, 2019

December 31, 2018
ASSETS (LIABILITIES) ^(a)

Cash and cash equivalents

17

16
Accounts receivable and other

35

39
Inventories

9

8
Other current assets

2

6
Equity investments

1,094

1,196
Property, plant and equipment, net

1,241

1,240
Other assets

1

1
Accounts payable and accrued liabilities

(26)

(33)
Accounts payable to affiliates, net

(86)

(40)
Accrued interest

(5)

(2)
Current portion of long-term debt

(123)

(36)
Long-term debt

(229)

(341)
Other liabilities

(29)

(27)
Deferred state income tax

(9)

(9)

~~(a)~~

Bison, an asset held through our consolidated VIEs, is excluded at September 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.

NOTE 1716 SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through ~~November 7, 2019,~~August 5, 2020, 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 ~~October 22, 2019,~~July 23, 2020, the board of directors of the General Partner declared the Partnership’s ~~third~~second quarter ~~2019~~2020 cash distribution in the amount of $0.65 per common unit payable on ~~November~~August 14, ~~2019~~2020 to unitholders of record as of ~~November 1, 2019.~~August 3, 2020. 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 2 percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the ~~third~~second quarter of ~~2019.~~

2020.

Northern Border declared its ~~September 2019~~June 2020 distribution of ~~$15~~$11 million on ~~October~~July 9 ~~2019,~~2020, of which the Partnership received its 50 percent share or $7$5 million on ~~October 18, 2019.~~

July 31, 2020.

Great Lakes declared its ~~third~~second quarter ~~2019~~2020 distribution of ~~$23~~$24 million on ~~October~~July 15, ~~2019,~~2020, of which the Partnership received its 46.45 percent share or $11 million on ~~October 18, 2019.~~

July 31, 2020.

Iroquois declared its ~~third~~second quarter ~~2019~~2020 distribution of ~~$28~~$21 million on ~~November 1, 2019,~~August 4, 2020, of which the Partnership will receive its 49.34 percent share or $10 million on September 29, 2020.

PNGTS declared its second quarter 2020 distribution of $14 million on ~~December 30, 2019.~~

~~PNGTS declared its third quarter 2019 distribution of $10 million on October 9, 2019,~~July 8, 2020, of which $4$5 million was paid to its non-controlling interest owner on ~~October 18, 2019.~~

July 31, 2020.

On August 1, 2020, GTN, Great Lakes, Tuscarora and North Baja entered into a purchase agreement with a TC Energy affiliate to purchase an internally developed customer-facing commercial natural gas transmission IT application that maintains and manages customer contracts, natural gas capacity release, customer nominations, metering and billings. The total value of the transaction was $51 million and the Partnership's proportionate share of the cost was $38 million. Prior to the transaction close, GTN, Great Lakes, Tuscarora and North Baja paid the affiliate for the use of this system and the costs are included in the "Impact on Partnership's income" tabular summary under Note 12.

~~Table of Contents~~

Item 2. ~~Management's~~Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and notes included in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q, as well as our 2019 Annual ~~Report~~Report.

RECENT BUSINESS DEVELOPMENTS

OUTLOOK

On March 11, 2020, the WHO declared COVID-19, a global pandemic. As primary operator of our pipelines, TC Energy’s business continuity plans remain in place across the organization and TC Energy continues to effectively operate our assets, conduct commercial activities and execute on ~~Form 10-K~~projects with a focus on health, safety and reliability. Our business is broadly considered essential in the United States given the important role our infrastructure plays in providing energy to North American markets. We believe that TC Energy’s robust continuity and business resumption plans for critical teams including gas control and commercial and field operations, will continue to ensure the safe and reliable delivery of energy that our customers depend upon. We anticipate that changes to work practices and other restrictions put in place by government and health authorities in response to the COVID-19 pandemic will have an impact on certain projects. While we generally believe this will not be material to our operations, we also recognize that the ultimate impact remains uncertain at this time.

Our pipeline assets are largely backed by long-term, take-or-pay contracts resulting in revenues that are materially insulated from short-term volatility associated with fluctuations in volume throughput and commodity prices. More importantly, a significant portion of our long-term contract revenue is with investment-grade customers and we have not experienced any material collection issues on our receivables to date. Aside from the impact of maintenance activities and normal seasonal factors, to date we have not seen any material changes in the utilization of our assets. Additionally, to date, we have not experienced any significant impacts on our supply chain. While it is too early to ascertain any long-term impact that the COVID-19 pandemic may have on our capital growth program, we note that we could experience some delay in construction and other related activities.

Capital market conditions in 2020 have been significantly impacted by COVID-19 resulting in periods of extreme volatility and reduced liquidity. Despite these challenges, our liquidity remains strong, underpinned by stable cashflow from operations, cash on hand and full access to our $500 million Senior Credit Facility. During the second quarter of 2020, GTN's $100 million Senior Notes due in June 2020 were refinanced through a Note Purchase Agreement whereby GTN issued $175 million of 10-year Series A Senior Notes with the incremental $75 million of proceeds to be used to fund the GTN XPress project through the balance of 2020. Additionally, GTN entered into a 3-year Private Shelf Agreement for an additional $75 million which will be used to finance a portion of the GTN XPress project into 2023. This refinancing demonstrates our continued access to the debt capital markets at attractive levels. Additionally, on July 23, 2020, we extended Tuscarora's $23 million Unsecured Term Loan due in August 2020 for one year to August 2021 under generally the same terms. PNGTS is also working on increasing its borrowing capacity to accommodate the financing required for the ~~year ended December~~balance of both the PXP and Westbrook XPress projects. We continue to conservatively manage our financial position, self-fund our ongoing capital expenditures and maintain our debt at prudent levels and we believe we are well positioned to fund our obligations through a prolonged period of disruption, should it occur. Based on current expectations, we believe our business will continue to deliver consistent financial performance going forward and support our current quarterly distribution level of $0.65 per common unit.

The full extent and lasting impact of the COVID-19 pandemic on the global economy is uncertain but to date has included extreme volatility in financial markets and commodity prices, a significant reduction in overall economic activity and widespread extended shutdowns of businesses along with supply chain disruptions. The degree to which COVID-19 has a more significant impact on our operations and growth projects will depend on future developments, policies and actions which remain highly uncertain. Additional information regarding risks and impacts on our business can be found throughout this section, including Item 3 - "Quantitative and Qualitative Disclosures About Market Risk" and Part II-Item 1A - "Risk Factors."

Impairment considerations:

Consistent with GAAP, we evaluate our goodwill related to Tuscarora and North Baja for impairment at least annually to determine if any indicators of impairment are evident. Our long-lived assets and equity investments in Northern Border, Great Lakes and Iroquois, including intangible assets with finite useful lives, are evaluated whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

We believe the current state of the macroeconomic environment described above does not represent a permanent shift although it is difficult to predict the severity of the impact of these events or how long any disruptions are likely to continue. Additionally, the following factors were considered in our analysis specific to the Partnership:

•the long-term natural gas price futures relevant to gas transported on our pipelines do not reflect material differences from what was forecast in 2019;

•a significant amount of our pipeline assets’ revenue is tied to long-term take-or-pay, fixed-price contracts which have a low correlation to short-term changes in demand;

•we have not experienced any material customer defaults to date and we have significant collateral supporting our contracts;

•multiples and discount rate assumptions used in our quantitative models are reflective of the long-term outlook for our assets, in line with their underlying asset life, versus the shorter-term nature of the current situation;

•while we may experience a slowdown in some of our construction activities, our current growth projects are materially on track, and we do not anticipate any significant changes in outlook, delays or inability to proceed due to financing requirements; and

•Our businesses are broadly considered essential in the United States given the important role these pipeline infrastructure assets play in delivering energy to the market areas we serve.

While the issues described above persist in the current quarter, we continue to believe these conditions remain temporary and as a result, we continue to believe no impairment exists on our goodwill, equity investments or long-lived assets. However, future adverse changes to our key considerations could change our conclusion.

Other notable business developments:

PNGTS’ Portland XPress Project- Phases I and II of this project are in service, and on March 5, 2020, FERC granted PNGTS’ request to begin construction of Phase III of the project. Construction activities are in progress and PXP is currently on track to be fully in service on November 1, 2020. Once fully in service, all three phases of PXP in aggregate are expected to generate approximately $50 million of annual revenue for PNGTS.

PNGTS’ Westbrook XPress Project- Phase I of this project is in service, and on June 18, 2020, FERC issued a certificate of public convenience and necessity for this project. Phases II and III have estimated in-service dates of November 2021 and 2022, respectively. Once fully in service, all three phases of Westbrook XPress in aggregate are expected to generate approximately $35 million of annual revenue for PNGTS.

ANR's Alberta XPress project-On February 12, 2020, TC Energy approved the Alberta XPress project, an expansion project on its ANR Pipeline system with an estimated in-service date of 2022. This project utilizes existing capacity on our Great Lakes and TC Energy’s Canadian Mainline systems to connect growing natural gas supply from the Western Canadian Sedimentary Basin (WCSB) to U.S. Gulf Coast Liquified Natural Gas (LNG) export markets. In 2018, Great Lakes entered into long-term transportation capacity contracts with ANR for approximately 900,000 Dth/day of aggregate capacity for a term of 15 years. In connection with the approval of the Alberta XPress project, such contracts have been reduced to provide for approximately 168,000 Dth/day of aggregate capacity for a term of 20 years at maximum rates for a total contract value of $182 million starting in 2022. The contract contains reduction options (i) at any time on or before October 1, 2022 for any reason and (ii) at any time, if ANR is not able to secure the required regulatory approval related to its anticipated expansion projects. Please read Note 12 within Item 1. “Financial Statements” for information regarding Great Lakes and ANR.

Northern Border complaint - On March 31, ~~2018.~~

~~RECENT BUSINESS DEVELOPMENTS~~

~~Cash Distributions~~

2020, BP Canada Energy Marketing Corp., Oasis Petroleum Marketing LLC and Tenaska Marketing Ventures (the “Alliance for Open Markets”) filed a complaint with FERC (Docket No. RP20-745-000) against Northern Border Pipeline Company alleging that Northern Border violated Sections 4 and 5 of the Natural Gas Act, FERC policy and other regulations by (i) failing to post capacity as available on a long-term basis before entering into a prearranged transaction for six agreements with ONEOK Rockies Midstream, L.L.C.; and (ii) structuring the prearranged transaction open season in a manner that denied other shippers a meaningful opportunity to bid on the capacity. On April 2, 2020, ConocoPhillips Company, Shell Energy North America (US), L.P. and XTO

Energy Inc. (the “Indicated Shippers”, together with the Alliance for Open Markets, the “Complainants”) filed a second complaint with FERC (Docket No. RP20-767-000) against Northern Border containing similar allegations regarding the prearranged transaction open season. The Complainants have requested that FERC (a) unwind the six prearranged contracts; (b) require Northern Border to hold an open season for the capacity such that all interested parties are on equal footing; and (c) direct Northern Border to cease from engaging in prearranged transactions where the unsubscribed capacity has not been publicly posted as generally available.

The prearranged contracts range in volume from 40,000 to 269,732 Dth/day for terms ranging from 10 months to 10 years, two of which were scheduled to begin June 1, 2020. Northern Border filed a motion to consolidate the two complaint dockets and filed its response to the complaints on May 1, 2020.

On June 1,2020 updated tariff sheets reflecting the contract price were filed by Northern Border with FERC for the two contracts set to begin June 1, 2020. On July 1, 2020, FERC issued an order and accepted the tariff sheets, subject to the outcome of complaint proceedings.

Great Lakes 501-G Proceeding-On May 11, 2020, FERC terminated Great Lakes’ 501-G proceeding and ruled that Great Lakes has complied with the one-time reporting requirement, designated as FERC Form No. 501-G related to the rate effect of Tax Act and Jobs Act. Additionally, FERC also stated that rate reductions provided for in its 2017 settlement and the 2.0% rate reduction from the Limited Section 4 Rate Reduction proceeding have provided substantial rate relief for Great Lakes’ shippers and as a result, it will not exercise its right to institute a Natural Gas Act Section 5 investigation to determine if Great Lakes is over-recovering on its current tariff rates.

Great Lakes' Credit Rating upgrade - On June 21, 2020, Standard & Poor's (S&P) upgraded Great Lakes' credit rating by two-notches from BBB-/Stable to BBB+/Stable primarily due to an improvement in Great Lakes' financial risk profile resulting from its increased long-term contracting levels.

PNGTS Credit Rating upgrade - On July 24, 2020, Fitch upgraded PNGTS' credit rating by one-notch from BBB/Stable to BBB+/Stable primarily due to an improvement in PNGTS' financial risk profile resulting from placing is PXP Phase II project in-service on November 1, 2019.

GTN financing - On June 1, 2020, GTN’s $100 million 5.29 percent Senior Notes matured and were refinanced through a Note Purchase and Private Shelf Agreement whereby GTN issued $175 million of 10-year Series A Senior Notes with a fixed rate coupon of 3.12 percent per annum and entered into a 3-year Private Shelf Facility for an additional $75 million. The new Series A Senior Notes do not require any principal payments until maturity on June 1, 2030. Proceeds from the Series A Senior Note issuance were used to repay the outstanding balance of the 5.29 percent Senior Notes and to fund the GTN XPress capital expenditures through the balance of 2020. GTN expects to draw the remaining $75 million available under the Private Shelf Facility by the end of 2023, the estimated completion date of GTN XPress. The Private Shelf Agreement contains a covenant that limits total debt to no greater than 65 percent of GTN’s total capitalization.

Tuscarora financing- On July 23, 2020, Tuscarora's $23 million Unsecured Term Loan due August 21, 2020, was amended to extend the maturity date to August 20, 2021 under generally the same terms.

Commercial system purchase- On August 1, 2020, GTN, Great Lakes, Tuscarora and North Baja entered into a purchase agreement with a TC Energy affiliate to purchase an internally developed customer-facing commercial natural gas transmission IT application that maintains and manages customer contracts, natural gas capacity release, customer nominations, metering and billings. The total value of the transaction was $51 million and the Partnership's proportionate share of the cost was $38 million. Prior to the transaction close, GTN, Great Lakes, Tuscarora and North Baja paid the affiliate for the use of this system. As a result of the capital purchase, the amount paid by each pipeline will be added to its respective rate base and utilized in the calculation of maximum allowable rates.

Pacific Gas and Electric Company- In early 2019, GTN’s largest customer, Pacific Gas and Electric Company (Pacific Gas), filed for Chapter 11 bankruptcy protection. Pacific Gas accounts for less than 10 percent Partnership’s consolidated revenues in 2019. On July 1, 2020, Pacific Gas emerged from its bankruptcy proceedings. To date, GTN

has not experienced any collection issues on its receivable from Pacific Gas and we continue to expect this going forward during the duration of its contracts with GTN.

Cash Distributions to Common Units and our General Partner

On April 21, 2020, the board of directors of our General Partner declared the ~~Partnership's~~Partnership’s first quarter ~~2019~~2020 cash distribution in the amount of $0.65 per common unit, ~~which was paid~~payable on May ~~13, 2019~~12, 2020 to unitholders of record as of May ~~3, 2019.~~1, 2020. The declared distribution totaled $47 million and was 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 a holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest.

On July 23, ~~2019,~~2020, the board of directors of our General Partner declared the Partnership’s second quarter ~~2019~~2020 cash distribution in the amount of $0.65 per common unit, ~~which was paid~~payable on August 14, ~~2019~~2020 to unitholders of record as of August ~~2, 2019.~~3, 2020. The declared distribution totaled $47 million and was 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 a holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest.

On October 22, 2019, the board of directors of our General Partner declared the Partnership’s third quarter 2019 cash distribution in the amount of $0.65 per common unit, payable on November 14, 2019 to unitholders of record as of November 1, 2019. The declared distribution totaled $47 million and was 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 our General Partner for its two percent general partner interest.

~~The General Partner did not receive any distributions in respect of its IDRs in 2019 year-to-date.~~

~~2018 FERC Actions Updates from our 2018 Annual Report on Form 10-K:~~

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 the 2018 FERC Actions. FERC has now closed all 501-G dockets for our pipeline systems with the exception of Great Lakes.

~~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. 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 by 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. 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 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 ADIT for rate-making purposes.

~~Northern Border settlement~~ - 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,

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~~effective January 1, 2020, the amended settlement agreement extends the two percent rate reduction implemented on February 1, 2019 to July 1, 2024.~~

~~Financing Updates:~~

~~Northern Border~~- In June 2019, Northern Border borrowed an additional $100 million under its $200 million revolving credit facility to finance a cash distribution of $100 million, of which $50 million was received by the Partnership. Northern Border's outstanding balance under this facility amounted to $115 million at September 30, 2019.

~~Iroquois Financing~~ - On May 9, 2019, Iroquois refinanced its 6.63% $140 million and 4.84% $150 million Senior Notes due in 2019 and 2020, respectively, by issuing new 15-year 4.12% $140 million and new 10-year 4.07% $150 million Senior Notes. The debt covenants requiring Iroquois to maintain a debt to capitalization ratio below 75 percent and a debt service coverage ratio of at least 1.25 times for the four preceding quarters are unchanged from those governing the refinanced Senior Notes.

~~Partnership’s 2013 $500 Million Term Loan Facility~~ - In June 2019, the Partnership repaid $50 million of outstanding borrowings under its 2013 $500 Million Term Loan Facility using the proceeds received from the Northern Border distribution on the same date. Additionally, the Partnership terminated an equivalent amount in interest rate swaps that were used to hedge this facility at a rate of 2.81%.

~~Partnership’s Senior Credit Facility and Overall Debt Level~~ - We continue to deleverage our balance sheet. At September 30, 2019, there was no outstanding balance under the Partnership's Senior Credit Facility. Additionally, the Partnership's overall consolidated debt was reduced by $115 million from $2,118 million at December 31, 2018 to $2,003 million at September 30, 2019 as a result of the (a) $40 million net repayment from cash flow of the outstanding balance under the Partnership's Senior Credit facility; (b) $50 million partial repayment of the Partnership's 2013 $500 Million Term Loan Facility; (c) the repayment of $35 million due upon the maturity of GTN's $75 million Unsecured Term Loan Facility; and (d) $1 million scheduled payment on Tuscarora's Unsecured Term Loan offset by $11 million of additional borrowings on PNGTS' revolving credit facility.

~~Credit Rating Upgrade~~ - On July 23, 2019, Standard & Poor's upgraded the Partnership’s credit rating to BBB/Stable from BBB-/Stable primarily due to the improvement in our financial risk profile resulting from our ongoing deleveraging efforts.

~~Growth Projects:~~

~~North Baja XPress Project (North Baja XPress)~~ -North Baja XPress is an estimated $90 million project to transport additional volumes of natural gas along North Baja's mainline system. The project was initiated in response to market demand to provide firm transportation service of up to approximately 495,000 Dth/day between Ehrenberg, Arizona and Ogilby, California. The binding open season for the project was concluded in April of 2019 and the estimated in-service date is November 1, 2022, subject to the satisfaction or waiver of certain conditions precedent.

~~PNGTS’ Portland XPress Project -~~ Our Portland XPress Project or “PXP” was initiated in 2017 in order to expand deliverability on the PNGTS system to Dracut through re-contracting and construction of incremental compression within PNGTS’ existing footprint in Maine. PXP was designed to be phased in over a three-year time period. Phases I and II were placed into service on November 1, 2018 and November 1, 2019, respectively. Phase III of the project is expected to be in service on November 1, 2020. Beginning 2021, the project is expected to generate approximately $50 million in annual revenue for PNGTS. PNGTS filed the required applications with FERC for all three phases of the project in 2018, which included an amendment to its Presidential Permit and an increase in its certificated capacity through the addition of a compressor unit at its jointly owned facility with Maritimes and Northeast Pipeline LLC to bring additional natural gas supply to New England. The total final volume of the project is approximately 183,000 Dth/ day; 40,000 Dth/day from Phase I, 118,400 Dth/day from Phase II, which includes re-contracting and renewal of expiring contracts, and 24,600 Dth/day from Phase III. We continue to advance this project and have received all approvals for filings to date. We intend to file with FERC for approval to proceed with construction of Phase III of the project in early 2020. PXP is secured by long-term agreements and when all phases of the project are in service, PNGTS will be effectively fully contracted until 2032.

Additionally, in connection with PXP, and as noted in our Annual Report on Form 10-K for the year ended December 31, 2018, PNGTS has entered into an arrangement with TC Energy regarding the construction of certain facilities on the TC Energy system (Canadian system expansions) that will be required to fulfill future contracts on the PNGTS system. In the event the Canadian system expansions terminate prior to their in-service dates, PNGTS could be required to reimburse TC Energy for an amount up to the total

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outstanding costs incurred to the date of the termination. As of September 30, 2019, the costs incurred to date by TC Energy on the construction of these facilities was approximately $134 million. As a result of TC Energy’s system expansions being commercially in service on November 1, 2019, and PNGTS’ commitments on TC Energy’s upstream pipelines being assigned to the PXP II shippers, PNGTS’ obligation to reimburse these costs terminated. Going forward, PNGTS will only be obligated to reimburse costs incurred by TC Energy in relation to Phase III, which was nil at September 30, 2019 and estimated to be approximately $7.2 million by November 1, 2020, when TC Energy’s facilities associated with the Phase volumes III go into service.

~~PNGTS' Westbrook XPress Project (Westbrook XPress)~~ - Westbrook XPress is an estimated $125 million multi-phase expansion project that is expected to generate approximately $35 million in revenue for PNGTS on an annualized basis when fully in service. It is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility. Westbrook XPress is designed to be phased in over a four-year period which began on November 1, 2019. Phases II and III have estimated in-service dates of November 2021 and 2022, respectively. These three Phases will add incremental capacity of approximately 43,000 Dth/day, 69,000 Dth/day, and 18,000 Dth/day, respectively. Westbrook XPress, together with PXP, will increase PNGTS’ capacity by 90 percent from 210,000 Dth/day to approximately 400,000 Dth/day.

~~Iroquois Gas Transmission ExC Project (Iroquois ExC Project)~~ -During the second quarter of 2019, Iroquois’ initiated the “Enhancement by Compression” project (ExC Project) which would optimize the Iroquois system to meet current and future gas supply needs of utility customers while minimizing environmental impact through enhancements at existing compressor stations along the pipeline. The project’s total design capacity is approximately 125,000 Dth/day with an estimated in-service date in November 2023. The capital cost of this project is still to be determined as the optimal facility set is finalized during the course of the regulatory process for this potential expansion. This project would be 100 percent underpinned with 20-year contracts.

~~GTN XPress Project (GTN XPress)~~ -On November 1, 2019, we announced that GTN will move forward with the GTN XPress project which will transport approximately 250,000 Dth/day of additional volumes of natural gas enabled by TC Energy’s system expansions upstream. The estimated total project cost of this integrated reliability and expansion project is $335 million. The project’s reliability work is anticipated to be in service by the end of 2021 and will account for more than three quarters of the total project cost. These costs are expected to be recovered in recourse rates. The project’s expansion work is anticipated to be commercially phased into service through November 2023. GTN XPress is 100 percent underpinned by fixed rate negotiated contracts with an average term in excess of 30 years. The incremental capacity is expected to generate approximately $25 million in revenue annually when fully in service.

~~Tuscarora XPress Project (Tuscarora XPress)~~ -Tuscarora XPress is an estimated $13 million expansion project through additional compression capability at an existing Tuscarora facility. Tuscarora XPress is 100 percent underpinned by a 20-year contract and will transport approximately 15,000 Dth/day of additional volumes when completed in November 2021. Tuscarora XPress is expected to generate approximately $2 million in revenue on an annualized basis when fully in service.

~~Pipeline Safety Matters~~ -On October 1, 2019, the Pipeline and Hazardous Materials Safety Administration (PHMSA) released the first of three final rulemakings (also known as the "gas mega rule") revising the Federal Pipeline Safety Regulations. The rule updates reporting and records retention standards for gas transmission pipelines and expands the level of required integrity assessments that must be completed on certain pipeline segments outside of high consequence areas. The final rule also requires operators to review maximum allowable operating pressure records and perform specific remediation activities where records are not available. We are currently assessing the operational and financial impact related to this final rule which will become effective on July 1, 2020. The remaining rulemakings comprising the gas mega rule are expected to be issued in late 2019 or early 2020.

Additionally, PHMSA released its “Enhanced Emergency Order Procedures” final rule on October 1, 2019. This final rule, which replaces an interim final rule issued by PHMSA in 2016, allows PHMSA to respond to imminent threats during natural disasters, and when serious flaws are discovered in pipes or in equipment manufacturing processes, or when an accident reveals an industry practice is unsafe. The final rule addressed comments made in response to the 2016 interim final rule, which resulted in several changes in the final rule. The Partnership is currently reviewing the final rule but does not expect any material issues with compliance when the final rule takes effect on December 2, 2019.

The Partnership expects new pipeline safety legislation to be proposed and finalized in late 2019 or early 2020, which could impose more stringent or costly compliance obligations on us and could require us to pursue additional capital projects or conduct integrity or maintenance programs on an accelerated basis, any or all of which tasks could result in the Partnership incurring increased operating

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~~costs that could have a material adverse effect on our costs of transportation services as well as our business, results of operations and financial condition.~~

HOW WE EVALUATE OUR OPERATIONS

We use certain non-GAAP financial measures that do not have any standardized meaning under GAAP as we believe they enhance the understanding of our operating performance. We use the following non-GAAP measures:

EBITDA

We define EBITDA as our net income before deducting interest, depreciation and amortization and taxes. We use EBITDA as a proxy of our operating cash flow and current operating profitability.

Adjusted EBITDA

Adjusted EBITDA is our EBITDA, less (1) earnings from our equity investments, plus (2) distributions from our equity investments, and plus or minus (3) certain non-recurring items (if any) that are significant but not reflective of our underlying operations. We provide Adjusted EBITDA as an additional performance measure of the current operating profitability of our assets.

Distributable Cash Flows

Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period.

Please see “Non-GAAP Financial Measures: EBITDA, Adjusted EBITDA and Distributable Cash Flow” for more information.

RESULTS OF OPERATIONS

Our ownership interests in eight pipelines were our only material sources of income during the period. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems.

Three months ended

Nine months ended

(unaudited)

September 30,

$

%

September 30,

$

%
(millions of dollars)

2019

2018

Change ^(a)

Change ^(a)

2019

2018

Change ^(a)

Change ^(a)

Transmission revenues

93

103

(10)

(10)

299

328

(29)

(9)
Equity earnings

31

34

(3)

(9)

115

129

(14)

(11)
Operating, maintenance and administrative costs

(26)

(24)

(2)

(8)

(76)

(73)

(3)

(4)
Depreciation

(19)

(25)

6

24

(58)

(73)

15

21
Financial charges and other

(20)

(23)

3

13

(63)

(69)

6

9
Net income before taxes

59

65

(6)

(9)

217

242

(25)

(10)
Income taxes

—

—

—

—

(1)

(1)

—

—
Net income

59

65

(6)

(9)

216

241

(25)

(10)
Net income attributable to non-controlling interests

3

3

—

—

12

10

2

(20)
Net income attributable to controlling interests

56

62

(6)

(10)

204

231

(27)

(12)

~~(a)~~

~~Positive number represents a favorable change; bracketed or negative number represents an unfavorable change.~~


	Three months ended
(unaudited)	June 30,			$	%
(millions of dollars)	2020	2019	Change	Change^(a)
Transmission revenues	95	93	2	2
Equity earnings	29	30	(1)	(3)
Operating, maintenance and administrative costs	(25)	(25)	—	—
Depreciation	(19)	(19)	—	—
Financial charges and other	(18)	(21)	3	14
Net income before taxes	62	58	4	7

Income taxes	(1)	(1)	—	—
Net income	61	57	4	7

Net income attributable to non-controlling interests	4	2	2	(100)
Net income attributable to controlling interests	57	55	2	4

^(a)~~Table of Contents~~ Positive number represents a favorable change; bracketed or negative number represents an unfavorable change.

Three Months Ended ~~September~~June 30, ~~2019 compared~~2020 Compared to the Same Period in ~~2018~~2019

The Partnership’s net income attributable to controlling interests increased by $2 million in the three months ended June 30, 2020 compared to the same period in 2019, mainly due to the following:

Transmission revenues -

The $2 million increase

in transmission revenues was largely the result of the following:

•higher revenue from PNGTS as a result of new revenues from PXP Phase II and Westbrook XPress Phase I. both of which entered service on November 1, 2019; partially offset by

•lower revenue at GTN due to (i) its scheduled 6.6 percent rate decrease effective January 1, 2020, and (ii) lower opportunity for the sale of discretionary services given the increased natural gas storage injection rates upstream of GTN; and

•lower revenueon Tuscarora due to its scheduled 10.8 percent rate decrease effective August 1, 2019

Financial charges and other - The $3 million decrease was primarily attributable to higher Allowance For Funds Used During Construction (AFUDC) which served to offset interest charges and thereby caused a decline. AFUDC increased as a result of continued spending on our expansion projects and higher maintenance capital spending.


	Six months ended
(unaudited)	June 30,			$	%
(millions of dollars)	2020	2019	Change	Change ^(a)
Transmission revenues	196	206	(10)	(5)
Equity earnings	84	84	—	—
Operating, maintenance and administrative costs	(48)	(50)	2	4
Depreciation	(39)	(39)	—	—
Financial charges and other	(37)	(43)	6	14
Net income before taxes	156	158	(2)	(1)

Income taxes	(1)	(1)	—	—
Net income	155	157	(2)	(1)

Net income attributable to non-controlling interests	10	9	1	(11)
Net income attributable to controlling interests	145	148	(3)	(2)

^(a) Positive number represents a favorable change; bracketed or negative number represents an unfavorable change.

Six Months Ended June 30, 2020 Compared to the Same Period in 2019

The Partnership’s net income attributable to controlling interests decreased by $6$3 million in the ~~three~~six months ended ~~September~~June 30, ~~2019~~2020 compared to the same period in ~~2018,~~2019, mainly due to the following:

Transmission revenues - ~~Revenues were lower due~~The $10 million decreasein transmission revenues was largely to the ~~decrease in revenue from Bison. During the fourth quarter~~net result of ~~2018, two of Bison's customers elected to pay out the remainder of their contracted obligations on Bison and terminate the associated transportation agreements. Revenues were also impacted by~~ the following:

•

●

higher revenue on GTN primarily due to the one-time $9 million charge against revenue in the third quarter of 2018 related to the 2018 settlement with its shippers which did not apply in the third quarter 2019, partially offset by the impact of its scheduled 10 percent rate decrease effective January 1, 2019;

●

~~higher revenue from PNGTS primarily due to higher~~lower revenueon GTN due to (i) its scheduled 6.6 percent rate decrease effective January 1, 2020, (ii) lower discretionary services due to an unseasonably warm summer and power generation demands in addition to new revenues from Phase I of its PXP project that went into service November 1, 2018, partially offset by lower contracted revenue as a result of the expiration of its legacy recourse rate firm contracts;

●

~~lower short-term firm transportation~~ services sold ~~by North Baja; and~~

●

~~lower revenue on Tuscarora due to its scheduled 10.8 percent rate decrease effective August 1, 2019 as part of the settlement reached with its customers in 2019.~~

~~Equity Earnings -~~ ~~The $3 million decrease was~~ primarily due to moderate weather conditions in early 2020 compared to colder weather experienced in early 2019, (iii) additional sales in 2019 related to regional supply constraints from a force majeure event experienced by a neighboring pipeline that were not repeated in 2020; and (iv) lower opportunity for the ~~following:~~

sale of discretionary services during the second quarter given the increased natural gas storage injection rates upstream of GTN;;

•

●

~~decrease in equity earnings from Great Lakes~~lower revenueon Tuscarora due to its scheduled 10.8 percent rate decrease effective August 1, 2019;

•higher revenue at PNGTS as a result of new revenues from its PXP Phase II and Westbrook XPress Phase I projects which both entered into service on November 1, 2019, partially offset by lower discretionary services sold by PNGTS in 2020 to date compared to the same period in 2019 due to more moderate weather conditions in early 2020;

•lower revenue from short-term discretionary services sold by North Baja; and

•lower revenue on Bison as a ~~result of an increase in operating costs related to compliance programs and estimated costs related to right-of-way renewals combined with an increase in allocated management costs from TC Energy; and~~

●

~~decrease in Iroquois’ equity earnings as a result of the scheduled reduction of its existing rates as part of the 2019 settlement with shippers.~~

~~Operation and maintenance expenses~~ -~~The increase in operation and maintenance expenses was primarily due to an overall net increase in:~~

●

~~operational costs related to our pipeline systems' compliance programs; and~~

●

~~increase in TC Energy's allocated costs related to corporate support functions and common costs such as insurance.~~

~~Depreciation~~ ~~- The decrease in depreciation expense was a direct~~ result of the ~~elimination~~expiration of ~~Bison's depreciable base during~~one of its legacy contracts at the ~~fourth quarter~~end of ~~2018.~~

January 2019.

Financial charges and other - The $3 million decrease was primarily attributable to the full repayment of our $170 million term loan during the fourth quarter of 2018, together with a $115 million reduction of our overall debt balance year-to-date which included a net $40 million repayment of borrowings under our Senior Credit Facility during the first quarter of 2019 and a $50 million payment on our 2013 term loan facility during the second quarter of 2019.

~~Nine Months Ended September 30, 2019 compared to Same Period in 2018~~

~~The Partnership’s net income attributable to controlling interests decreased by $27 million in the nine months ended September 30, 2019 compared to 2018, mainly due to the following:~~

~~Table of Contents~~

~~Transmission revenues~~- Revenues were lower due largely to the decrease in revenue from Bison. During the fourth quarter of 2018, two of Bison’s customers elected to pay out the remainder of their contracted obligations on Bison and terminate the associated transportation agreements. The decrease was also due to the following:

●

higher revenue on GTN primarily due to the $9 million provision for revenue sharing recorded at the end of September 30, 2018 partially offset by the impact of its scheduled 10 percent rate decrease effective January 1, 2019, both of which are part of the settlement reached with its customers in 2018;

●

higher revenue from PNGTS primarily due to higher discretionary services due to unseasonably warm summer and power generation demands in its area and new revenues from Phase I of its PXP project that went into service November 1, 2018 partially offset by lower contracted revenue as a result of the expiration of its legacy recourse rate firm contracts; and

●

lower revenue on Tuscarora due to its 1.7% rate decrease effective February 1, 2019 and scheduled additional 10.8 percent rate decrease effective August 1, 2019 as part of the settlement reached with its customers in 2019.

~~Equity Earnings -~~ ~~The $14 million decrease was primarily due to the net effect of the following:~~

●

decrease in Iroquois’ equity earnings as a result of decrease in its revenue. The sustained cold temperatures in the first quarter of 2018 resulted in incremental seasonal winter sales that were not achieved in the same period of 2019. Additionally, there was a scheduled reduction of Iroquois’ existing rates as part of the 2019 Iroquois Settlement; and

●

decrease in Great Lakes’ equity earnings as a result of decrease in its revenue and increase in its operating costs. The sustained cold temperatures in the first quarter of 2018 resulted in incremental seasonal winter sales for Great Lakes that were not achieved in the same period of 2019. Additionally, there was an increase in its operating costs related to its compliance programs, estimated costs related to right-of-way renewals and an increase in TC Energy's allocated management costs and allocated costs related to corporate support functions and common costs such as insurance.

~~Operation and maintenance expenses~~ ~~- The increase in operation and maintenance expenses was primarily due to the overall net impact of the following:~~

●

~~increase in operational costs related to our pipeline systems' compliance programs;~~

●

~~increase in TC Energy's allocated costs related to corporate support functions and common costs such as insurance; and~~

●

~~decrease in overall property taxes primarily due to lower taxes assessed on Bison.~~

~~Depreciation~~ - The decrease in depreciation expense during the nine months ended September 30, 2019 was a direct result of the long-lived asset impairment recognized during the fourth quarter of 2018 on Bison which effectively eliminated the depreciable base of the pipeline.

~~Financial charges and other -~~ The $6 million decrease was primarily attributable to the ~~repayment of~~following:

•generally lower weighted average interest costs despite an increase on our ~~$170 million Term Loan during the fourth quarter of 2018~~overall debt balance; and ~~repayment of borrowings under~~

•higher AFUDC primarily due to continued spending on our ~~Senior Credit Facility during the first quarter of 2019.~~

expansion projects and higher maintenance capital spending.

Net Income Attributable to Common Units and Net Income per Common Unit

As discussed in Note 9 within Item 11. “Financial Statements,” we ~~allocated $1 million~~will allocate a portion of the Partnership’s ~~net~~ income ~~attributable to controlling interests~~ to the Class B units inafter the ~~three and nine months ended September 30, 2019, representing~~annual threshold is exceeded which will effectively reduce the ~~excess of 30 percent of GTN’s distribution over the 2019 threshold level of $20 million, which was further reduced by the estimated Class B Reduction for 2019. This allocation reduced net~~ income ~~attributable~~allocable to the common units and ~~accordingly, reduced~~ net income per common ~~unit by approximately $0.01 cent for both~~unit. Beginning in 2020 and beyond, we expect the ~~three and nine months ended September 30, 2019.~~

~~We allocated $4 million~~impact of ~~the Partnership’s net income attributable to controlling interests to~~ the Class B ~~units in~~distribution on our cashflows to be significantly lower compared to previous periods due to TC Energy's reduced share of GTN's distributable cashflows beginning at the ~~three and nine months ended September 30, 2018, representing~~end of March 2020 as part of the ~~excess of 30 percent of GTN’s distribution over the 2018 threshold level of $20 million, which was further reduced by the estimated~~ Class B ~~Reduction~~agreement. Please also read Note 8 within Item 1. “Financial Statements,” for ~~2018. This allocation reduced net income attributable to~~additional disclosures on the ~~common units and accordingly, reduced net income per common unit by approximately $0.05 cents for both the three and nine months ended September 30, 2018.~~

Class B units.

~~Table of Contents~~

LIQUIDITY AND CAPITAL RESOURCES

Overview

The Partnership strives to maintain financial strength and flexibility in all parts of the economic cycle. Our principal sources of liquidity and cash flows currently include distributions received from our equity investments, operating cash flows from our subsidiaries ~~public offerings of debt and equity, term loans~~ and our ~~Senior Credit Facility.~~credit facilities. The Partnership funds its operating expenses, debt service and cash distributions (including those distributions made to TC Energy through our General Partner and as holder of all our Class B units) primarily ~~with~~from operating cash flow.

Overall Current Financial Condition

Cash and Debt position

~~At September 30, 2019,~~- Our overall long-term debt balance increased by approximately $107 million primarily as result of the financing put in place during the period for our expansion projects. The increase included an incremental $75 million of liquidity from GTN's issuance of Series A Senior Notes at a fixed rate of 3.12 percent which effectively secured the funding required for GTN XPress for the balance of 2020. The $75 million also resulted in an increase in the balance of our cash and cash equivalents, ~~was higher than~~which totaled $215 million at June 30, 2020 compared to our position at December 31, ~~2018 by~~2019 of approximately ~~$57~~$83 million.

Working capital position-At June 30, 2020, our current assets totaled $262 million and current liabilities amounted to $415 million, leaving us with a working capital deficit of $153 million compared to a deficit of $14 million at December 31, 2019. Our working capital deficiency is considered normal course for our business and is managed through:

•our ability to generate predictable and growing cash flows from operations;

•cash on hand and full access to our $500 million Senior Credit Facility; and

•our access to debt capital markets, facilitated by our strong investment grade ratings, allowing us the ability to renew and/or refinance the current portion of our long-term ~~debt balance was lower by $115 million.~~ debt.

We continue to ~~use~~be financially disciplined by using our available cash to fund ongoing capital expenditures and ~~the repayment of~~maintaining debt at prudent levels and we believe we are well positioned to ~~levels that prudently manage~~fund our ~~financial metrics.~~

obligations as required.

We believe our (1) cash ~~position, remaining~~on hand, (2) operating cash-flows (3) $500 million available borrowing capacity onunder our Senior Credit Facility ~~(see table below),~~at August 5, 2020, and ~~our operating cash flows~~(4) if needed, and subject to customary lender approval upon request, an additional $500 million capacity that is available under the Senior Credit Facility's accordion feature, are sufficient to fund our short-term liquidity requirements, including distributions to our unitholders, ongoing capital expenditures, ~~and~~ required debt ~~repayments.~~

repayments and other financing needs such as capital contribution requests from our equity investments without the need for additional common equity.

Our Pipeline Systems' Current Financial Condition

The ~~following table sets forth the available borrowing capacity under the~~ Partnership's ~~Senior Credit Facility:~~

source of operating cashflows emanates from (1) operating cash generated by GTN, North Baja, Tuscarora, PNGTS and Bison, our consolidated subsidiaries, and (2) distributions received from our equity investments in Great Lakes, Northern Border and Iroquois.

(unaudited)

(millions of dollars)

September 30, 2019

December 31, 2018

Total capacity under the Senior Credit Facility

500

500
Less: Outstanding borrowings under the Senior Credit Facility

—

40
Available capacity under the Senior Credit Facility

500

460

~~The~~

Our pipeline systems’ principal sources of liquidity ~~on our pipeline systems~~ are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from ~~their~~ owners. ~~Our~~Except as noted below, our pipeline systems ~~have historically funded~~expect to fund their respective expansion projects primarily with debt. Except as noted below, our pipeline systems' normal recurring operating expenses, maintenance capital expenditures, debt service and cash distributions toare primarily funded with their ~~owners primarily with~~ operating cash ~~flow. However, since~~flows.

•Since the fourth quarter of 2010, Great Lakes has funded its debt repayments with cash calls to its owners. ~~Additionally,~~We contributed approximately $10 million in ~~June~~ 2019 ~~Northern Border borrowed~~and expect our 2020 contribution to be approximately the same.

•In August 2019, the Partnership made an equity contribution to Iroquois of approximately $4 million. This amount represented the Partnership’s 49.34 percent share of a $7 million capital call from Iroquois to cover regulatory costs related to the ExC Project. In 2020, we expect to make an additional ~~$100~~contribution of approximately $2 million ~~under its $200~~to support the ExC Project.

•Bison’s remaining contracts will continue to be in effect until January of 2021. In 2019, Bison generated revenues of $32 million ~~revolving credit facility~~and is expected to ~~finance a cash distribution~~produce comparable results in 2020. We continue to explore alternative transportation-related options for Bison and we believe commercial potential exists to reverse the direction of ~~$100~~natural gas flow on Bison for deliveries onto third party pipelines and ultimately connect into the Cheyenne hub. In any event, Bison will continue to incur costs related to property tax and operating and maintenance costs of approximately $6 million ~~of which $50 million was received by the Partnership. The Partnership used the $50 million proceeds to partially pay its 2013 Term Loan Facility due in 2021.~~

per year.

~~Capital~~

Maintenance and expansion capital expenditures ~~of our pipeline systems~~ are funded by a variety of sources, ~~including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or equity contributions from our pipeline systems' owners.~~as noted above. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends onupon their financial ~~position~~condition and ~~general~~prevailing market ~~conditions.~~

conditions

The ~~Partnership's~~Partnership’s pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs which, although ~~limited~~governed by FERC, allow them to request a certain amount of credit support as circumstances dictate.

~~Table of Contents~~

Cash Flow Analysis for the ~~Nine months ended September~~Six Months Ended June 30, ~~2019 compared~~2020 Compared to the Same Period in ~~2018~~2019


	Six months ended
(unaudited)	June 30,
(millions of dollars)	2020	2019
Net cash provided by (used in):
Operating activities	228	228
Investing activities	(88)	22
Financing activities	(8)	(238)
Net increase in cash and cash equivalents	132	12
Cash and cash equivalents at beginning of the period	83	33
Cash and cash equivalents at end of the period	215	45

Nine months ended
(unaudited)

September 30,
(millions of dollars)

2019

2018

Net cash provided by (used in):




Operating activities

344

354
Investing activities

1

(24)
Financing activities

(288)

(315)
Net increase in cash and cash equivalents

57

15
Cash and cash equivalents at beginning of the period

33

33
Cash and cash equivalents at end of the period

90

48

Operating Cash Flows

The Partnership's operating cashflows for the ~~nine~~six months ended ~~September~~June 30, ~~2019, the Partnership's net cash provided by operating activities decreased by $10 million~~2020 compared to the same period in ~~2018 primarily~~2019 were comparable due to the net effect of:

•

●

~~lower net cash flow from operations of our consolidated subsidiaries primarily due to the decrease in revenue from Bison, North Baja and Tuscarora partially offset by an increase in PNGTS’ revenue;~~

●

~~increase in distributions received from operating activities of equity investments as a result of:~~

the timing of receipt of Iroquois' third quarter 2019 distributions from its operating activities, which we would ordinarily have received during the fourth quarter of 2019 but were instead received early in the first quarter of 2020; offset by

~~lower maintenance capital spending during the nine months ended September 30, 2019 on Northern Border;~~

~~net higher earnings generated by Northern Border and Great Lakes compared to the same period in the prior year;~~

~~increase in distributions from Iroquois related to cash generated from prior years' operating activities; and~~

•

●

~~impact from amount and timing of operating working capital changes.~~

lower distributions from operating activities of our equity investment in Northern Border and Great Lakes largely due to higher maintenance capital spending at both entities.

Investing Cash Flows

During the ~~nine~~six months ended ~~September~~June 30, ~~2019,~~2020, the cash ~~provided by~~used in our investing activities was a net cash ~~inflow~~outflow of $1$88 million compared to a net ~~outflow~~inflow of ~~$24~~$22 million in the ~~same period in 2018 primarily~~six months ended June 30, 2019 due to the net ~~impact~~effect of:

•higher maintenance capital expenditures at GTN for its overhaul projects together with continued capital spending on our GTN XPress, PXP and Westbrook XPress projects; and

•$50 million distribution received from Northern Border during the second quarter of ~~the following:~~

●

~~$50 million distribution received from Northern Border that was considered a return of investment during the second quarter of 2019;~~

●

$4 million equity contribution to Iroquois representing the Partnership’s 49.34 percent share of a $7 million cash call from Iroquois to cover costs of regulatory approvals related to their capital project; and

●

~~higher capital maintenance expenditures on GTN for reliability projects together with continued capital spending on our PXP project.~~

2019 that was considered a return of investment

Financing Cash Flows

The ~~Partnership's net~~change in the cash used for financing activities was ~~approximately $27 million lower in the nine months ended September 30, 2019 compared to the same period in 2018~~ primarily due to the net ~~effect of:~~

●

~~$42 million decrease in net debt repayments;~~

●

~~$29 million decrease in distributions paid to common unitholders as a result of a lower per unit distribution paid beginning in second quarter 2018 in response to the 2018 FERC Actions;~~

●

~~$7 million increase in distributions paid to non-controlling interests during the nine months ended September 30, 2019;~~

●

~~$2 million decrease in distributions paid to Class B units in 2019 as compared to 2018; and~~

●

~~no ATM equity issuances in 2019 year-to-date.~~

debt issuance of $107 million in the six months ended June 30, 2020 compared to a net debt repayment of $115 million for the same period in the prior year, primarily due to financing executed for the capital expenditures on our GTN XPress, PXP and Westbrook XPress expansion projects.

~~Table of Contents~~

Short-Term Cash Flow Outlook

Operating Cash Flow Outlook

Northern Border declared its ~~September 2019~~June 2020 distribution of ~~$15~~$11 million on ~~October~~July 9, ~~2019,~~2020, of which the Partnership received its 50 percent share or ~~$7 million. The distribution was paid~~$5 million on ~~October 18, 2019.~~

July 31, 2020.

September 29, 2020.

Investing Cash Flow Outlook

The Partnership made an equity contribution to Great Lakes of $5 million in the first quarter of ~~2019.~~2020. 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 expects to make an additional $5 million equity contribution to Great Lakes in the fourth quarter of ~~2019~~2020 to further fund debt repayments. This is consistent with prior years.

Our equity investee, Iroquois, has $3$1.5 million of scheduled debt repayments for the remainder of ~~2019 and~~2020. Iroquois’ debt repayments are expected to be funded through cash flow from operations.

Our consolidated entities have commitments of ~~$21~~$100 million as of ~~September~~June 30, ~~2019~~2020 in connection with various maintenance and general plant projects.

Commercial system purchase effective August 1, 2020

On August 1, 2020, four of our pipelines jointly purchased an internally developed customer-facing commercial natural gas IT application system from a TC Energy affiliate. The total price of the transaction was $51 million and the Partnership's proportionate share was $38 million. The purchase, which is considered a maintenance capital cost, was funded primarily from cash generated from each pipeline's cash from operations. See Note 16 of the “Financial Statements” within Item 1.

Except for the commercial system purchase described above, we do not anticipate any other material changes to our expected 2020 growth and maintenance capital expenditures from what was disclosed in our 2019 ~~our pipeline systems~~Annual Report. However, those estimates are subject to cost and timing adjustments due to weather, market conditions, permitting conditions and timing of regulatory permits, among other factors, as well as additional uncertainty presented by the COVID-19 pandemic. We expect to ~~invest approximately $97 million in maintenance~~continue funding these expenditures from a combination of ~~existing facilities~~(1) cash from operations and ~~approximately $45 million in growth projects, of which~~(2) debt at both the ~~Partnership’s share would be $78 million~~asset and ~~$30 million, respectively. As our GTN XPress project progresses, we anticipate funding the Partnership's share of the required capital using cash on hand and the Senior Credit facility, if required.~~

Partnership levels.

Financing Cash Flow Outlook

Distributions to unitholders

On ~~October 22, 2019,~~July 23, 2020, the board of directors of our General Partner declared the Partnership’s ~~third~~second quarter ~~2019~~2020 cash distribution in the amount of $0.65 per common unit payable on ~~November~~August 14, ~~2019~~2020 to unitholders of record as of ~~November 1, 2019.~~August 3, 2020. Please see Note 1716 of the "Financial Statements" within Item 1 and ~~“Recent~~��Recent Business Developments” within Item 2 for additional disclosures.

Debt refinancing:

•

WePNGTS is currently ~~intend~~negotiating an increase in its borrowing capacity to ~~refinance GTN’s $100~~include the balance of the financing required for its PXP and Westbrook XPress expansion projects; and

•The Partnership's $350 million ~~5.29%~~aggregate principal amount 4.65 percent Unsecured Senior Notes and $500 million Senior Credit Facility are both due ~~June 1, 2020,~~in 2021 and ~~Tuscarora's $23 million variable rate Unsecured Term Loan due August 21, 2020 in full~~we expect that both will be refinanced or ~~at an amount based on our preferred capitalization levels.~~

extended prior to maturity.

Non-GAAP Financial Measures: EBITDA, Adjusted EBITDA and Distributable Cash Flow

EBITDA is an approximate measure of our operating cash flow during the current earnings period and reconciles directly to the most comparable measure of net ~~income. It measures our earnings before deducting interest, depreciation and amortization, taxes,~~income, which includes net income attributable to non-controlling interests, and ~~includes~~ earnings from our equity investments.

It measures our net income before deducting interest, depreciation and amortization and taxes.

Adjusted EBITDA is our EBITDA, less (1) earnings from our equity investments, plus (2) distributions from our equity investment, and plus or minus (3) certain non-recurring items (if any) that are significant but not reflective of our underlying operations.

Beginning the first quarter of 2020, the Partnership revised its calculation of Adjusted EBITDA to include distributions from our equity investments, net of equity earnings from our investments as described above, which were previously excluded from such measure. The presentation of Adjusted EBITDA for the three months and six months ended June 30, 2019 was recast to conform with the current presentation. The Partnership believes the revised presentation more closely aligns with similar non-GAAP measures presented by our peers and with the Partnership’s definitions of such measures.

Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period and reconcile directly to the net income amounts presented.

Total distributable cash flow includes ~~EBITDA~~ ~~plus:~~

●

~~Distributions from our equity investments~~

~~less:~~

●

~~Earnings from our equity investments,~~

Adjusted EBITDA:

less:

~~Table of Contents~~•

AFUDC;

●

~~Equity allowance for funds used during construction (if any),~~

●

~~Interest expense,~~

●

~~Income taxes,~~

●

~~Distributions to non-controlling interests, and~~

●

~~Maintenance capital expenditures from consolidated subsidiaries.~~

•

Interest expense;

•Current income taxes;

•Distributions to non-controlling interests; and

•Maintenance capital expenditures from consolidated subsidiaries.

Distributable cash flow is computed net of distributions declared to the General Partner and any distributions allocable to Class B units. Distributions declared to the General Partner are based on its two percent interest plus, if applicable, an amount equal to incentive distributions. Distributions allocable to the Class B units in ~~2019~~2020 equal 30 percent of ~~GTN's~~GTN’s distributable cash flow less $20 million, the residual of which is further multiplied by 43.75 percent and is further reduced by the Class B Reduction. Distributions allocable to the Class B units in 2019 equaled 30 percent of GTN’s distributable cash flow less $20 million and the Class B Reduction.

Distributable cash flow, EBITDA and Adjusted EBITDA are performance measures presented to assist investors in evaluating our business performance. We believe these measures provide additional meaningful information in evaluating our financial performance and cash generating capacity.

The non-GAAP financial measures described above are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.

~~Table of Contents~~

Reconciliations of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow

The following table represents a reconciliation of the non-GAAP financial measures of EBITDA, total distributable cash flow and distributable cash flow, to the most directly comparable GAAP financial measure of ~~Net Income:~~

net income:

Three months ended

Nine months ended
(unaudited)

September 30,

September 30,
(millions of dollars)

2019

2018

2019

2018
Net income

59

65

216

241

Add:








Interest expense ^(a)

22

23

66

71
Depreciation and amortization

19

25

58

73
Income taxes

—

—

1

1

EBITDA

100

113

341

386

Add:








Distributions from equity investments ^(b) (f)








Northern Border ^(c)

21

22

69

60
Great Lakes

7

10

39

49
Iroquois ^(d)

28

14

56

42

56

46

164

151
Less:








Equity earnings:








Northern Border

(15)

(16)

(50)

(49)
Great Lakes

(8)

(9)

(37)

(45)
Iroquois

(8)

(9)

(28)

(35)

(31)

(34)

(115)

(129)
Less:








AFUDC equity

—

—

(1)

—
Interest expense ^(a)

(22)

(23)

(66)

(71)
Income taxes

—

—

(1)

(1)
Distributions to non-controlling interest ^(e)

(4)

(3)

(14)

(12)
Maintenance capital expenditures ^(f)

(19)

(11)

(40)

(21)

(45)

(37)

(122)

(105)

Total Distributable Cash Flow

80

88

268

303
General Partner distributions declared ^(g)

(1)

(1)

(3)

(3)
Distributions allocable to Class B units ^(h)

(1)

(4)

(1)

(4)
Distributable Cash Flow

78

83

264

296

~~(a)~~


	Three months ended			Six months ended
(unaudited)	June 30,			June 30,
(millions of dollars)	2020	2019	2020	2019
Net income	61	57	155	157
Add:
Interest expense^(a)	22	22	42	44
Depreciation and amortization	19	19	39	39
Income taxes	1	1	1	1
EBITDA	103	99	237	241

Less:
Equity earnings:
Northern Border	(13)	(14)	(35)	(35)
Great Lakes	(9)	(9)	(29)	(29)
Iroquois	(7)	(7)	(20)	(20)
	(29)	(30)	(84)	(84)
Add:
Distributions from equity investments^(b)
Northern Border	15	21	42	48
Great Lakes	11	9	32	32
Iroquois^(c)	10	14	21	28
	36	44	95	108

Adjusted EBITDA	110	113	248	265

Less:
AFUDC	(2)	(1)	(3)	(1)
Interest expense^(a)	(22)	(22)	(42)	(44)
Current income taxes	(1)	(1)	(1)	(1)
Distributions to non-controlling interest^(d)	(5)	(3)	(11)	(10)
Maintenance capital expenditures^(e)	(24)	(15)	(46)	(21)
	(54)	(42)	(103)	(77)

Total Distributable Cash Flow	56	71	145	188
General Partner distributions declared^(f)	(1)	(1)	(2)	(2)
Distributions allocable to Class B units^(g)	—	—	—	—
Distributable Cash Flow	55	70	143	186

^(a)Interest expense as presented includes net realized loss or gain related to interest rate swaps.

^(b)Amounts are calculated in accordance with the cash distribution policies of each of our equity investments. Distributions from our equity investments represent our respective share of these entities’ quarterly distributable cash for the current reporting period.

^(c)This amount represents our proportional 49.34 percent share of the distribution declared by our equity investee, Iroquois, for the current reporting period. For the three and six months ended June 30, 2019, the amount includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million and $5.2 million, respectively (three and six months ended June 30, 2020 - none).

^(d)Distributions to non-controlling interests represent the respective share of our consolidated entities’ distributable cash not owned by us for the periods presented.

^(e)The Partnership’s maintenance capital expenditures include expenditures made to maintain, over the long term, the operating capacity, system integrity and reliability of our pipeline assets. This amount represents the Partnership’s and its consolidated subsidiaries’ maintenance capital expenditures and does not include the Partnership’s share of maintenance capital expenditures for our equity investments. Such amounts are reflected in “Distributions from equity investments” as those amounts are withheld by those entities from their quarterly distributable cash.

^(f)No incentive distributions were declared to the General Partner for both the three and six months ended June 30, 2020 and 2019.

^(g)For the three and six months ended June 30, 2020 and 2019, no distributions were allocated to the Class B units. Please read Notes 8 and 9 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

Three Months Ended June 30, 2020 Compared to the ~~interest rate swaps.~~

~~(b)~~

Amounts are calculated in accordance with the cash distribution policies of each of our equity investments. Distributions from our equity investments represent our respective share of these entities' quarterly distributable cash for the current reporting period.

~~(c)~~

~~Excludes the $50 million additional distribution we received from Northern Border. The entire proceeds were used by us to partially paydown our 2013 Term Loan Facility.~~

~~(d)~~

This amount represents our proportional 49.34 percent share of the distribution declared by our equity investee, Iroquois, for the current reporting period. It includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million and $7.8 million, respectively, for both the three and nine months ended September 30, 2019 and 2018 and an additional distribution we received amounting to approximately $15 million for both the three and nine months ended September 30, 2019 (2018-none) related to the increase in the cash Iroquois generated from its higher net income in 2017 (post acquisition) and 2018.

~~Table of Contents~~

~~(e)~~

~~Distributions to non-controlling interests represent the respective share of our consolidated entities' distributable cash not owned by us for the periods presented.~~

~~(f)~~

The Partnership's maintenance capital expenditures include expenditures made to maintain, over the long term, the operating capacity, system integrity and reliability of our pipeline assets. This amount represents the Partnership's and its consolidated subsidiaries' maintenance capital expenditures and does not include the Partnership's share of maintenance capital expenditures for our equity investments. Such amounts are reflected in “Distributions from equity investments” as those amounts are withheld by those entities from their quarterly distributable cash.

~~(g)~~

~~No incentive distributions were declared to the General Partner for both the three and nine months ended September 30, 2019 and 2018.~~

~~(h)~~

For the three and nine months ended September 30, 2019 and 2018, $1 million and $4 million was allocated to the Class B units, respectively. Please read Notes 8 and 9 within Item 1. “Financial Statements” for additional disclosures on the Class B units.

~~Three months ended September 30, 2019 Compared to~~ Same Period in ~~2018~~

2019

Our EBITDA was ~~lower~~higher for the ~~third quarter of 2019~~three months ended June 30, 2020 compared to the same period in ~~2018.~~2019. The ~~$13~~$4 million ~~decrease~~increase was primarily due to ~~lower~~higher revenue ~~and equity earnings and higher operation and maintenance expenses during the period~~from consolidated subsidiaries as discussed in more detail under the “Results of Operations” ~~section.~~

section within Item 2.

Our ~~distributable cash flow decreased by $5 million in~~Adjusted EBITDA was lower for the ~~third quarter of 2019~~three months ended June 30, 2020 compared to the same period in ~~2018 due to the net effect of:~~

●

~~lower EBITDA from our consolidated subsidiaries;~~

●

~~higher maintenance capital expenditures related to major compression equipment overhauls and pipe integrity costs on GTN as a result of higher transportation volumes of natural gas;~~

●

~~lower Class B allocation due to the increase in maintenance capital expenditures which reduced the distributable cash flow generated by GTN;~~

●

lower interest expense due to the full repayment of the $170 million Term Loan during the fourth quarter of 2018 and the repayment of borrowings under our Senior Credit Facility and term loan facility in the first half of 2019;

●

~~lower distributions from Great Lakes resulting from decreased earnings and increased maintenance capital spending; and~~

●

~~additional distribution received from Iroquois due to the surplus cash it accumulated from the previous years' higher net income.~~

~~Nine months ended September 30, 2019 Compared to Same Period in 2018~~

~~Our EBITDA was lower for the nine months ended September 30, 2019 compared to the same period in 2018.~~2019. The ~~$45~~$3 million decrease was primarily due to ~~lower revenue, lower equity~~the net effect of the following:

•higher earnings ~~and higher operation and maintenance expenses offset by lower property taxes during the period~~from consolidated subsidiaries as discussed in more detail under the “Results of Operations” ~~section.~~

section within Item 2;

•

lower distributions from Northern Border primarily due to higher maintenance capital spending for its major equipment overhauls; and

•lower distribution from Iroquois as it satisfied its final surplus cash distribution obligation of $2.6 million per quarter in the fourth quarter of 2019 and the surplus cash payments are no longer applicable.

Our distributable cash flow decreased by ~~$32~~$15 million in the ~~nine~~three months ended ~~September~~June 30, ~~2019~~2020 compared to the same period in ~~2018~~2019 due to the net effect of:

●

~~lower EBITDA from our consolidated subsidiaries;~~

●

~~higher maintenance capital expenditures related to major compression equipment overhauls and pipe integrity costs on GTN as a result of higher transportation volumes of natural gas;~~

●

lower interest expense due to the full repayment of the $170 million Term Loan during the fourth quarter of 2018 and the partial repayment of borrowings under our Senior Credit Facility in the first quarter of 2019;

●

~~higher distributions from our equity investment in Northern Border primarily due to lower capital spending related to compressor station maintenance costs;~~

●

~~lower distributions from Great Lakes resulting from decreased earnings and increased maintenance capital spending;~~

●

~~additional distribution received from Iroquois due to the surplus cash it accumulated from previous years' higher net income; and~~

●

~~lower Class B allocation due to lower distributable cash flow generated by GTN.~~

•lower Adjusted EBITDA; and

•higher normal-course maintenance capital expenditures at GTN as a result of increased spending on major equipment overhauls at several compressor stations and certain system upgrades.

Six Months Ended June 30, 2020 Compared to the Same Period in 2019

Our EBITDA was lower for the six months ended June 30, 2020 compared to the same period in 2019. The $4 million decrease was primarily due to lower revenue from consolidated subsidiaries as discussed in more detail under the “Results of Operations” section within Item 2.

Our Adjusted EBITDA was lower for the six months ended June 30, 2020 compared to the same period in 2019. The $17 million decrease was primarily due to:

•lower revenue from consolidated subsidiaries as discussed in more detail under the “Results of Operations” section within Item 2;

•lower distributions from Northern Border primarily due to higher maintenance capital spending on its major equipment overhauls and certain system upgrades; and

•lower distributions from Iroquois as it satisfied its final surplus cash distribution obligation of $2.6 million per quarter in the fourth quarter of 2019 and the surplus cash payments are no longer applicable.

Our distributable cash flow decreased by $43 million in the six months ended June 30, 2020 compared to the same period in 2019 due to the net effect of:

•lower Adjusted EBITDA; and

•higher maintenance capital expenditures at GTN as a result of increased spending on major equipment overhauls at several compressor stations and certain system upgrades.

~~Table of Contents~~

Contractual Obligations

The ~~Partnership's~~Partnership’s Contractual Obligations

The ~~Partnership's~~Partnership’s contractual obligations as of ~~September~~June 30, ~~2019~~2020 included the following:

Payments Due by Period












Weighted Average

Interest Rate for

the Nine Months

(unaudited)

Less than

1‑3

4‑5

More than 5

Ended September 30,

(millions of dollars)

Total

1 Year

Years

Years

Years

2019

TC PipeLines, LP













Senior Credit Facility due 2021

—

—

—

—

—

— %

2013 Term Loan Facility due 2022

450

—

—

450

—

3.66%

4.65% Senior Notes due 2021

350

—

350

—

—

4.65%
^(a)
4.375% Senior Notes due 2025

350

—

—

—

350

4.375%
^(a)
3.90% Senior Notes due 2027

500

—

—

—

500

3.90%
^(a)
GTN



5.29% Unsecured Senior Notes due 2020

100

100

—

—

—

5.29%
^(a)
5.69% Unsecured Senior Notes due 2035

150

—

—

—

150

5.69%
^(a)
PNGTS













Revolving Credit Facility due 2023

30

—

—

30

—

3.65%

North Baja









Unsecured Term Loan due 2021

50

—

50

—

—

3.48%

Tuscarora









Unsecured Term Loan due 2020

23

23

—

—

—

3.54%

Partnership (TC PipeLines, LP and its subsidiaries)











Interest on Debt Obligations^(b)

466

87

139

88

152



Operating Leases

1

—

1

—

—



Right of Way commitments

4

1

—

1

2



2,474

211

540

569

1,154

~~(a)~~

~~Fixed interest rate.~~

~~(b)~~

Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at September 30, 2019 and are therefore subject to change.


	Payments Due by Period
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Six Months Ended June 30, 2020
TC PipeLines, LP
Senior Credit Facility due 2021	—	—	—	—	—	—
2013 Term Loan Facility due 2022	450	—	450	—	—	2.34%
4.65% Senior Notes due 2021	350	350	—	—	—	4.65%	^(a)
4.375% Senior Notes due 2025	350	—	—	350	—	4.375%	^(a)
3.90% Senior Notes due 2027	500	—	—	—	500	3.90%	^(a)
GTN
3.12% Series A Senior Notes due 2030	175	—	—	—	175	3.12%	^(a)
5.69% Unsecured Senior Notes due 2035	150	—	—	—	150	5.69%	^(a)
PNGTS
Revolving Credit Facility due 2023	71	—	71	—	—	2.36%

North Baja
Unsecured Term Loan due 2021	50	—	50	—	—	2.17%
Tuscarora
Unsecured Term Loan due 2021	23	—	23	—	—	2.22%
Partnership (TC PipeLines, LP and its subsidiaries)
Interest on Debt Obligations^(b)	436	79	114	94	149
Operating Leases	1	1	—	—	—
Right of Way commitments	4	1	1	—	2
	2,560	431	709	444	976

^(a)Fixed interest rate.

^(b)Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at June 30, 2020 and are therefore subject to change.

The ~~Partnership's~~Partnership’s long-term debt results in exposures to changing interest rates. The Partnership uses derivatives to assist in managing its exposure to interest rate risk. Refer to Item 3. “Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our derivatives.

The fair value of the ~~Partnership's~~Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The estimated fair value of the ~~Partnership's~~Partnership’s debt at ~~September~~June 30, ~~2019~~2020 was ~~$2,100~~$2,223 million.

Please read Note 7 within Item 1. “Financial Statements” for additional information regarding the ~~Partnership's~~Partnership’s debt.

~~Table of Contents~~

Summary of Northern ~~Border's~~Border’s Contractual Obligations

Northern ~~Border's~~Border’s contractual obligations as of ~~September~~June 30, ~~2019~~2020 included the following:

Payments Due by Period ^(a)












Weighted Average

Interest Rate for the
(unaudited)

Less than

1‑3

4‑5

More than 5

Nine Months Ended
(millions of dollars)

Total

1 Year

Years

Years

Years

September 30, 2019
$200 million Credit Agreement due 2024 ^(d)

115

—

—

—

115

3.53%
7.50% Senior Notes due 2021

250

—

250

—

—

7.50%^(b)
Interest payments on debt ^(c)

38

23

15

—

—


Right of way commitments

47

2

5

5

35



450

25

270

5

150

~~(a)~~

~~Represents 100 percent of Northern Border's debt obligations.~~

~~(b)~~

~~Fixed interest rate.~~

~~(c)~~

~~(d)~~

~~On October 1, 2019, Northern Border's $200 million Credit Agreement was extended to mature on October 1, 2024.~~


	Payments Due by Period ^(a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Six Months Ended June 30, 2020
$200 million Credit Agreement due 2024	120	—	—	120	—	2.21%
7.50% Senior Notes due 2021	250	—	250	—	—	7.50%	^(b)
Interest payments on debt ^(c)	29	20	7	2	—
Other commitments ^(d)	47	3	6	6	32
	446	23	263	128	32

^(a) Represents 100 percent of Northern Border’s debt obligations.

^(b) Fixed interest rate.

^(c) Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at June 30, 2020 and are therefore subject to change.

^(d) Future minimum payments for office space and rights-of-way commitments.

As of ~~September~~June 30, ~~2019, $115~~2020, $120 million was outstanding under Northern ~~Border's~~Border’s $200 million revolving credit agreement, leaving ~~$85~~$80 million available for future borrowings. At ~~September~~June 30, ~~2019,~~2020, Northern Border was in compliance with all of its financial covenants.

If needed, and subject to customary lender approval upon request, an additional $200 million of capacity is available under Northern Border's revolving credit agreement accordion feature.

Northern Border has commitments of $3$11 million as of ~~September~~June 30, ~~2019~~2020 in connection with compressor station overhauls and other capital projects.

Summary of Great ~~Lakes'~~Lakes’ Contractual Obligations

Great ~~Lakes'~~Lakes’ contractual obligations as of ~~September~~June 30, ~~2019~~2020 included the following:


	Payments Due by Period ^(a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Six Months Ended June 30, 2020
9.09% series Senior Notes due 2020 to 2021	20	10	10	—	—	9.09%	^(b)
6.95% series Senior Notes due 2020 to 2028	88	11	22	22	33	6.95%	^(b)
8.08% series Senior Notes due 2021 to 2030	100	10	20	20	50	8.08%	^(b)
Interest payments on debt ^(c)	74	16	24	17	17
Right of Way commitments	1	—	—	—	1
	283	47	76	59	101

^(a) Represents 100 percent of Great Lakes’ debt obligations.

Payments Due by Period ^(a)












Weighted Average

Interest Rate for the
(unaudited)

Less than

1‑3

4‑5

More than 5

Nine Months Ended
(millions of dollars)

Total

1 Year

Years

Years

Years

September 30, 2019
9.09% series Senior Notes due 2019 to 2021

30

10

20

—

—

9.09%^(b)
6.95% series Senior Notes due 2020 to 2028

99

11

22

22

44

6.95%^(b)
8.08% series Senior Notes due 2021 to 2030

100

—

20

20

60

8.08%^(b)
Interest payments on debt ^(c)

84

17

27

19

21


Right of way commitments

2

—

—

—

2



315

38

89

61

127

^(b) Fixed interest rate.

~~(a)~~

~~Represents 100 percent of Great Lakes' debt obligations.~~

~~(b)~~

~~Fixed interest rate.~~

~~(c)~~

~~Future interest payments on our fixed rate debt are based on scheduled maturities.~~

^(c) Future interest payments on our fixed rate debt are based on scheduled maturities.

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately ~~$123~~$112 million of Great ~~Lakes' partners'~~Lakes’ partners’ capital was restricted as to distributions as of ~~September~~June 30, ~~2019~~2020 (December 31, ~~2018 — $129~~2019 - $118 million). Great Lakes was in compliance with all of its financial covenants at ~~September~~June 30, ~~2019.~~

2020.

Great Lakes has commitments of $5$12 million as of ~~September~~June 30, ~~2019~~2020 in connection with pipeline integrity program spending, major overhaul projects, and right of way renewals.

~~Table of Contents~~

Summary of ~~Iroquois'~~Iroquois’ Contractual Obligations

~~Iroquois'~~

Iroquois’ contractual obligations as of ~~September~~June 30, ~~2019~~2020 included the following:

Payments Due by Period ^(a)












Weighted Average

Interest Rate for the
(unaudited)

Less than

1‑3

4‑5

More than 5

Nine Months Ended
(millions of dollars)

Total

1 Year

Years

Years

Years

September 30, 2019
4.12% series Senior Notes due 2034

140

—

—

—

140

4.12%^(b)
4.07% series Senior Notes due 2030

150

—

—

—

150

4.07%^(c)
6.10% series Senior Notes due 2027

32

5

7

8

12

6.10%^(b)
Interest payments on debt ^(d)

103

15

15

14

59


Transportation by others ^(e)

10

3

6

1

—


Operating leases

5

1

1

1

2


Pension contributions ^(f)

1

1

—

—

—



441

25

29

24

363

~~(a)~~

~~Represents 100 percent of Iroquois' debt obligations.~~

~~(b)~~

~~Fixed interest rate.~~

~~(c)~~

The refinancing agreement for 4.07% $150 million Senior Notes has a delay feature where Iroquois will not be paying any interest on the new 4.07% $150 million Senior Notes until the funds are drawn to repay the existing 4.84% $150 million Senior Notes in 2020. Iroquois will continue to pay the current interest rate of 4.84 percent until April 2020 when interest rate of 4.07% becomes effective.

~~(d)~~

~~Future interest payments on our fixed rate debt are based on scheduled maturities.~~

~~(e)~~

~~Future rates are based on known rate levels at September 30, 2019 and are therefore subject to change.~~

~~(f)~~

~~Pension contributions cannot be reasonably estimated by Iroquois.~~


	Payments Due by Period ^(a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Six Months Ended June 30, 2020
4.12% series Senior Notes due 2034	140	—	—	—	140	4.12%	^(b)
4.07% series Senior Notes due 2030	150	—	—	—	150	4.07%
6.10% series Senior Notes due 2027	28	4	8	8	8	6.10%	^(b)
Interest payments on debt ^(c)	148	14	26	25	83
Transportation by others^(d)	7	3	4	—	—
Operating leases	11	1	2	5	3

	484	22	40	38	384

^(a) Represents 100 percent of Iroquois’ debt obligations.

^(b) Fixed interest rate.

^(c) Future interest payments on our fixed rate debt are based on scheduled maturities.

^(d) Future rates are based on known rate levels at June 30, 2020 and are therefore subject to change.

Iroquois has no capital commitments ~~of $54 million~~ as of ~~September~~June 30, ~~2019 related to procurement of materials on its expansion project.~~

On May 9, 2019, Iroquois refinanced its 6.63% $140 million and 4.84% $150 million Senior Notes due in 2019 and 2020, respectively, by issuing new 15-year 4.12% $140 million and new 10-year 4.07% $150 million Senior Notes.

2020.

Iroquois is restricted under the terms of its note purchase agreement from making cash distributions to its partners unless certain conditions are ~~met, which remained unchanged with the refinancing transaction.~~met. Before a distribution can be made, the ~~debt/~~debt to capitalization ratio must be below 75 percent and the debt service coverage ratio must be at least 1.25 times for the four preceding quarters. At ~~September~~June 30, ~~2019,~~2020, the ~~debt/~~debt to capitalization ratio was ~~52.2~~52.6 percent and the debt service coverage ratio was ~~5.31~~6.29 times; therefore, Iroquois was not restricted from making any cash distributions.

RELATED PARTY TRANSACTIONS

Please read Note 12 within Item 1. “Financial Statements” for information regarding related party transactions.

Item 3.Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

The Partnership and our pipeline systems are exposed to market risk, counterparty credit risk, and liquidity risk. Our exposure to market risk discussed below includes forward-looking statements and is not necessarily indicative of actual results, which may not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual market conditions.

Our primary risk management objective is to mitigate the impact of these risks on earnings and cash flow, and ultimately, unitholder value. We do not use financial instruments for trading purposes.

~~Table of Contents~~

We record derivative financial instruments on the consolidated balance sheet as assets and liabilities at fair value. We estimate the fair value of derivative financial instruments using available market information and appropriate valuation techniques. Changes in the fair value of derivative financial instruments are recognized in earnings unless the instrument qualifies as a hedge and meets specific hedge accounting criteria. Qualifying derivative financial ~~instruments'~~instruments’ gains and losses may offset the hedged ~~items'~~items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.

MARKET RISK

From time to time, and in order to finance our business and that of our pipeline systems, the Partnership and our pipeline systems issue debt to invest in growth opportunities and provide for ongoing operations. The issuance of floating rate debt exposes the Partnership and our pipeline systems to market risk from changes in interest rates which affect earnings and the value of the financial instruments we hold.

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. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

LIBOR, which is set to be phased out at the end of 2021, is used as a reference rate for certain of our financial instruments, including the ~~Partnership's~~Partnership’s term loans, revolving credit facilities and the interest rate swap agreements that we use to manage our interest rate exposure. We are reviewing how the expected LIBOR phase-out will affect the Partnership, ~~but we~~including the possibility of a delay in adopting a new benchmark due to the uncertainty surrounding the COVID-19 pandemic. We currently do not expect the impact to be material.

As of ~~September~~June 30, ~~2019,~~2020, the ~~Partnership's~~Partnership’s interest rate exposure resulted from our floating rate on North ~~Baja's~~Baja’s Unsecured Term Loan Facility, ~~PNGTS'~~PNGTS’ Revolving Credit Facility and ~~Tuscarora's~~Tuscarora’s Unsecured Term Loan Facility, under which ~~$103~~$144 million, or 57 percent, of our outstanding debt was subject to variability in LIBOR interest rates (December 31, ~~2018- $168~~2019 - $112 million or 86 percent).

As of ~~September~~June 30, ~~2019,~~2020, the variable interest rate exposure related to our 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 3.26 percent. If interest rates hypothetically increased (decreased) on these facilities by one percent (100 basis points), compared with rates in effect at ~~September~~June 30, ~~2019,~~2020, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $1 million.

As of ~~September~~June 30, ~~2019, $115~~2020, $120 million, or 32 percent, of Northern ~~Border's~~Border’s outstanding debt was at floating rates. If interest rates hypothetically increased (decreased) by one percent (100 basis points), compared with rates in effect at ~~September~~June 30, ~~2019,~~2020, Northern ~~Border's~~Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately $1 million.

~~GTN's Unsecured Senior Notes,~~

Northern ~~Border's~~Border’s and ~~Iroquois'~~Iroquois’ Senior Notes, and all of Great ~~Lakes'~~Lakes’ and ~~PNGTS'~~GTN's Notes represent fixed-rate ~~debt;~~debt, and are therefore ~~they are~~ not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison, as Bison does not have any debt.

The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to assist in managing exposures to market risk resulting from these activities within established policies and procedures. We do not enter into derivatives for speculative purposes. Derivative contracts used to manage market risk generally consist of the following:

•

●

~~Swaps — contractual agreements between two parties to exchange streams of payments over time according to specified terms.~~

Swaps - contractual agreements between two parties to exchange streams of payments over time according to specified terms.

●

Options — contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period.

•

Options - contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period.

The ~~Partnership's~~Partnership and our pipeline systems enter into interest rate swaps ~~mature on October 2, 2022~~ and ~~are structured such that~~option agreements to mitigate the ~~cash flows~~impact 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 amountchanges in interest ~~rate~~rates. For details regarding our current interest swaps ~~that were used~~and other agreements related to ~~hedge this facility at a rate~~mitigation of ~~2.81 percent (See also~~impact on changes in interest rates, see Note 13 within Part I, Item 1. ~~"Financial Statements").~~

“Financial Statements,” which information is incorporated herein by reference.

~~Table of Contents~~

At September 30, 2019, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $8 million (both on a gross and net basis) (December 31, 2018 - asset of $8 million), the net change of which is recognized in other comprehensive income. For the three and nine months ended September 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 (September 30, 2018 - nil and gain of $2 million, respectively).

COMMODITY PRICE RISK

The Partnership is influenced by the same factors that influence our pipeline systems. None of our pipeline systems own any of the natural gas they transport; therefore, they do not assume any of the related natural gas commodity price risk with respect to transported natural gas volumes.

COUNTERPARTY CREDIT RISK ~~AND LIQUIDITY RISK~~

Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the financial instruments with the Partnership or its pipeline systems.

The Partnership has exposure to counterparty credit risk in the following areas:

•

●

cash and cash equivalents;

•accounts receivable and other receivables; and

•the fair value of derivative assets

~~cash and cash equivalents~~

●

~~accounts receivable and other receivables~~

●

~~the fair value of derivative assets~~

At ~~September~~June 30, ~~2019,~~2020, we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired. As noted in our 2019 Annual Report, a significant portion of our long-term contract revenues are with counterparties who have an investment grade rating or who have provided guarantees from investment grade parties. Additionally, during the three ~~and nine~~ months ended ~~September~~June 30, ~~2019~~2020 and at ~~September~~June 30, ~~2019,~~2020, no ~~customer~~counterparty accounted for more than 10 percent of either our consolidated revenue ~~and~~or accounts ~~receivable, respectively.~~

receivable.

The Partnership and our pipeline systems have significant credit exposure to financial institutions as they hold cash deposits and provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to ~~non-creditworthy~~non-credit worthy customers.

The Partnership closely monitors the creditworthiness of our counterparties, including financial institutions, reviews accounts receivable regularly and, if needed, requests financial assurances in accordance with our pipeline tariffs and records allowances for doubtful accounts using the specific identification method. However, we ~~cannot~~are not able to predict with certainty the extent to ~~what extent~~which our business ~~would~~could be impacted by the uncertainty ~~in energy commodity~~surrounding the COVID-19 pandemic or the prolonged impact of low oil prices, including possible declines in our ~~customers'~~counterparties' creditworthiness.

The factors described above have been incorporated by the Partnership as part of the Measurement of credit losses on financial instruments accounting standard that became effective on January 1, 2020 as described in more detail under Note 3 within Item 1. “Financial Statements.” The Partnership believes the factors as described above are considered to have a negligible impact considering the portfolio of counterparties held by our pipeline assets.

LIQUIDITY RISK

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they become due. We manage our liquidity risk by continuously forecasting our cash flow on a regular basis to ensure we have adequate cash balances, cash flow from operations and credit facilities to meet our operating, financing and capital expenditure obligations when due, under both normal and stressed conditions. ~~Refer~~As discussed previously, global market volatility has heightened and liquidity has tightened but we have taken steps to ~~“Liquidity~~mitigate our risk. Please see "Liquidity and Capital ~~Resources” section~~Resources" within Item 2 for more information about our liquidity.

Item 4.Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act) the management of our General Partner, including the principal executive officer and principal financial officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. The ~~Partnership's~~Partnership’s disclosure controls and procedures are designed to provide reasonable assurance of

~~Table of Contents~~

achieving their objectives. Based upon and as of the date of the evaluation, the management of our General Partner, including the principal executive officer and principal financial officer, concluded that the ~~Partnership's~~Partnership’s disclosure controls and procedures as of the end of the period covered by this quarterly report were effective to provide reasonable assurance that the information required to be disclosed by the Partnership in the reports that it files or submits under the Exchange Act, is (a) recorded, processed, summarized and reported within the time periods specified in the ~~SEC's~~SEC’s rules and forms and (b) accumulated and communicated to the management of our General Partner, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the quarter ended ~~September~~June 30, ~~2019,~~2020, there was no change in the ~~Partnership's~~Partnership’s internal control over financial reporting that ~~has~~ materially affected or is reasonably likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various legal proceedings that arise in the ordinary course of business, as well as proceedings that we consider material under federal securities regulations. For additional information on other legal and environmental proceedings affecting the Partnership, please refer to Part 1 - Item 3 of ~~the Partnership's~~our 2019 Annual Report ~~on Form 10-K for the year ended December 31, 2018.~~

and Part I-Other Recent

Business Developments-Northern Border within Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Item 1A. Risk Factors

The following updated risk factors should be read in conjunction with the risk factors disclosed in Part I, Item 1A. “Risk Factors,” in our 2019 Annual Report.

We face various risks and uncertainties beyond our control, such as recent public health concerns related to the COVID-19 pandemic, which could have a materially adverse impact on our business, financial condition and results of operation.

On March 11, 2020, the WHO declared COVID-19, a global pandemic. In addition, the spread of the COVID-19 virus across the globe has impacted financial markets and global economic activity. These impacts include supply chain disruptions, massive unemployment and a decrease in commercial and industrial activity around the world. The impact of the COVID-19 pandemic, compounded by the recent collapse in crude oil markets, has resulted in significant market disruption.

Our ability to access the debt market or borrowings under our debt agreements to fund our significant capital expenditures could be negatively impacted due to uncertainty in the current market environment. The COVID-19 pandemic could also lead to a general slowdown in construction activities related to our capital projects. However, there is no information available at this time that would allow us to quantify the impact such delay may have on the completion of our capital projects. Finally, if COVID-19 were to impact a location where we have a high concentration of business and resources, our local workforce could be affected by such an occurrence or outbreak which could also significantly disrupt our operations and decrease our ability to service our customers.

While we have not seen any material impact of the COVID-19 pandemic on our business to date, it is difficult to predict how significant the impact of the COVID-19 virus, including any responses to it, will be on the global economy and our business or for how long any disruptions are likely to continue. The extent of such impact will depend on future developments, which are highly uncertain, including new information which may emerge concerning the severity of the COVID-19 pandemic and additional actions which may be taken to contain the further spread of the COVID-19 virus. Even after the COVID-19 pandemic has subsided, our business may be adversely impacted by the economic downturn or a recession that has occurred or may occur in the future. The COVID-19 pandemic could also increase or trigger other risks discussed in our Annual Report on Form 10-K for the ~~year ended~~year-ended December 31, ~~2018.~~

~~We do not own the majority~~2019, any of ~~the land~~which could have a materially adverse impact on ~~which~~ our ~~pipeline systems are located, which~~business, financial condition and results of operation.

Prolonged low oil and natural gas prices could result in ~~higher costs~~supply and ~~disruptions~~demand imbalances that impact availability of natural gas for transportation on our pipeline systems.

In early March 2020, the market experienced a precipitous decline in crude oil prices in response to ~~our operations, particularly with respect~~oil oversupply and demand concerns due to ~~easements and rights-of-way across Indian tribal lands.~~

~~We do not own~~ the ~~majority~~economic impacts of the ~~land on which our pipeline systems are located. We obtain easements, rights-of-way~~COVID-19 pandemic. Additionally, in April 2020, extreme shortages of transportation and ~~other rights~~storage capacity caused the New York Mercantile Exchange (NYMEX) West Texas Intermediate oil futures price to ~~construct~~go as low as approximately negative $37. This negative pricing resulted from the holders of expiring front month oil purchase contracts being unable or unwilling to take physical delivery of crude oil and ~~operate our pipeline systems~~accordingly forced to make payments to purchasers of such contracts in order to transfer the corresponding purchase obligations.

Although oil prices have partially recovered from ~~individual landowners, Native American tribes, governmental authorities~~what was experienced in April, the COVID-19 pandemic and ~~other third parties. Some of these rights expire after~~economic downturn could further negatively impact domestic and international demand for crude oil and natural gas and a ~~specified~~prolonged period of ~~time. As a result, we are subject~~low crude oil and natural gas prices would negatively impact exploration and development of new crude oil and natural gas supplies. In response to the ~~possibility~~sharp decline in oil and natural gas prices, many producers have announced cuts or suspension of ~~more onerous terms~~exploration and ~~increased costs~~production activities and some state regulators are considering mandating the proration of production of hydrocarbons. A drilling reduction could impact the availability of natural gas to ~~renew expiring easements, rights-of-way~~be transported by our pipelines. Sustained low oil and other land use rights. While we are generally able to obtain these rights through agreement with land owners or legal process if necessary, rights-of-way across Indian tribal land require approval of the applicable tribal governing authority and the Bureau of Indian Affairs. If efforts to retain existing land use rights on tribal land at a reasonable cost are unsuccessful, our pipeline systemsnatural gas prices could also ~~be subject to a disruption of operations~~impact counterparties’ creditworthiness and increased costs to re-route the applicable portion of our pipeline system located on tribal land. Increased costs associated with renewing or obtaining new easements or rights-of-way and any disruption of operations could negatively impact the results of operations and cash available for distribution from our pipeline systems.

Our Great Lakes pipeline system had rights-of-way that expired during the second quarter of 2018 on approximately 7.6 miles of pipeline across tribal land located within the Fond du Lac Reservation and Leech Lake Reservation in Minnesota and the Bad River Reservation in Wisconsin. We are negotiating to obtain new rights-of-way with the tribal authorities and are entitled to continue operating the Great Lakes pipeline as long as good faith negotiations with the tribal authorities to obtain the new rights-of-way continues.

On April 1, 2019, Great Lakes received notice from the Fond du Lac Tribal Chairman to immediately cease operations of the Great Lakes pipeline and begin the process of removing all infrastructure from the tribal land to which Great Lakes responded in an effort to negotiate a mutually acceptable renewal agreement. On May 23, 2019, the Fond du Lac tribe provided Great Lakes with a Memorandum of Agreement (“MOA”) establishing a process to compensate the tribe for its negotiation expenses.

~~Great Lakes continues to negotiate with Fond du Lac, Bad River and Leech Lake representatives to resolve the lease issues for all three tribes.~~

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If discussions with any of the three tribes ultimately are unsuccessful or the cost of renewal is significantly high, we could be required or choose to remove and relocate a portion or portions of the Great Lakes pipeline system from the tribal lands at a significant cost. While the outcome of these negotiations or thetheir ability to ~~reach agreements is uncertain, the impact of a disruption of operations and~~meet their transportation service cost ~~of relocating a portion of the Great Lakes pipeline or significantly increased costs to renew the rights-of-way~~obligations. Such developments could have ~~a material~~an adverse effect on our assets, liabilities, business, financial condition, results of operations and cash ~~flows.~~

Chemical substances in the natural gas our pipeline systems transport could cause damage or affect the ability of our pipeline systems' or third-party equipment to function properly, which may result in increased preventative and corrective action costs.

GTN has identified the presence of a chemical substance, dithiazine, at several facilities on the GTN system as well as some upstream and downstream connecting pipeline facilities. Certain customers have also followed complaint procedures set forth in GTN’s FERC Gas Tariff to communicate regarding dithiazine-related matters, and GTN will follow its tariff procedures in responding. Dithiazine is a byproduct of triazine which is a liquid chemical scavenger known to be used in natural gas processing to remove hydrogen sulfide from natural gas. It has been determined that dithiazine may drop out of gas streams, under certain conditions, in a powdery form at some points of pressure reduction (for example, at a regulator). In incidents where a sufficient quantity of the material accumulates in certain appurtenances, improper functioning of equipment can and has occurred, resulting in increased preventative and corrective action costs.

While we believe that the presence of dithiazine on the GTN system is from upstream-sourced gas, we have advised stakeholders of potential risks, mitigation efforts and safety measures. We are following appropriate inspection and maintenance protocols to minimize any safety issues to people, equipment or the environment on our pipeline system. TC Energy has been engaging producers and other users of triazine in an effort to mitigate the presence of dithiazine in pipelines upstream of our GTN pipeline system. Multiple fouling incidents, and at least one overpressure incident, potentially related to dithiazine have been reported on customer systems. Certain customers have questioned whether the presence of dithiazine in gas shipped on GTN meets the standard of GTN’s tariff. In response, GTN has communicated that the gas transported by GTN satisfies the standards of its tariff, and that GTN disagrees with any assertions to the contrary. Additionally, GTN and TC Energy are gathering information and working with customers, producers, vendors, and other stakeholders in an effort to develop and implement a collaborative plan to address the issue, and have informed federal and state regulators, trade associations and other stakeholders of the issue. At the same time, GTN has taken steps and made capital expenditures to address the matter. In 2018, we incurred capital expenditures of approximately $5 million and, unless the issue is resolved, we expect to spend approximately $10 million to $12 million in 2019 and 2020 in aggregate to further mitigate the matter. There can be no assurance that significant additional costs will not be incurred in the future or that dithiazine or other substances will not be identified on our other pipeline systems.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships including legislative proposals that would have eliminated the qualifying income exception we rely upon; thus, treating all publicly traded partnerships as corporations for U.S. federal income tax purposes. For example, the "Clean Energy for America Act", which is similar to legislation that was proposed during the Obama Administration, was introduced in the Senate on May 2, 2019. If enacted, this proposal would, among other things, repeal Section 7704(d)(1)(E) of the Internal Revenue Code, upon which we rely for our status as a partnership for U.S. federal income tax purposes.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department's interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a publicly traded partnership in the future. We believe the income that we treat as qualifying satisfies the requirements under current regulations.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

flow.

~~Table of Contents~~

Item 6.Exhibits

Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.


3.1		Certificate of Limited Partnership of TC PipeLines, LP (Incorporated by reference to Exhibit 3.2 to TC PipeLines, LP's Form S-1 Registration Statement, filed on December 30, 1998).
3.2		Conformed Copy of Fourth Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP ~~dated~~(incorporating Amendment No. 1, thereto, entered into on February 4, 2020 and effective as of December 31, ~~2018 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP's Form 8-K filed January 2, 2019).~~
~~4.1~~	~~Indenture, dated as of June 17, 2011, between the Partnership and The Bank of New York Mellon, as trustee~~2018) (Incorporated by reference to Exhibit ~~4.1~~3.2 to TC PipeLines, LP's Annual Report on Form ~~8-K filed on June 17, 2011)~~10-K for the year ended December 31, 2019).
~~4.2~~ 31.1*		Supplemental Indenture, dated as of June 17, 2011 relating to the issuance of $350,000,000 aggregate principal amount of 4.65% Senior Notes due 2021 (Incorporated by reference to Exhibit 4.2 to TC PipeLines, LP's Form 8-K filed on June 17, 2011).
~~4.3~~	~~Specimen of 4.65% Senior Notes due 2021 (Incorporated by reference to Exhibit A to the Supplemental Indenture filed as Exhibit 4.2 to TC PipeLines, LP's Form 8-K filed on June 17, 2011).~~
~~4.4~~	~~Form of indenture for senior debt securities (Incorporated by reference to Exhibit 4.1 to TC PipeLines, LP's Form 8-K filed on June 14, 2011).~~
~~4.5~~	Second Supplemental Indenture, dated March 13, 2015, between TC PipeLines, LP and The Bank of New York Mellon (Incorporated by reference from Exhibit 4.1 to TC PipeLines, LP's Form 8-K filed March 13, 2015).
~~4.6~~	Third Supplemental Indenture, dated as of May 25, 2017, relating to the issuance of $500,000,000 aggregate principal amount of 3.900% Senior Notes due 2027 (Incorporated by reference from Exhibit 4.2 to TC PipeLines, LP's Form 8-K filed May 25, 2017).
31.1*	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Principal ~~Executive~~Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101
~~101~~	The following materials from TC Pipelines, LP's Quarterly Report on Form 10-Q for the period ended ~~September~~June 30, ~~2019~~2020 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements Comprehensive Income, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statement of Cash Flows, (v) the Consolidated Statement of Changes in Partners' Equity, and (vi) the Condensed Notes to Consolidated Financial Statements (Unaudited).
104		Cover Page Interactive Data File (embedded within the Inline XBRL document)

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 75^th day of ~~November 2019.~~

August 2020.


			TC PIPELINES, LP
			(A Delaware Limited Partnership)
			by its General Partner, TC PipeLines GP, Inc.

			By:			/s/ Nathaniel A. Brown
						Nathaniel A. Brown
						President
						TC PipeLines GP, Inc. (Principal Executive Officer)

			By:			/s/ William C. Morris
						William C. Morris
						Vice President and Treasurer
						TC PipeLines GP, Inc. (Principal Financial Officer)

~~Delaware~~	~~52-2135448~~
Delaware		52-2135448
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)



700 Louisiana Street,, Suite 700 Houston,, Texas	77002-2761
(Address of principal executive offices)		(Zip code)


Title of each class	Trading Symbol(s)	Trading Symbol(s)	Name of each exchange on which registered
Common units representing limited partner interests	TCP	~~TCP~~	New York Stock Exchange


Large accelerated filer x	☒	Accelerated filer	☐
Non-accelerated filer ☐ (Do not check if a smaller reporting company)	☐	Smaller reporting company	☐
Emerging growth company	☐

	~~Page No.~~
~~PART I~~		~~FINANCIAL INFORMATION~~	Page No.

PART I		FINANCIAL INFORMATION

Item 1.		Consolidated Financial Statements (Unaudited)	7
		Condensed Notes to Consolidated Financial Statements	12
Item 2.		~~Management's~~Management’s Discussion and Analysis of Financial Condition and Results of Operations	28 26
Item 3.		Quantitative and Qualitative Disclosures About Market Risk	42 41
Item 4.		Controls and Procedures	44 43

PART II		OTHER INFORMATION

Item 1.		Legal Proceedings	45 43
Item 1A.		Risk Factors	45
Item 6.		Exhibits	47 46
		Signatures	48 47


2013 Term Loan Facility			TC PipeLines, ~~LP's~~LP’s term loan credit facility under a term loan agreement as amended, dated September 29, 2017
~~2017 Tax Act~~ AFUDC		Allowance for funds used during construction	~~Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act, enacted on December 22, 2017~~
~~2018 FERC Actions~~ ANR		ANR Pipeline Company	FERC's 2018 issuance of 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
~~2019 Iroquois Settlement~~ ASC			An uncontested settlement filed by Iroquois with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
~~2019 Tuscarora Settlement~~	An uncontested settlement filed by Tuscarora with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
~~ADIT~~	~~Accumulated Deferred Income Tax~~
~~ASC~~	Accounting Standards Codification
~~ATM program~~ AOCI		Accumulated other comprehensive income	~~At-the-market equity issuance program~~
Bison			Bison Pipeline LLC
Class B Distribution			Annual distribution to TC Energy based on 30 percent of ~~GTN's~~GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter
Class B Reduction			Approximately 35 percent reduction applied to the estimated annual Class B Distribution beginning in 2018, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit
~~DOT~~ COVID-19		Coronavirus 2019
DOT		U.S. Department of Transportation
EBITDA			Earnings Before Interest, Tax, Depreciation and Amortization
EPA			U.S. Environmental Protection Agency
~~FASB~~ ExC Project		Iroquois Enhancement by Compression project that involves upgrading its compressor stations along the pipeline and provides approximately 125,000 Dth/day of additional firm transportation service to meet current and future gas supply needs of utility customers
FASB		Financial Accounting Standards Board
FERC			Federal Energy Regulatory Commission
GAAP			U.S. generally accepted accounting principles
General Partner			TC PipeLines GP, Inc.
Great Lakes			Great Lakes Gas Transmission Limited Partnership
GTN			Gas Transmission Northwest LLC
GTN ~~Xpress~~ XPress			GTN’s project to both increase the reliability of existing transportation service on GTN and to provide for 250,000 Dth/day of incremental transportation volumes, primarily through facility replacements and additions of existing brownfield compression sites.
IDRs			Incentive Distribution Rights
~~ILPs~~ Iroquois			~~Intermediate Limited Partnerships~~
~~Intermediate GP~~	~~TC PipeLines Intermediate GP, LLC~~
~~Iroquois~~	Iroquois Gas Transmission System, L.P.
LIBOR			London Interbank Offered Rate
~~MAOP~~ LNG		Liquified natural gas	~~Maximum Allowable Operating Pressure~~
MLP		Master Limited Partnership
North Baja			North Baja Pipeline, LLC
Northern Border			Northern Border Pipeline Company
NYMEX		New York Mercantile Exchange
Our pipeline systems			Our ownership interests in GTN, Northern Border, Bison, Great Lakes, North Baja, Tuscarora, PNGTS and Iroquois
Partnership			TC PipeLines, LP including its subsidiaries, as applicable


Partnership Agreement						Fourth Amended and Restated Agreement of Limited Partnership of the Partnership


	Three months ended				Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars, except per common unit amounts)	2019		2018		2019		2018
Transmission revenues		93		103		299		328
Equity earnings (Note 5)		31		34		115		129
Operation and maintenance expenses		(18)		(15)		(51)		(48)
Property taxes		(6)		(7)		(19)		(21)
General and administrative		(2)		(2)		(6)		(4)
Depreciation and amortization		(19)		(25)		(58)		(73)
Financial charges and other (Note 15)		(20)		(23)		(63)		(69)
Net income before taxes		59		65		217		242
Income taxes		—		—		(1)		(1)
Net income		59		65		216		241
Net income attributable to non-controlling interest		3		3		12		10
Net income attributable to controlling interests		56		62		204		231

Net income attributable to controlling interest allocation (Note 9)
Common units		54		57		199		222
General Partner		1		1		4		5
Class B units		1		4		1		4
		56		62		204		231

Net income per common unit (Note 9) – basic and diluted	$	0.76	$	0.79	$	2.79	$	3.11
Weighted average common units outstanding – basic and diluted (millions)		71.3		71.3		71.3		71.3
Common units outstanding, end of period (millions)		71.3		71.3		71.3		71.3


(unaudited)
(millions of dollars)	September 30, 2019	December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	90	33
Accounts receivable and other (Note 14)	39	48
Inventories	9	8
Other	2	8
	140	97
Equity investments (Note 5)	1,094	1,196
Property, plant and equipment
(Net of $1,163 accumulated depreciation; 2018 - $1,110)	1,517	1,529
Goodwill	71	71
Other assets	—	6
TOTAL ASSETS	2,822	2,899

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities	31	36
Accounts payable to affiliates (Note 12)	6	6
Accrued interest	20	12
Current portion of long-term debt (Note 7)	123	36
	180	90
Long-term debt, net (Note 7)	1,871	2,072
Deferred state income taxes	9	9
Other liabilities	36	29
	2,096	2,200
Partners’ Equity
Common units	522	462
Class B units (Note 8)	96	108
General partner	14	13
Accumulated other comprehensive income (loss) (AOCI)	(8)	8
Controlling interests	624	591
Non-controlling interests	102	108
	726	699
TOTAL LIABILITIES AND PARTNERS' EQUITY	2,822	2,899


						Accumulated
						Other	Non-
	Limited Partners				General	Comprehensive	Controlling	Total
	Common Units		Class B Units		Partner	Income (Loss) ^(a)	Interest	Equity
	millions	millions	millions	millions of	millions of	millions of	millions of	millions of
(unaudited)	of units	of dollars	of units	dollars	dollars	dollars	dollars	dollars
Partners' Equity at December 31, 2018	71.3	462	1.9	108	13	8	108	699
Net income	—	199	—	1	4	—	12	216
Other comprehensive income (loss)	—	—	—	—	—	(16)	—	(16)
Distributions (Note 10)	—	(139)	—	(13)	(3)	—	(18)	(173)
Partners' Equity at September 30, 2019	71.3	522	1.9	96	14	(8)	102	726


	Ownership		Equity Earnings				Equity Investments
	Interest at		Three months ended		Nine months ended
(unaudited)	September 30,		September 30,		September 30,		September 30,	December 31,
(millions of dollars)	2019		2019	2018	2019	2018	2019	2018
Northern Border	50.00	%	15	16	50	49	426	497
Great Lakes	46.45	%	8	9	37	45	482	489
Iroquois	49.34	%	8	9	28	35	186	210
			31	34	115	129	1,094	1,196


		Weighted Average				Weighted Average
		Interest Rate for the				Interest Rate for the
(unaudited)		Nine months ended			December 31,	Year Ended
(millions of dollars)	September 30, 2019	September 30, 2019			2018	December 31, 2018
TC PipeLines, LP
Senior Credit Facility due 2021	—	—			40	3.14	%
2013 Term Loan Facility due 2022	450	3.66	%		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	30	3.65	%		19	3.55	%

Tuscarora
Unsecured Term Loan due 2020	23	3.54	%		24	3.10	%

North Baja
Unsecured Term Loan due 2021	50	3.48	%		50	3.54	%
	2,003				2,118
Less: unamortized debt issuance costs and debt discount	9				10
Less: current portion	123				36
	1,871				2,072


(unaudited)
(millions of dollars)		Principal Payments
2019		—
2020		123
2021		400
2022		450
2023		30
Thereafter		1,000
		2,003


(unaudited)	Three months ended September 30,				Nine months ended September 30,
(millions of dollars, except per common unit amounts)	2019		2018		2019		2018
Net income attributable to controlling interests		56		62		204		231
Net income attributable to the Class B units^(a)		(1)		(4)		(1)		(4)
Net income attributable to the General Partner and common units		55		58		203		227
Net income attributable to the General Partner		(1)		(1)		(4)		(5)
Net income attributable to common units		54		57		199		222
Weighted average common units outstanding (millions) – basic and diluted		71.3		71.3		71.3		71.3
Net income per common unit – basic and diluted	$	0.76	$	0.79	$	2.79	$	3.11


	Payments Due by Period
						Weighted Average
						Interest Rate for
						the Nine Months
(unaudited)		Less than	1‑3	4‑5	More than 5	Ended September 30,
(millions of dollars)	Total	1 Year	Years	Years	Years	2019
TC PipeLines, LP
Senior Credit Facility due 2021	—	—	—	—	—	— %
2013 Term Loan Facility due 2022	450	—	—	450	—	3.66%
4.65% Senior Notes due 2021	350	—	350	—	—	4.65%	^(a)
4.375% Senior Notes due 2025	350	—	—	—	350	4.375%	^(a)
3.90% Senior Notes due 2027	500	—	—	—	500	3.90%	^(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	100	—	—	—	5.29%	^(a)
5.69% Unsecured Senior Notes due 2035	150	—	—	—	150	5.69%	^(a)
PNGTS
Revolving Credit Facility due 2023	30	—	—	30	—	3.65%
North Baja
Unsecured Term Loan due 2021	50	—	50	—	—	3.48%
Tuscarora
Unsecured Term Loan due 2020	23	23	—	—	—	3.54%
Partnership (TC PipeLines, LP and its subsidiaries)
Interest on Debt Obligations^(b)	466	87	139	88	152
Operating Leases	1	—	1	—	—
Right of Way commitments	4	1	—	1	2
	2,474	211	540	569	1,154