UNITED STATES

~~UNITED STATES~~ SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

~~FORM 10-Q~~☒

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, ~~2017~~2019

o☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-35358

TC PipeLines, LP

(Exact name of registrant as specified in its charter)

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 ~~principle~~principal executive offices)		(Zip code)

877-290-2772

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ⌧ No ◻

~~Yes~~ x No o

Securities registered pursuant to Section 12(b) of the Exchange Act:

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

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files).

Yes⌧ No ◻

~~Yes~~ x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o☐No x☒

As of November ~~3, 2017,~~5, 2019, there were ~~69,881,012~~71,306,396 of the registrant’s common units outstanding.

Table of Contents

TC PIPELINES, LP

TABLE OF CONTENTS

All amounts are stated in United States dollars unless otherwise indicated.

Table of Contents

DEFINITIONS

The abbreviations, acronyms, and industry terminology used in this quarterly report are defined as follows:

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
~~2015 GTN Acquisition~~2017 Tax Act		~~Partnership’s acquisition of~~Public Law No. 115-97, commonly known as the ~~remaining 30 percent interest in GTN~~Tax Cuts and Jobs Act, enacted on ~~April 1, 2015~~
~~2015 Term Loan Facility~~		~~TC PipeLines, LP’s term loan credit facility under a term loan agreement as amended, dated September 29,~~December 22, 2017
~~2016 PNGTS Acquisition~~2018 FERC Actions		~~Partnership’s acquisition~~FERC's 2018 issuance of Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a ~~49.9 percent interest in PNGTS, effective January 1, 2016~~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
~~2017 Acquisition~~2019 Iroquois Settlement		~~Partnership’s acquisition of~~An uncontested settlement filed by Iroquois with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an ~~additional 11.81 percent interest in PNGTS~~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 ~~49.34 percent in Iroquois~~2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on ~~June 1, 2017~~May 2, 2019
ADIT		Accumulated Deferred Income Tax
ASC		Accounting Standards Codification
~~ASU~~		~~Accounting Standards Update~~
ATM program		At-the-market equity issuance program
Bison		Bison Pipeline LLC
~~Consolidated Subsidiaries~~Class B Distribution		~~GTN, Bison, North Baja, Tuscarora~~Annual distribution to TC Energy based on 30 percent of GTN's annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and ~~PNGTS~~(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		U.S. Department of Transportation
EBITDA		Earnings Before Interest, Tax, Depreciation and Amortization
EPA		U.S. Environmental Protection Agency
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		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		Intermediate Limited Partnerships
Intermediate GP		TC PipeLines Intermediate GP, LLC
Iroquois		Iroquois Gas Transmission System, L.P.
LIBOR		London Interbank Offered Rate
~~NGA~~MAOP		~~Natural Gas Act of 1938~~Maximum Allowable Operating Pressure
North Baja		North Baja Pipeline, LLC
Northern Border		Northern Border Pipeline Company
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		~~Third~~Fourth Amended and Restated Agreement of Limited Partnership of the Partnership

Table of Contents

PHMSA		~~U.S. Department of Transportation~~The Pipeline and Hazardous Materials Safety Administration
PNGTS		Portland Natural Gas Transmission System
~~Term Loan Facilities~~PXP		~~The 2013 Term Loan Facility and the 2015 Term Loan Facility, collectively~~Portland XPress Project
ROU		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
~~TransCanada~~TC Energy		TC Energy Corporation formerly known as TransCanada Corporation ~~and its subsidiaries~~
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
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

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).

Table of Contents

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. 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.

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

· ~~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; and~~

· ~~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;~~

· changes in the taxation of master limited partnerships by state or federal governments such as final adoption of proposed regulations narrowing the sources of income qualifying for partnership tax treatment or 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), the 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, terms and closure of future potential acquisitions;~~

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

· ~~the impact of any impairment charges;~~

· ~~cybersecurity threats, acts of terrorism and related disruptions;~~

· ~~the impact of new accounting pronouncements;~~

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

· ~~the level of our indebtedness, including the indebtedness of our pipeline systems, and the availability of capital; and~~

· ~~the overall increase in the allocated management and operational expenses on our pipeline systems as performed by TransCanada~~

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, ~~2016~~2018 as filed with the SEC on February ~~28, 2017.~~21, 2019. 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)

2017

2016 (a)

2017

2016 (a)

Transmission revenues

100

103

313

315

Equity earnings (Note 4)

27

22

87

75

Operation and maintenance expenses

(16
)
(15
)
(47
)
(42
)
Property taxes

(7
)
(7
)
(21
)
(20
)
General and administrative

(1
)
(1
)
(6
)
(5
)
Depreciation

(25
)
(24
)
(73
)
(71
)
Financial charges and other (Note 14)

(23
)
(18
)
(59
)
(53
)
Net income before taxes

55

60

194

199

Income taxes (Note 18)

—

—

(1
)
(1
)
Net income

55

60

193

198

Net income attributable to non-controlling interests

1

2

7

10

Net income attributable to controlling interests

54

58

186

188

Net income attributable to controlling interest allocation (Note 8)

Common units

42

43

164

164

General Partner

4

4

12

9

TransCanada and its subsidiaries

8

11

10

15

54

58

186

188

Net income per common unit (Note 8) — basic and diluted

$
0.61

$
0.65
(b)
$
2.38

$
2.51
(b)

Weighted average common units outstanding — basic and diluted (millions)

69.4

66.1

68.9

65.3

Common units outstanding, end of period (millions)

69.6

66.6

69.6

66.6

~~(a)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).~~

~~(b)~~ ~~Net income per common unit prior to recast (Refer to Note 2).~~

T~~he accompanying notes are an integral part of these consolidated financial statements.~~

~~TC PIPELINES, LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

Three months ended

Nine months ended

(unaudited)

September 30,

September 30,

(millions of dollars)

2017

2016(a)

2017

2016(a)

Net income

55

60

193

198

Other comprehensive income

Change in fair value of cash flow hedges (Note 12)

—

2

1

(1
)
Amortization of realized loss on derivative financial instruments (Note 12)

—

—

1

1

Reclassification to net income of gains and losses on cash flow hedges (Note 12)

1

—

—

—

Comprehensive income

56

62

195

198

Comprehensive income attributable to non-controlling interests

1

2

7

10

Comprehensive income attributable to controlling interests

55

60

188

188

~~(a)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).~~

T~~he accompanying notes are an integral part of these consolidated financial statements.~~


	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

~~TC PIPELINES, LP~~

~~CONSOLIDATED BALANCE SHEETS~~

(unaudited)

(millions of dollars)

September 30, 2017

December 31, 2016 (a)

ASSETS

Current Assets

Cash and cash equivalents

73

64

Accounts receivable and other (Note 13)

35

47

Inventories

7

7

Other

6

7

121

125

Equity investments (Note 4)

1,207

918

Plant, property and equipment

(Net of $1,158 accumulated depreciation; 2016 - $1,088)

2,133

2,180

Goodwill

130

130

Other assets

—

1

3,591

3,354

LIABILITIES AND PARTNERS’ EQUITY

Current Liabilities

Accounts payable and accrued liabilities

31

29

Accounts payable to affiliates (Note 11)

5

8

Distribution payable

—

3

Accrued interest

21

10

Current portion of long-term debt (Note 5)

51

52

108

102

Long-term debt, net (Note 5)

2,427

1,859

Deferred state income taxes (Note 18)

10

10

Other liabilities

28

28

2,573

1,999

Common units subject to rescission (Note 7)

—

83

Partners’ Equity

Common units

790

1,002

Class B units (Note 7)

103

117

General partner

23

27

Accumulated other comprehensive loss

—

(2
)
Controlling interests

916

1,144

Non-controlling interests

102

97

Equity of former parent of PNGTS

—

31

1,018

1,272

3,591

3,354

~~Contingencies~~ ~~(Note 15)~~

~~Variable Interest Entities~~ ~~(Note 17)~~

~~Subsequent Events~~ ~~(Note 19)~~

~~(a)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).~~

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

Table of Contents

TC PIPELINES, LP

CONSOLIDATED ~~STATEMENT~~STATEMENTS OF ~~CASH FLOWS~~COMPREHENSIVE INCOME

Nine months ended

(unaudited)

September 30,

(millions of dollars)

2017

2016 (a)

Cash Generated From Operations

Net income

193

198

Depreciation

73

71

Amortization of debt issue costs reported as interest expense

1

1

Amortization of realized loss on derivative instrument

1

1

Deferred state income tax recovery (Note 18)

—

—

Equity earnings from equity investments (Notes 3 and 4)

(87
)
(75
)
Distributions received from operating activities of equity investments (Note 3)

106

125

Change in operating working capital (Note 10)

24

11

311

332

Investing Activities

Investment in Northern Border (Note 4)

(83
)
—

Investment in Great Lakes (Note 4)

(4
)
(4
)
Distribution received from Iroquois as return of investment (Note 4)

3

—

Acquisition of a 49.9 percent interest in PNGTS

—

(193
)
Acquisition of a 49.34 percent in Iroquois and an additional 11.81 percent in PNGTS (Note 6)

(646
)
—

Capital expenditures

(26
)
(21
)
Other

—

3

(756
)
(215
)
Financing Activities

Distributions paid (Note 9)

(210
)
(184
)
Distributions paid to Class B units (Note 7)

(22
)
(12
)
Distributions paid to non-controlling interests

(5
)
(12
)
Distributions paid to former parent of PNGTS

(1
)
(9
)
Common unit issuance, net (Note 7)

126

35

Common unit issuance subject to rescission, net (Note 7)

—

83

Long-term debt issued, net of discount (Note 5)

732

200

Long-term debt repaid (Note 5)

(164
)
(196
)
Debt issuance costs

(2
)
—

454

(95
)
Decrease in cash and cash equivalents

9

22

Cash and cash equivalents, beginning of period

64

55

Cash and cash equivalents, end of period

73

77


	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

~~(a)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).~~

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~~BALANCE SHEETS

Limited Partners

Common Units

Class B Units

General
Partner

Accumulated
Other
Comprehensive
Loss (a) (b)

Non-
Controlling
Interest(b)

Equity of
former
parent of
PNGTS(b)

Total
Equity(b)

(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

millions
of dollars

Partners’ Equity at December 31, 2016

67.4

1,002

1.9

117

27

(2
)
97

31

1,272

Net income (b)

—

164

—

8

12

—

7

2

193

Other comprehensive income

—

—

—

—

—

2

—

—

2

ATM equity issuances, net (Note 7)

2.2

124

—

—

2

—

—

—

126

Reclassification of common units no longer subject to rescission (Note 7)

—

81

—

—

2

—

—

—

83

Acquisition of interests in PNGTS and Iroquois (Note 6)

—

(383
)
—

—

(8
)
—

—

(32
)
(423
)
Distributions (b)

—

(198
)
—

(22
)
(12
)
—

(2
)
(1
)
(235
)

Partners’ Equity at September 30, 2017

69.6

790

1.9

103

23

—

102

—

1,018


(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

~~(a)~~ Losses related to cash flow hedges reported in Accumulated Other Comprehensive Loss and expected to be reclassified to Net Income in the next 12 months are estimated to be $1 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.

~~(b)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).~~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

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

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TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY


						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.

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TC PIPELINES, LP

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 ~~TransCanada~~TC Energy Corporation ~~(TransCanada~~(TC Energy Corporation together with its subsidiaries collectively referred to herein as ~~TransCanada)~~TC Energy), to acquire, own and participate in the management of energy infrastructure assets in North America.

The Partnership owns its pipeline assets through ~~three~~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 2 SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three and nine months ended September 30, ~~2017~~2019 and ~~2016~~2018 are not necessarily indicative of the results that may be expected for the full fiscal year.

The accompanying consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, ~~2016~~2018 included ~~as exhibit 99.2~~ in our ~~Current~~Annual Report on Form ~~8-K dated August 3, 2017.~~10-K. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying consolidated financial statements contain all of the appropriate adjustments, ~~all of~~ 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 ~~audited financial statements and notes thereto~~Annual Report on Form 10-K for the year ended December 31, ~~2016 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017,~~2018, except as described in Note 3, Accounting Pronouncements.

Basis of Presentation

The Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included inas 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 ~~TransCanada~~TC Energy are considered common control transactions. ~~When~~If businesses are acquired from ~~TransCanada~~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.

~~When~~If the Partnership acquires an asset or an investment from ~~TransCanada,~~TC Energy, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition.

~~On June 1, 2017,~~U.S. federal and certain state income taxes are the ~~Partnership acquired~~responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from ~~a subsidiary of TransCanada an additional 11.81 percent interest in PNGTS, that resulted~~the net income or loss reported in the ~~Partnership owning a 61.71 percent interest~~consolidated statement of operations, is includable in ~~PNGTS (Refer to Note 6). As a result~~the U.S. federal income tax returns of the Partnership owning 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented ineach partner.

In instances where the Partnership’s consolidated ~~financial statements. Additionally, this acquisition was accounted~~entities are subject to state income taxes, the asset-liability method is used to account for ~~as transaction between entities under common control, similar to pooling~~taxes. This method requires recognition of ~~interests, whereby the~~deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of ~~PNGTS were recorded at TransCanada’s carrying value.~~existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are classified as non-current on our consolidated balance sheets.

~~Also, on June 1, 2017, the Partnership acquired from subsidiaries~~12

Table of TransCanada a 49.34 percent interest in Iroquois Gas Transmission, L.P. (“Iroquois”) (Refer to Note 6). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively.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

~~Retrospective application of Accounting Standards Update (ASU) No 2016-15~~ “~~Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments”~~Leases

In ~~August~~February 2016, the Financial Accounting Standards Board (FASB) issued an amendment of previously issued guidance, which intends to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The new guidance is effective January 1, 2018, however, as early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The Partnership has elected to classify distributions received from equity method investees using the nature of distributions approach as it is more representative of the nature of the underlying activities of the investees that generated the distributions. As a result, certain comparative period distributions received from equity method investees, amounting to $50 million for the nine months ended September 30, 2016, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.

~~Effective January 1, 2017~~

~~Inventory~~

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Partnership’s consolidated balance sheet.

~~Equity method and joint ventures~~

In March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting. The new guidance is effective January 1, 2017 and was applied prospectively. The application of this guidance did not have a material impact on the Partnership’s consolidated financial statements.

~~Consolidation~~

In October 2016, the FASB issued new guidance on consolidation relating to interests held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entry (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to our consolidation conclusions.

~~Future accounting changes~~

~~Revenue from contracts with customers~~

In 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Partnership will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Partnership will adopt the

~~standard using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowable and elected practical expedients.~~

The Partnership has identified all existing customer contracts that are within the scope of the new guidance and is on schedule in the process of analyzing individual contracts or groups of contracts to identify any significant changes in how revenues are recognized as a result of implementing the new guidance. While the Partnership has not identified any material differences in the amount and timing of revenue recognition for the contracts that have been analyzed to date, the evaluation is not complete and the Partnership has not concluded on the overall impact of adopting the new guidance. The Partnership continues its contract analysis to obtain the information necessary to quantify the cumulative-effect adjustment, if any, on prior period revenues and revenue recognized going forward.

Although consolidated revenues may not be materially impacted by the new guidance, the Partnership currently anticipates significant changes to disclosures based on the additional requirements prescribed. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is recognized and information related to contract assets and liabilities. In addition, the new guidance requires that the Partnership’s revenue recognition policy disclosure includes additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenue and cash flows generated from contracts with customers. The Partnership continues to develop and evaluate disclosures required with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. The Partnership also continues to address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor additional authoritative or interpretive guidance related to the new guidance as it becomes available.

~~Leases~~

~~In February 2016, the FASB~~ issued new guidance on the accounting for leases. The new guidance amends the definition of a lease ~~requiring~~such that, in order for an arrangement to qualify as a lease, the ~~customer~~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 in order for the arrangement to qualify as a lease.~~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 12twelve months. Leases will be classified as finance or operating, with classification affecting the pattern ~~and classification~~ of expense recognition in the ~~income statement.~~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

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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 is effective on January 1, ~~2019, with early adoption permitted. A~~2020 and will be applied using a modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available.approach. The Partnership ~~is continuing to identify~~has substantially completed its analysis and ~~analyze existing lease agreements to determine~~does not expect the ~~effect of~~ adoption of ~~the~~this new guidance to have a material impact on its consolidated financial statements. ~~The Partnership is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.~~

~~Goodwill Impairment~~Consolidation

In ~~January 2017,~~October 2018, the FASB issued new guidance ~~on simplifying the test~~ for ~~goodwill impairment by eliminating the requirement~~determining whether fees paid to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value.decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied ~~prospectively. Early~~on a retrospective basis, however early adoption is permitted. The Partnership ~~is currently evaluating the impact of~~does not expect the adoption of this new guidance ~~and has not yet determined the effect~~to have a material impact on its consolidated financial statements.

~~Hedge Accounting~~NOTE 4 REGULATORY

~~In August~~Iroquois, Tuscarora, and Northern Border took the actions listed below to conclude the issues impacting their pipelines as contemplated by the 2017 Tax Act and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the ~~FASB issued new guidance~~rate impact of the 2017 Tax Act on ~~hedge accounting, making more financial~~FERC-regulated pipelines and nonfinancial hedging strategies eligible for hedge accounting. The new guidance amends the presentation requirements relating to the change in fair value of a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges and the effect of hedging on individual statement of income line items. This new guidance is effective January 1, 2019 and will be applied prospectively with a cumulative-effect adjustment to opening equity on adoption. Early adoption is permitted. The Partnership is currently evaluating the impact of the ~~adoption~~Revised Policy Statement on pipelines held by an MLP (collectively “2018 FERC Actions”).

Iroquois

On February 28, 2019, Iroquois filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (2019 Iroquois Settlement). Among the terms of ~~this guidance~~the 2019 Iroquois Settlement, Iroquois agreed to reduce its existing maximum system rates by 6.5 percent to be implemented in 2 phases, (i) effective March 1, 2019, a 3.25 percent rate reduction and ~~has not yet determined~~(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

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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 ~~consolidated financial statements.~~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 45 EQUITY INVESTMENTS

The Partnership has equity interests in Northern Border, Great Lakes and ~~effective June 1, 2017,~~ Iroquois. The pipeline systems owned by these entities are regulated by FERC. The pipeline systems of Northern Border and Great Lakes are operated by subsidiaries of ~~TransCanada.~~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 ~~17)~~16).

	Ownership		Equity Earnings				Equity Investments
	Interest at		Three months		Nine Months

									Ownership		Equity Earnings				Equity Investments
									Interest at		Three months ended		Nine months ended
(unaudited)	September 30,		ended September 30,		ended September 30,		September 30,	December 31,	September 30,		September 30,		September 30,		September 30,	December 31,
(millions of dollars)	2017		2017	2016(b)	2017	2016(b)	2017	2016(b)	2019		2019	2018	2019	2018	2019	2018

Northern Border ~~(a)~~	50	%	16	18	50	52	516	444	50.00	%	15	16	50	49	426	497
Great Lakes	46.45	%	2	4	24	23	469	474	46.45	%	8	9	37	45	482	489
Iroquois	49.34	%	9	—	13	—	222	—	49.34	%	8	9	28	35	186	210
			27	22	87	75	1,207	918
											31	34	115	129	1,094	1,196

~~(a)~~Distributions from Equity ~~earnings~~Investments

Distributions received from equity investments in the three and nine months ended September 30, 2019 were $59 million and $226 million, respectively (September 30, 2018 - $49 million and $150 million, respectively), of which $2.6 million and $57.8 million, respectively (September 30, 2018 - $2.6 million and $7.8 million, respectively), were considered return of capital and included in “Investing Activities” in the Partnership’s consolidated statement of cash flows. The return of capital was related to our investment in Northern Border ~~is net of~~and Iroquois (see further discussion below).

Northern Border

During the ~~12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent interest in April 2006.~~

~~(b)~~ ~~Recast to eliminate equity earnings from PNGTS~~three and ~~consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).~~

~~Northern Border~~

Onnine months ended September ~~1, 2017,~~30, 2019, the Partnership ~~made an equity contribution to~~received distributions from Northern Border amounting to $~~83 million. This amount represents~~$21 million and $121 million, respectively (September 30, 2018 - $21 million and $60 million, respectively). The $121 million includes the Partnership’s 50 percent share of ~~$166 million capital contribution request from~~the Northern Border ~~to reduce~~$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 ~~outstanding balance~~Partnership received did not represent a distribution of ~~its revolver debt to increase its available borrowing capacity.~~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 months ended September 30, ~~2017~~2019 and ~~2016.~~2018.

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

(unaudited)

(millions of dollars)

September 30, 2017

December 31, 2016

ASSETS

Cash and cash equivalents

24

14

Other current assets

36

36

Plant, property and equipment, net

1,069

1,089

Other assets

14

14

1,143

1,153

LIABILITIES AND PARTNERS’ EQUITY

Current liabilities

48

38

Deferred credits and other

30

28

Long-term debt, including current maturities, net

264

430

Partners’ equity

Partners’ capital

802

659

Accumulated other comprehensive loss

(1
)
(2
)

1,143

1,153

Three months ended

Nine months ended

(unaudited)

September 30,

September 30,

(millions of dollars)

2017

2016

2017

2016

Transmission revenues

73

74

217

218

Operating expenses

(20
)
(18
)
(56
)
(53
)
Depreciation

(15
)
(15
)
(45
)
(44
)
Financial charges and other

(5
)
(5
)
(14
)
(16
)
Net income

33

36

102

105


(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)

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

The Partnership made an equity contribution to Great Lakes of $4$5 million in the first quarter of ~~2017.~~2019 (September 30, 2018 - $4 million). This amount represents the Partnership’s 46.45 percent share of ~~a $9~~an $11 million cash call from Great Lakes to make a scheduled debt repayment.

The Partnership did not have undistributed earnings from Great Lakes for the three and nine months ended September 30, ~~2017~~2019 and ~~2016.~~2018.

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


(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016	September 30, 2019	December 31, 2018

ASSETS
Current assets	56	66	59	75
Plant, property and equipment, net	705	714
	761	780

Property, plant and equipment, net			685	689
			744	764

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	41	40	29	26
Net long-term debt, including current maturities(a)	269	278	229	240
Partners’ equity	451	462
	761	780
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)

2017

2016

2017

2016

Transmission revenues

34

36

138

133

Operating expenses

(19
)
(15
)
(49
)
(45
)
Depreciation

(7
)
(7
)
(21
)
(21
)
Financial charges and other

(5
)
(6
)
(16
)
(17
)
Net income

3

8

52

50


	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)

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

~~On June 1, 2017,~~The Partnership made an equity contribution to Iroquois of $4 million in August 2019. This amount represents the ~~Partnership acquired a~~Partnership’s 49.34 percent ~~interest in Iroquois. Also on July 27, 2017,~~share of an $7 million cash call from Iroquois ~~declared its second quarter 2017 distribution~~to cover costs of ~~$28 million, of which~~regulatory approvals related to their capital project.

During the three and nine months ended September 30, 2019, the Partnership received ~~its 49.34 percent share or~~distributions from Iroquois amounting to $28 million and $56 million, respectively (September 30, 2018 - $14 million ~~on August 1, 2017. The distribution~~and $42 million, respectively), which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million ~~(Refer to Note 6)~~and $7.8 million, respectively (September 30, 2018 - $2.6 million and $7.8 million, respectively). ~~This amount is~~The unrestricted cash did not represent a distribution of Iroquois’ cash from operations during the period and therefore it was reported as ~~distributions received 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 ~~recorded no~~did not have undistributed earnings from Iroquois infor the three and nine months ended September 30, ~~2017.~~2019 and 2018.

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


(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016	September 30, 2019	December 31, 2018

ASSETS
Cash and cash equivalents	93	86	38	80
Other current assets	33	34	33	32
Plant, property and equipment, net	592	604
Property, plant and equipment, net			570	581
Other assets	8	7	14	8
	726	731

			655	701

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	20	18	21	19
Net long-term debt, including current maturities	332	335
Long-term debt, net ^(a)			320	325
Other non-current liabilities	9	6	20	14
Partners’ equity	365	372
	726	731
Partners' equity			294	343
			655	701

	Three months ended				Nine months ended

									Three months ended		Nine months ended
(unaudited)	September 30,				September 30,				September 30,		September 30,
(millions of dollars)	2017		2016		2017		2016		2019	2018	2019	2018

Transmission revenues	43		45		142		145		39	42	131	147
Operating expenses	(13	)	(13	)	(41	)	(43	)	(15)	(13)	(43)	(41)
Depreciation	(7	)	(9	)	(22	)	(28	)	(7)	(7)	(22)	(22)
Financial charges and other	(4	)	(4	)	(13	)	(12	)	(2)	(4)	(9)	(11)
Net income	19		19		66		62		15	18	57	73

(a)

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 6 REVENUES

Disaggregation of Revenues

For the three and nine months ended September 30, 2019 and 2018, effectively all of the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed in more detail below.

Capacity Arrangements and Transportation Contracts

The Partnership’s performance obligations in its contracts with customers consist primarily of capacity arrangements and natural gas transportation contracts.

The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Partnership has elected to utilize the practical expedient of recognizing revenue as invoiced.

The Partnership's pipeline systems are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. As of September 30, 2019, the Partnership does not have any outstanding refund obligations related to any rate proceedings. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers.

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

Additionally, our accounts receivable represent the Partnership’s unconditional right to consideration for services completed which includes billed and unbilled accounts.

Future revenue from remaining performance obligations

When the right to invoice practical expedient is applied, the guidance does not require disclosure of information related to future revenue from remaining performance obligations, therefore, no additional disclosure is required.

Additionally, in the application of the right to invoice practical expedient, the Partnership’s revenues from regulated capacity arrangements are recognized based on rates specified in the contract. Therefore, the amount invoiced, which includes the capacity contracted and variable volume of natural gas transported, corresponds directly to the value the customer received. These revenues are recognized on a monthly basis once the Partnership’s performance obligation to provide capacity has been satisfied.

NOTE 57 DEBT AND CREDIT FACILITIES

(unaudited) (millions of dollars)	September 30, 2017	Weighted Average Interest Rate for the Nine Months Ended September 30, 2017		December 31, 2016 (a)	Weighted Average Interest Rate for the Year Ended December 31, 2016


								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	255	2.34	%	160	1.72	%	—	—			40	3.14	%
2013 Term Loan Facility due October 2022	500	2.26	%	500	1.73	%
2015 Term Loan Facility due October 2020	170	2.15	%	170	1.63	%
2013 Term Loan Facility due 2022							450	3.66	%		500	3.23	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(b)	350	4.65	%(b)	350	4.65	%	^(a)	350	4.65	%	^(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(b)	350	4.375	%(b)	350	4.375	%	^(a)	350	4.375	%	^(a)
3.90 % Unsecured Senior Notes due 2027	500	3.90	%(b)	—	—		500	3.90	%	^(a)	500	3.90	%	^(a)

GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(b)	100	5.29	%(b)	100	5.29	%	^(a)	100	5.29	%	^(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(b)	150	5.69	%(b)	150	5.69	%	^(a)	150	5.69	%	^(a)
Unsecured Term Loan Facility due 2019	55	1.95	%	65	1.43	%	—	—			35	2.93	%

PNGTS
5.90% Senior Secured Notes due December 2018	36	5.90	%(b)	53	5.90	%(b)
Revolving Credit Facility due 2023							30	3.65	%		19	3.55	%

Tuscarora
Unsecured Term Loan due 2020	25	2.18	%	10	1.64	%	23	3.54	%		24	3.10	%
3.82% Series D Senior Notes due August 2017	—	3.82	%(b)	12	3.82	%(b)
	2,491			1,920

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	13			9			9				10
Less: current portion	51			52			123				36
	2,427			1,859
							1,871				2,072

(a)

Fixed interest rate

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~~(a)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).~~

~~(b)~~ ~~Fixed interest rate~~

TC ~~Pipelines,~~PipeLines, LP

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 10, ~~2021,~~2021. In March 2019, the Partnership repaid all amounts outstanding under ~~which $255 million~~its Senior Credit Facility and there was 0 outstanding balance at September 30, ~~2017~~2019 (December 31, ~~2016~~2018 - ~~$160~~$40 million)~~, leaving $245 million available for future borrowing.~~ .

The LIBOR-based interest rate onapplicable to the Senior Credit Facility was ~~2.49~~3.77 percent at ~~September 30, 2017 (December~~December 31, ~~2016 — 1.92 percent).~~2018.

On ~~September 29, 2017,~~June 26, 2019, the ~~Partnership’s~~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 ~~was due on July 1, 2018 was amended~~were used to ~~extend the maturity period through October 2, 2022.~~hedge this facility at a rate of 2.81 percent. As of September 30, ~~2017,~~2019, the variable interest rate exposure related to the 2013 Term Loan Facility was hedged ~~by fixed~~using interest rate ~~swap arrangements and our effective interest~~swaps at an average rate ~~was 2.31~~of 3.26 percent (December 31, ~~2016 — 2.31~~2018 – 3.26 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was ~~2.49~~3.35 percent at September 30, ~~2017~~2019 (December 31, ~~2016 — 1.87~~2018 - 3.60 percent).

~~On September 29, 2017, the Partnership’s 2015 Term Loan Facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020.~~ The ~~LIBOR-based interest rate on the 2015 Term Loan Facility was 2.39 percent at September 30, 2017 (December 31, 2016 — 1.77 percent).~~

~~The 2013 Term Loan~~Senior Credit Facility and the ~~2015~~2013 Term Loan ~~Facility (collectively, the Term Loan Facilities) and the Senior Credit~~ Facility require the Partnership to maintain a ~~certain leverage ratio (debt~~debt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains])leverage ratio of no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions ~~has~~have been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was ~~4.76~~2.79 to 1.00 as of September 30, ~~2017.~~2019.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition (Refer to Note 6). The indenture for the notes contains customary investment grade covenants.

~~PNGTS~~GTN

PNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At September 30, 2017, the debt service coverage ratio was 1.71 for the twelve

~~preceding months and 5.31 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.~~

~~GTN~~

GTN’s Unsecured Senior Notes ~~along with GTN’s Unsecured Term Loan Facility~~ contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization. GTN’s total debt to total capitalization ratio at September 30, ~~2017~~2019 was ~~44.2~~39.8 percent.

During the three months ended June 30, 2019, GTN's Unsecured Term Loan Facility matured and was fully repaid using the Partnership's funds from operations. The LIBOR-based interest rate ~~on the~~applicable to GTN’s Unsecured Term Loan Facility was ~~2.19~~3.30 percent at December 31, 2018.

GTN's $100 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 greater than 5.00 to 1.00. The leverage ratio was 0.5 to 1.00 as of September 30, 2019.

The LIBOR-based interest rate applicable to PNGTS’s Revolving Credit Facility was 3.35 percent at September 30, ~~2017~~2019 (December 31, ~~2016 — 1.57~~2018 - 3.60 percent).

Tuscarora

On August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of September 30, ~~2017,~~2019, the ratio was ~~3.08~~9.01 to 1.00.

The LIBOR-based interest rate ~~on the~~applicable to Tuscarora’s Unsecured Term Loan Facility was ~~2.36~~3.23 percent at September 30, ~~2017~~2019 (December 31, ~~2016 — 1.90~~2018 - 3.47 percent).

Tuscarora's $23 million variable rate Unsecured Term Loan due August 21, 2020 is expected to be refinanced in full or at an amount based on the Partnership's preferred capitalization levels.

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North Baja

North Baja’s Term Loan Facility contains a covenant that limits total debt to no greater than 70 percent of North Baja’s total capitalization. North Baja’s total debt to total capitalization ratio at September 30, 2019 was 38.94 percent.

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

Partnership (TC PipeLines, LP and its subsidiaries)

At September 30, ~~2017,~~2019, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the ~~Third~~Fourth Amended and Restated Agreement of Limited Partnership (Partnership Agreement), incurring additional debt and distributions to unitholders.

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


(unaudited)
(millions of dollars)		Principal Payments

2017	12
2018	45
2019	36	—
2020	293	123
2021	605	400
2022		450
2023		30
Thereafter	1,500	1,000
	2,491
		2,003

~~NOTE 6~~~~ACQUISITION~~

~~2017 Acquisition~~

On June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois, including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus final purchase price adjustments amounting to $50 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1, 2017), (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ outstanding debt on June 1, 2017) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration for Iroquois’ surplus cash amounting to $28 million. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.

At the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.

Additionally, Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly

distributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of November 6, 2017 the Partnership has received approximately $5.2 million of the expected $28 million, of which $2.6 million was received on November 1, 2017 (Refer to Note 19).

The acquisition of a 49.34 percent interest in Iroquois was accounted for as a transaction between entities under common control, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.

~~Iroquois’ net purchase price was allocated as follows:~~

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

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

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

~~The acquisition of an additional 11.81 percent interest in PNGTS, which resulted in the Partnership owning 61.71 percent in PNGTS, was accounted for~~ as a transaction between entities under common control, similar to a pooling of interests, whereby assets and liabilities of PNGTS were recorded at TransCanada’s carrying value and the Partnership’s historical financial information, except net income per common unit, was recast to consolidate PNGTS for all periods presented.

~~The PNGTS purchase price was recorded as follows:~~

~~(millions of dollars)~~
~~Current assets~~	25
~~Property, plant and equipment, net~~	~~294~~
~~Current liabilities~~	(4	)
~~Deferred state income taxes~~	~~(10~~	)
~~Long-term debt, including current portion~~	~~(41~~	)
	~~264~~

~~Non-controlling interest~~	~~(100~~	)
~~Carrying value of pre-existing Investment in PNGTS~~	~~(132~~	)
~~TransCanada’s carrying value of the acquired 11.81 percent interest at June 1, 2017~~	32
~~Excess purchase price over net assets acquired~~ ~~(a)~~	21
~~Total cash consideration~~ ~~(b)~~	53

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

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

NOTE 8 PARTNERS’ EQUITY

~~NOTE 7 PARTNERS’ EQUITY~~

ATM equity issuance program (ATM program)

During the nine months ended September 30, ~~2017, we issued 2,165,162~~2019, 0 common units were issued under our ATM program generating net proceeds of approximately $124 million, plus $2 million contributed by the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the nine months ended September 30, 2017 were approximately $1 million. The net proceeds were used for general partnership purposes.this program.

Class B units issued to ~~TransCanada~~TC Energy

The Class B ~~Units we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us and~~units entitle ~~TransCanada~~TC Energy to an annual distribution based on 30 percent of GTN’s annual

distributions as follows: (i) 100 percent of distributions above $20 million ~~through March~~for the year ending December 31, 2019; (ii) 43.75 percent of distributions above $20 million for the year ending December 31, 2020; and ~~(ii)~~(iii) 25 percent of distributions above $20 million ~~thereafter.~~thereafter (Class B Distribution). Additionally, the Class B Distribution will be further reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018 (Class B Reduction). The Class B Reduction was implemented during the first quarter of 2018 following the Partnership’s common unit distribution reduction of 35 percent. The Class B Reduction will continue to apply to any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit.

For the year ending December 31, ~~2017,~~2019, the Class B units’ equity account will be increased by the ~~excess of 30 percent of GTN’s distributions over~~Class B Distribution, less the ~~annual threshold of $20 million~~Class B Reduction, until such amount is declared for distribution and paid in the first quarter of ~~2018.~~2020. During the nine months ended September 30, ~~2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold,~~2019, the Class B ~~units’~~units' equity account was increased by $8$1 million ~~(Refer to Note 8).~~after the 2019 threshold was exceeded and the estimated Class B Reduction for 2019 was applied.

For the year ended December 31, ~~2016,~~2018, the Class B ~~distribution~~Distribution was ~~$22~~$13 million and was declared and paid in the first quarter of ~~2017.~~2019.

~~Common unit issuance subject to rescission~~21

~~In connection with a late filing~~Table of an employee-related Form 8-K with the SEC in March 2016, the Partnership became ineligible to use the then effective shelf registration statement upon filing of its Annual Report on Form 10-K for the year ended December 31, 2015. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the Partnership’s ATM program may have had a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to the Partnership. The Securities Act of 1933, as amended (Securities Act) generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of violation.Contents

At December 31, 2016, $83 million was recorded as common units subject to rescission on the consolidated balance sheet. The Partnership classified the 1.6 million common units that were sold under its ATM program from March 8, 2016 up to and including May 19, 2016, which may have been subject to rescission rights, outside of equity given the potential redemption feature which was not within the control of the Partnership. These units were treated as outstanding for financial reporting purposes.

No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. As a result of the expiration of these rights, the $83 million was reclassified back to partners’ equity. At September 30, 2017, there were no outstanding common units subject to rescission on the Partnership’s consolidated balance sheet.

NOTE 89 NET INCOME PER COMMON UNIT

Net income per common unit is computed by dividing net income attributable to controlling interests, after deduction of ~~net income attributable to PNGTS’ former parent,~~ amounts attributable to the General Partner and Class B units, by the weighted average number of common units outstanding.

The ~~amounts~~amount allocable to the General Partner equals an amount based upon the General Partner’s ~~effective two~~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 ~~2017 equals~~2019 will equal 30 percent of GTN’s distributable cash flow during the year ~~ended~~ending December 31, ~~2017~~2019 less $20 million and is further reduced by the estimated Class B Reduction for 2019 (December 31, ~~2016 —$~~2018-$20 ~~million).~~

~~Net income per common unit was determined as follows:~~

Three months ended
September 30,

Nine months ended
September 30,

(unaudited)

(millions of dollars, except per common unit amounts)

2017

2016 (a)

2017

2016 (a)

Net income attributable to controlling interests (a)

54

58

186

188

Net income attributable to PNGTS’ former parent (a) (b)

—

—

(2
)
(3
)
Net income attributable to General and Limited Partners

54

58

184

185

Incentive distributions allocated to the General Partner (c)

(3
)
(2
)
(9
)
(5
)
Net income attributable to the Class B units (d)

(8
)
(11
)
(8
)
(12
)
Net income attributable to the General Partner and common units

43

45

167

168

Net income attributable to General Partner’s effective two percent interest

(1
)
(2
)
(3
)
(4
)
Net income attributable to common units

42

43

164

164

Weighted average common units outstanding (millions) — basic and diluted

69.4

66.1
(e)
68.9

65.3
(e)
Net income per common unit — basic and diluted

$
0.61

$
0.65
(f)
$
2.38

$
2.51
(f)

~~(a)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).~~

~~(b)~~ Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated to TransCanada and was not allocable to either the general partner, common units ormillion less Class B ~~units.~~

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

~~(d)~~Reduction). During the three and nine months ended September 30, ~~2017,~~2019 $1 million was allocated to the Class B units (September 30, 2018 - $4 million).

Net income per common unit was determined as follows:


(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 ~~$28~~$25 million. ~~As a result of exceeding~~After applying the $20 million annual threshold $8and the estimated Class B Reduction for 2019, $1 million of net income attributable to controlling interests was allocated to the Class B units ~~during~~for both the three and nine months ended September 30, ~~2017.~~2019. During ~~the six months ended June 30, 2016, the threshold was exceeded and during~~ the nine months ended September 30, ~~2016,~~2018, 30 percent of GTN’s total distributable cash flow was ~~$32~~$31 million. ~~As a result, $12~~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 atfor both the three and nine months ended September 30, ~~2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively~~2018 (Refer to Note 7)8).

~~(e)~~ ~~Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 7).~~

~~(f)~~ ~~Net income per common unit prior to recast (Refer to Note 2).~~

NOTE 910 CASH DISTRIBUTIONS PAID TO COMMON UNITS

2019

During the three and nine months ended September 30, ~~2017,~~2019, the Partnership distributed ~~$1.00~~$0.65 and ~~$2.88~~$1.95 per common unit, respectively, ~~(September 30, 2016 — $0.94 and $2.72 per common unit)~~ for a total of ~~$74~~$47 million and ~~$210~~$142 million, ~~respectively (September~~respectively.

The total distribution paid above includes our General Partner’s share during the three and nine months ended September 30, ~~2016 - $65~~2019 for its 2 percent general partner interest, which was $1 million and ~~$184 million).~~$3 million, respectively. The General Partner did not receive any distributions in respect of its IDRs during the three and nine months ended September 30, 2019.

2018

During the three 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 months ended September 30, 2017 for its effective two percent general partner interest was $2 million along with an IDR payment of $3 million for a total distribution of $5 million (September 30, 2016 - $1 million for the effective two percent interest and ~~a $2 million IDR payment).~~

~~The distribution paid to our General Partner during the~~ nine months ended September 30, ~~2017 for its effective two percent general partner interest was $4 million along with an IDR payment of $7 million for a total distribution of $11 million (September 30, 2016 -~~2018 were NaN and $3 million, ~~for the effective two percent interest and a $4 million IDR payment).~~respectively.

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NOTE 1011 CHANGE IN OPERATING WORKING CAPITAL


(unaudited)	Nine months ended September 30,				Nine months ended September 30,
(millions of dollars)	2017		2016 (a)		2019	2018

Change in accounts receivable and other(a)	13		3		16	3
Change in inventories					(1)	—
Change in other current assets	1		2		4	1
Change in accounts payable and accrued liabilities(b)	2		3
Change in accounts payable to affiliates	(3	)	(2	)
Change in accounts payable and accrued liabilities^(a)					(11)	13
Change in accrued interest	11		5		8	8
Change in operating working capital	24		11		16	25

(a)

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

~~(a)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).~~

~~(b)~~ The accrual of $10 million for the construction of GTN’s Carty Lateral in December 31, 2015 was paid during the first quarter 2016. Accordingly, the payment was reported as capital expenditures in our 2016 cash flow statement.

NOTE 1112 RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to ~~the~~ conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. For ~~both~~ the three and nine months ended September 30, ~~2017~~2019 and ~~2016,~~2018, total costs charged to the Partnership by the General Partner were $1 million and $3 million, respectively.

As operator of our pipelines, except Iroquois ~~TransCanada’s~~and a certain portion of the PNGTS facilities, TC Energy’s subsidiaries provide capital and operating services to our pipeline systems. ~~TransCanada’s~~TC Energy’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. ~~The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. Therefore,~~ Iroquois does not receive any capital and operating services from ~~TransCanada.~~TC Energy (Refer to Note 5).

Capital and operating costs charged to our pipeline systems, except for Iroquois, for the three and nine months ended September 30, ~~2017~~2019 and ~~2016~~2018 by ~~TransCanada’s~~TC Energy’s subsidiaries and amounts payable to ~~TransCanada’s~~TC Energy’s subsidiaries at September 30, ~~2017~~2019 and December 31, ~~2016~~2018 are summarized in the following tables:

	Three months ended September 30,		Nine months ended September 30,
			Nine months ended September 30,
					Three months ended		Nine months ended
(unaudited)	Three months ended September 30,	Three months ended September 30,		Nine months ended September 30,		September 30,		September 30,
(millions of dollars)		Three months ended September 30,		Nine months ended September 30,	2019	2018	2019	2018

Capital and operating costs charged by TransCanada’s subsidiaries to:
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes (a)	10	8	27	22	12	9	35	34
Northern Border (a)	10	9	30	25	10	8	29	26
GTN	9	8	24	20	11	8	32	25
Bison	2	1	4	1	1	2	2	5
North Baja	1	1	3	3	1	1	4	3
Tuscarora	1	1	3	3	1	1	3	3
PNGTS(a)	2	2	6	6	2	2	5	7
Impact on the Partnership’s net income:
Impact on the Partnership’s income ^(b):
Great Lakes ~~(a)~~	4	3	11	9	4	4	14	14
Northern Border (a)	4	3	11	9
Northern Border					4	4	13	12
GTN	7	7	21	18	9	7	25	21
Bison	2	1	4	2	—	2	1	5
North Baja	1	1	3	3	1	1	3	3
Tuscarora	1	1	3	3	1	1	3	3
PNGTS (b)	1	1	4	3	1	1	3	4

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(unaudited)

September 30,

(millions of dollars)

2017

December 31, 2016

Net amounts payable to TransCanada’s subsidiaries is as follows:

Great Lakes (a)

3

4

Northern Border (a)

3

4

GTN

3

3

Bison

1

1

North Baja

—

1

Tuscarora

—

1

PNGTS

1

1


(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

~~(a)~~
(a) Represents 100 percent of the costs.
(b) Represents the Partnership's proportionate share based ownership percentage of these pipelines

~~(b)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Note 2).~~Great Lakes

Great Lakes earns significant transportation revenues from ~~TransCanada~~TC Energy and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For the three and nine months ended September 30, ~~2017,~~2019, Great Lakes earned 4473 percent ~~and 53 percent~~ of its transportation revenues from ~~TransCanada~~TC Energy and its affiliates ~~respectively~~ (September 30, ~~2016 — 62~~2018 - 76 percent and ~~69 percent)~~71 percent, respectively).

At September 30, ~~2017, $8~~2019, $13 million was included in Great Lakes’ receivables ~~in regards~~with regard to the transportation contracts with ~~TransCanada~~TC Energy and its affiliates (December 31, ~~2016 — $19~~2018 - $18 million).

During the second quarter of 2018, Great Lakes ~~operates under~~reached an agreement on the terms of new long-term transportation capacity contracts with its affiliate, ANR Pipeline Company. The contracts are for a ~~FERC approved 2013 rate settlement that includes~~term of 15 years from November 2021 to October 31, 2036 with a ~~revenue sharing mechanism that requires~~total contract value of approximately $1.3 billion. The contracts contain reduction options (i) at any time on or before April 1, 2019 for any reason and (ii) any time before April 2021, if TC Energy is not able to secure the required regulatory approval related to anticipated expansion projects. During the first quarter of 2019, Great Lakes reached an agreement to ~~share with its shippers certain percentages of~~amend volume reduction “for any ~~qualifying revenues earned above a certain return on equity threshold. For~~reason” option by extending the ~~year ended December 31, 2016, Great Lakes recorded an estimated 2016 revenue sharing provision of $7.2 million. For~~period “on or before” April 1, 2019 to “on or before” April 1, 2020. All the three and nine months ended September 30, 2017, Great Lakes recorded an estimated 2017 revenue sharing provision of $12 million and $22 million, respectively. Great Lakes expects that a significant percentage of this refund will be paid to its affiliates.other terms remained the same.

PNGTS earns transportation revenues from TransCanada and its affiliates. For three and nine months ended September 30, 2017, PNGTS earned approximately nil million and $1 million of its transportation revenues from TransCanada and its affiliates, respectively (2016 — $1 million and $2 million, respectively).

~~At September 30, 2017, nil million was included in PNGTS’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2016 — nil).~~

In connection with ~~anticipated future commercial opportunities,~~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 required to fulfill future contracts on the ~~PNGTS’~~PNGTS system. PXP Phases I and II were placed into service on November 1, 2018 and November 1, 2019, respectively. Phase III is estimated to be in service on November 1, 2020. In the event the ~~anticipated developments do not proceed,~~expansions terminate prior to their in-service dates, PNGTS will be required to reimburse its affiliates for any costs incurred related to the development of these facilities. At September 30, ~~2017,~~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 Phase II terminated.

Going forward, the PNGTS ~~does not have an obligation for reimbursement under this arrangement.~~will only be obligated to reimburse costs incurred by TC Energy in relation to Phase III, which was NaN at September 30, 2019 and estimated to be approximately $7.2 million by November 1, 2020, when Phase III goes into service.

NOTE 1213 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.~~24

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●

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.

· ~~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 inas Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified inas 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 30, ~~2017~~2019 and December 31, ~~2016~~2018 was ~~$2,555~~$2,100 million and ~~$1,962~~$2,101 million, respectively.

Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. The Partnership’s floating rate debt is subject to LIBOR benchmark interest rate risk. The Partnership uses ~~interest rate~~ derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

The Partnership’s interest rate swaps mature on October 2, 2022, and are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The ~~Partnership hedged~~fixed weighted average interest ~~payments~~rate on these instruments is 3.26 percent. On June 26, 2019, in conjunction with the ~~variable-rate~~Partnership’s $50 million repayment on its 2013 Term Loan Facility, ~~with~~the Partnership also terminated an equivalent amount in interest rate swaps ~~maturing July 1, 2018,~~that were used to hedge this facility at ~~a weighted average fixed interest~~an unwind rate of ~~2.31 percent.~~ 2.81 percent (See also Note 7).

At September 30, ~~2017,~~2019, the fair value of the interest rate swaps accounted for as cash flow hedges was ~~an asset~~ a liabilityof $2$8 million (both on a gross and net basis)~~. At December~~ (December 31, ~~2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an~~2018 - asset of ~~$1 million and a liability~~$8 million), the net change of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and nine months ended September 30, 2017 and 2016. The change in fair value of interest rate derivative instrumentswhich is recognized in other comprehensive ~~income was nil and a gain of $1 million for the three and nine months ended September 30, 2017, respectively (September 30, 2016 — gain of $2 million and a loss of $1 million).~~income. For the three and nine months ended September 30, ~~2017,~~2019, the net realized ~~loss~~gain related to the interest rate swaps was ~~nil,~~NaN and $1 million, respectively, and was included in ~~financial~~"financial charges and ~~other~~other" (September 30, ~~2016 —$1~~2018 - NaN and gain of $2 million, ~~and $2 million)~~respectively) (Refer to Note ~~14)~~ 15).

As discussed in Note 5, the Partnership’s $500 million 2013 Term Loan that was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. At September 30, 2017, the entire $500 million 2013 Term Loan was hedged until July 1, 2018. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.

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 30, ~~2017 (net asset of nil million as of~~2019 and December 31, ~~2016).~~2018.

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, ~~Derivatives and Hedging~~. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in accumulated other comprehensive income as of the termination date. The previously recorded loss is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes. At September 30, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in other comprehensive income was $1 million (December 31, 2016 - $2 million). For the three and nine months ended September 30, 2017, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil and $1 million, respectively (September 30, 2016 —nil and $1 million).

NOTE 1314 ACCOUNTS RECEIVABLE AND OTHER


(unaudited)
(millions of dollars)	September 30, 2017	December 31, 2016 (a)	September 30, 2019	December 31, 2018

Trade accounts receivable, net of allowance of nil	34	44	30	44
Imbalance receivable from affiliates	—	2	—	2
Other	1	1	9	2
	35	47
			39	48

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~~(a)~~ ~~Recast as discussed in Notes 2 and 6.~~

NOTE 1415 FINANCIAL CHARGES AND OTHER

	Three months ended September 30,		Nine months ended September 30,
			Nine months ended September 30,
							Three months ended		Nine months ended
(unaudited)	Three months ended September 30,	Three months ended September 30,			Nine months ended September 30,			September 30,		September 30,
(millions of dollars)		Three months ended September 30,			Nine months ended September 30,		2019	2018	2019	2018

Interest expense (a)	23	17	59		52		22	23	67	71
PNGTS’ amortization of derivative loss on derivative instruments (Note 12) (b)	—	—	1		1
Net realized loss related to the interest rate swaps	—	1	—		2
PNGTS' amortization of loss on derivative instruments							—	—	—	2
Net realized gain related to the interest rate swaps							—	—	(1)	(2)
Other income	—	—	(1	)	(2	)	(2)	—	(3)	(2)
	23	18	59		53
							20	23	63	69

(a)

Includes amortization of debt issuance costs and discount costs.

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

~~(b)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Note 2).~~

~~NOTE 15~~~~CONTINGENCIES~~

~~Great Lakes v. Essar Steel Minnesota LLC, et al~~. — On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes. On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. The Eighth Circuit heard the appeal on October 20, 2016. A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Before the Circuit Court issued its decision, Essar Minnesota filed for bankruptcy in July 2016. The Foreign Essar Affiliates have not filed for bankruptcy. Following the Circuit Court’s decision, the performance bond was released into the bankruptcy court proceedings. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April 2017, after Great Lakes agreement with creditors on an allowed claim, the bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million. On May 20, 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the performance bond premium, to be paid by Great Lakes. Great Lakes filed a motion with the bankruptcy court to offset the $1.2 million award of costs against its claim against Essar Minnesota in the bankruptcy proceeding. If Great Lakes’ motion to offset the federal district court’s award of costs is against its claim in the bankruptcy proceeding is not successful, Great Lakes will be responsible to the bankruptcy estate for payment of the award. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.

~~NOTE 16~~~~REGULATORY~~

~~North Baja —~~On January 6, 2017, North Baja notified FERC that current market conditions do not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to permanently abandon two compressor units and a nominal volume of unsubscribed firm capacity. FERC approved the permanent abandonment request on February 16, 2017. The abandonments will not have any impact on existing firm transportation service.

~~Great Lakes~~ - On April 24, 2017, Great Lakes reached an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.

On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Settlement). The 2017 Great Lakes Settlement, if approved by FERC, will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017. Great Lakes expects that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.

~~Northern Border-~~ Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement. Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term. At this time, we do not believe that the final outcome of the settlement will have a material impact to the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.

NOTE 1716 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 ~~other~~ GAAP. A ~~variable interest entity (VIE)~~VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the ~~VIEs~~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 ~~Partnership’s ILPs~~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 ~~that~~ 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 ~~Iroquois~~North

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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, 2017		December 31, 2016(a)		September 30, 2019	December 31, 2018

ASSETS (LIABILITIES) *
ASSETS (LIABILITIES) ^(a)
Cash and cash equivalents	19		14		17	16
Accounts receivable and other	23		33		35	39
Inventories	6		6		9	8
Other current assets	4		6		2	6
Equity investments	1,207		918		1,094	1,196
Plant, property and equipment	1,132		1,146
Property, plant and equipment, net					1,241	1,240
Other assets	1		2		1	1
Accounts payable and accrued liabilities	(21	)	(21	)	(26)	(33)
Accounts payable to affiliates, net	(25	)	(32	)	(86)	(40)
Distributions payable	—		(3	)
Other taxes payable	(1	)	—
Accrued interest	(5	)	(2	)	(5)	(2)
Current portion of long-term debt	(51	)	(52	)	(123)	(36)
Long-term debt	(314	)	(337	)	(229)	(341)
Other liabilities	(26	)	(25	)	(29)	(27)
Deferred state income tax	(10	)	(10	)	(9)	(9)

*North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities
(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.

~~(a)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).~~

~~NOTE 18 INCOME TAXES~~

The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire. As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at September 30, 2017 and December 31, 2016 relate primarily to utility plant. At September 30, 2017 and December 31, 2016 the New Hampshire BPT effective tax rate was 3.8 percent for both periods and was applied to PNGTS’ taxable income.

Three months ended
September 30,

Nine months ended
September 30,

(unaudited)

(millions of dollars)

2017

2016(a)

2017

2016(a)

State income taxes

Current

—

(7
)
1

1

Deferred

—

7

—

—

—

—

1

1

~~(a)~~ ~~Recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6).~~

NOTE 1917 SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through November ~~6, 2017,~~7, 2019, the date the consolidated financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

On October ~~24, 2017,~~22, 2019, the board of directors of the General Partner declared the Partnership’s third quarter ~~2017~~2019 cash distribution in the amount of ~~$1.00~~$0.65 per common unit payable on November 14, ~~2017~~2019 to unitholders of record as of November ~~3, 2017.~~1, 2019. The declared distribution totaled ~~$75~~$47 million and is payable in the following manner: ~~$70~~$46 million to common unitholders (including $6$4 million to the General Partner as a holder of 5,797,106 common units and ~~$11~~$7 million to another subsidiary of ~~TransCanada~~TC Energy as holder of 11,287,725 common units) and $5$1 million to the General Partner ~~which included $2 million~~ for its ~~effective two~~2 percent general partner ~~interest and $3 million~~interest. The General Partner did not receive any distributions in respect of its ~~IDRs.~~IDRs for the third quarter of 2019.

Northern Border declared its September ~~2017~~2019 distribution of ~~$14~~$15 million on October 9, ~~2017,~~2019, of which the Partnership ~~will receive~~received its 50 percent share or $7 million on October ~~31, 2017.~~18, 2019.

Great Lakes declared its third quarter ~~2017~~2019 distribution of $2$23 million on October ~~19, 2017,~~15, 2019, of which the Partnership received its 46.45 percent share or $11 million on October 18, 2019.

Iroquois declared its third quarter 2019 distribution of $28 million on November 1, 2019, of which the Partnership will receive ~~its 46.45 percent share or $1 million on November 1, 2017.~~

~~Iroquois declared its third quarter 2017 distribution of $28 million on October 23, 2017, of which the Partnership received~~ its 49.34 percent share or $14 million on ~~November 1, 2017. The~~December 30, 2019.

PNGTS declared its third quarter 2019 distribution ~~includes our 49.34 percent share~~ of ~~the Iroquois unrestricted cash distribution amounting~~$10 million on October 9, 2019, of which $4 million was paid to ~~approximately $2.6 million (Refer to Note 6).~~its non-controlling interest owner on October 18, 2019.

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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 Annual Report on Form 10-K for the year ended December 31, 2016, in which certain parts of the report were amended through the Partnership’s filing of Current Report on Form 8-K dated August 3, 2017 to give retrospective adjustments to include the results of operations and financial position of PNGTS for all periods presented (Refer to Notes 2 and 6 within Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q).2018.

RECENT BUSINESS DEVELOPMENTS

Cash Distributions —

On April ~~25, 2017,~~23, 2019, the board of directors of our General Partner declared the ~~Partnership’s~~Partnership's first quarter ~~2017~~2019 cash distribution in the amount of ~~$0.94~~$0.65 per common unit, ~~payable~~which was paid on May ~~15, 2017~~13, 2019 to unitholders of record as of May ~~5, 2017.~~3, 2019. The declared distribution totaled ~~$68~~$47 million and was ~~paid~~payable in the following manner: ~~$65~~$46 million to common unitholders (including $5$4 million to the General Partner as a holder of 5,797,106 common units and ~~$11~~$7 million to another subsidiary of ~~TransCanada~~TC Energy as holder of 11,287,725 common units) and $3$1 million to our General Partner ~~which included $1 million~~ for its ~~effective~~ two percent general partner ~~interest and $2 million in respect of its IDRs.~~interest.

On July ~~20, 2017,~~23, 2019, the board of directors of our General Partner declared the Partnership’s second quarter ~~2017~~2019 cash distribution in the amount of ~~$1.00~~$0.65 per common unit, ~~payable~~which was paid on August ~~11, 2017~~14, 2019 to unitholders of record as of August ~~1, 2017.~~2, 2019. The declared distribution totaled ~~$74~~$47 million and was ~~paid~~payable in the following manner: ~~$69~~$46 million to common unitholders (including $6$4 million to the General Partner as a holder of 5,797,106 common units and ~~$11~~$7 million to another subsidiary of ~~TransCanada~~TC Energy as holder of 11,287,725 common units) and $5$1 million to our General Partner ~~which included $2 million~~ for its ~~effective~~ two percent general partner ~~interest and $3 million in respect of its IDRs.~~interest.

On October ~~24, 2017,~~22, 2019, the board of directors of our General Partner declared the Partnership’s third quarter ~~2017~~2019 cash distribution in the amount of ~~$1.00~~$0.65 per common unit, payable on November 14, ~~2017~~2019 to unitholders of record as of November ~~3, 2017.~~1, 2019. The declared distribution totaled ~~$75~~$47 million and iswas payable in the following manner: ~~$70~~$46 million to common unitholders (including $6$4 million to the General Partner as a holder of 5,797,106 common units and ~~$11~~$7 million to another subsidiary of ~~TransCanada~~TC Energy as holder of 11,287,725 common units) and $5$1 million to our General Partner ~~which included $2 million~~ for its ~~effective~~ two percent general partner ~~interest and $3 million~~interest.

The General Partner did not receive any distributions in respect of its ~~IDRs.~~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.

~~Pipeline updates~~Iroquois

-~~Great Lakes Contracting and Settlement~~- On ~~April 24, 2017, Great Lakes reached~~February 28, 2019, Iroquois filed an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.

~~On October 30, 2017, Great Lakes filed a rate~~uncontested settlement with FERC to ~~satisfy~~address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its ~~obligations from~~prior 2016 settlement. Among the terms of the 2019 Iroquois Settlement, Iroquois agreed to reduce its ~~2013 rate settlement for new~~existing maximum system rates by 6.5 percent to be implemented in ~~effect by January~~two phases, (i) effective March 1, ~~2018.~~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 ~~2017 Great Lakes~~2019 Iroquois Settlement, ifwhich was approved by FERC ~~will decrease Great Lakes’ maximum transportation rates~~on May 2, 2019, preserved the 2016 settlement moratorium on further rate changes until September 1, 2020. Unless superseded by 27 percent beginning October 1, 2017. Great Lakes expects that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakesa subsequent rate case or settlement, Iroquois will be required to ~~file for~~have new rates ~~no later than~~in effect by March ~~31, 2022,~~1, 2023.

Tuscarora - On March 15, 2019, Tuscarora filed an uncontested settlement with ~~new rates to be effective October 1, 2022.~~

~~Northern Border Rate Case-~~ Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement. Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term. At this time, we do not believe that the final outcome of the settlement will have a material impact to the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.

~~Northern Border Contracting~~ — Northern Border revenues are now substantially supported by firm transportation contracts through March 2020. The continued successful renewals of these contracts provide a strong indication of Northern Border’s attractiveness to its customers.

~~PNGTS Projects~~

~~Continent to Coast (C2C) Project~~

As previously reported in our 2016 Annual Report on the Form 10-K dated February 28, 2017, PNGTS filed to increase its FERC-certificated capacity as contemplated in its Continent-to-Coast (C2C) contracts, bringing its capacity capability up to 210,000 Dth/day effective November 1, 2017. PNGTS has not received full regulatory approvals to date but will cooperatively work with C2C shippers while awaiting approvals.

~~Portland XPress Project~~

PNGTS has executed Precedent Agreements with several Local Distribution Companies in New England and Atlantic Canada to re-contract certain system capacity set to expire in 2019 as well as expand the PNGTS system to bring its certificated capacity up to 0.3 Bcf/d. The approximately $80 million Portland XPress Project (PXP) will proceed concurrently with upstream capacity expansions. The in-service dates of PXP are being phased-in over a three-year period beginning November 1, 2018.

~~Acquisitions and Financing~~

~~Debt Offering~~ — On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition (Refer to Note 6 within Item 1. “Financial Statements” of this Quarterly Report on Form 10Q).

~~2017 Acquisition~~ — On June 1, 2017, the Partnership completed the acquisitions of a 49.34 percent interest in Iroquois from subsidiaries of TransCanada including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS that resulted in the Partnership owning a 61.71 percent interest in PNGTS. The total purchase price of the 2017 Acquisition was $765 million plus the final purchase price adjustments amounting to approximately $50 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected the Partnership’s 49.34 percent share of Iroquois outstanding debt at the time of the 2017 Acquisition (ii) $55 million for the additional 11.81 percent in PNGTS (less $5 million, which reflected our 11.81 percent share in PNGTS’ outstanding debt at the time of the 2017 Acquisition) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration on Iroquois’ surplus cash amounting to $28 million. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 25, 2017 public debt offering and borrowing under its Senior Credit Facility

As at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.

~~Additionally, Iroquois’ partners adopted a distribution resolution~~ to address the ~~significant cash on Iroquois’ balance sheet post-closing. The Partnership expects~~issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to ~~receive the $28 million of unrestricted cash as part of~~ its ~~quarterly distributions from Iroquois over 11 quarters under~~prior 2016 settlement. Among the terms of the ~~resolution, which began with Iroquois’ second quarter 2017 distribution on~~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, ~~2017. As of November 6, 2017~~2019 through the ~~Partnership has received approximately $5.2 million~~term of the ~~expected $28~~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 ~~$2.6~~$50 million was received ~~on November 1, 2017.~~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 Iroquois pipeline transports natural gas under long-term contracts and extends from the TransCanada Mainline system at the U.S. border near Waddington, New York to markets in the U.S. northeast, including New York City, Long Island and Connecticut. Iroquois provides service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, directly or indirectly, through interconnecting pipelines and exchanges throughout the northeastern U.S. Both the Iroquois and PNGTS pipelines are critical natural gas infrastructure systems in the Northeast U.S. market and the addition ofdebt covenants requiring Iroquois to ~~the Partnership’s asset portfolio will further diversify our cash flow.~~

~~Tuscarora Refinancing~~ ~~— On August 21, 2017, Tuscarora refinanced all of its outstanding~~maintain a debt ~~by amending its existing Unsecured Term Loan Facility~~to capitalization ratio below 75 percent and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio ~~(cash available~~of at least 1.25 times for the four preceding quarters are unchanged from ~~operations divided~~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 ~~sum~~result of ~~interest expense~~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 ~~principal payments)~~(d) $1 million scheduled payment on Tuscarora's Unsecured Term Loan offset by $11 million of ~~greater than~~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 ~~equal~~waiver of certain conditions precedent.

PNGTS’ Portland XPress Project - Our Portland XPress Project or “PXP” was initiated in 2017 in order to ~~3.00~~expand deliverability on the PNGTS system to ~~1.00.~~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, ~~2017,~~2019, the ~~ratio~~costs incurred to date by TC Energy on the construction of these facilities was ~~3.08 to 1.00.~~

~~2013 Term Loan Facility~~ - On September 29, 2017, the Partnership’s variable rate 2013 $500 million Term loan facility that was due on July 1, 2018 was amended to extend the maturity period through October 2, 2022. At September 30, 2017, the $500 million 2013 Term loan facility is hedged by fixed interest rate swap arrangements at an effective interest rate of 2.31 percent, expiring July 1, 2018.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 ~~extension,~~project is still to be determined as the ~~Partnership implemented an interest rate hedging strategy~~optimal facility set is finalized during the ~~fourth quarter~~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 ~~hedged~~expansion project is $335 million. The project’s reliability work is anticipated to be in service by the ~~entire $500~~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 ~~until its October 2, 2022 maturity using forward starting swaps~~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 ~~average rate~~existing Tuscarora facility. Tuscarora XPress is 100 percent underpinned by a 20-year contract and will transport approximately 15,000 Dth/day of ~~3.26 percent.~~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.

~~2015 Term Loan Facility~~Pipeline Safety Matters ~~-On September 29, 2017,~~-On October 1, 2019, the ~~Partnership’s 2015 $170 million Term loan facility~~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 ~~was due~~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, ~~2018 was amended~~2019. This final rule, which replaces an interim final rule issued by PHMSA in 2016, allows PHMSA to ~~extend~~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 ~~maturity period through October 1, 2020.~~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 use EBITDA as a proxy of our operating cash flow and current operating profitability.

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 and Distributable Cash Flow” for more information.

RESULTS OF OPERATIONS

Our ~~equity~~ownership interests in ~~Northern Border, Great Lakes, and effective June 1, 2017, Iroquois and full ownerships of GTN, Bison, North Baja and Tuscarora and beginning also on June 1, 2017, 61.71 percent ownership in PNGTS~~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.

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Three months
ended

Nine months
ended

(unaudited)

September 30,

$

%

September 30,

$

%

(millions of dollars)

2017

2016(a)

Change*

Change*

2017

2016(a)

Change*

Change*

Transmission revenues

100

103

(3
)
(3
)
313

315

(2
)
(1
)
Equity earnings

27

22

5

23

87

75

12

16

Operating, maintenance and administrative

(24
)
(23
)
(1
)
(4
)
(74
)
(67
)
(7
)
(10
)
Depreciation

(25
)
(24
)
(1
)
(4
)
(73
)
(71
)
(2
)
(3
)
Financial charges and other

(23
)
(18
)
(5
)
(3
)
(59
)
(53
)
(6
)
(11
)
Net income before taxes

55

60

(5
)
(8
)
194

199

(5
)
(3
)
State income taxes

—

—

—

—

(1
)
(1
)
—

—

Net income

55

60

(5
)
(8
)
193

198

(5
)
(3
)
Net income attributable to non-controlling interests

1

2

1

50

7

10

3

30

Net income attributable to controlling interests

54

58

(4
)
7

186

188

(2
)
1

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

~~(a)~~ ~~Financial information was recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6 within Item 1. “Financial Statements”).~~

Three Months Ended September 30, ~~2017~~2019 compared to Same Period in ~~2016~~2018

~~Net income attributable to controlling interests~~ - The Partnership’s net income attributable to controlling interests ~~was lower~~decreased by $4$6 million in the three months ended September 30, 2019 compared to ~~prior~~the same period in 2018, mainly due to the ~~net effect of lower revenues and overall higher costs partially offset by higher equity earnings.~~following:

Transmission revenues — - Revenues were lower due largely to ~~lower discretionary revenues~~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 ~~short-term services sold~~Bison and terminate the associated transportation agreements. Revenues were also impacted by ~~PNGTS.~~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 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 $5$3 million ~~increase~~decrease was primarily due to the ~~addition of equity earnings from Iroquois, resulting from the addition of Iroquois to our portfolio of assets effective June 1, 2017 partially offset by lower equity earnings from Northern Border~~following:

●

decrease in equity earnings from Great Lakes 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 ~~Great Lakes due to higher pipeline integrity program spending and other operating costs.~~ maintenance expenses -The increase in ~~pipeline integrity work at Great Lakes is~~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 ~~relation to~~depreciation expense was a direct result of the ~~increase in natural gas flows which have been ramping up~~elimination of Bison's depreciable base during the ~~year.~~fourth quarter of 2018.

~~Operating, maintenance and administrative costs -~~ The $1 million increase was mainly attributable to higher pipeline integrity on GTN and overall higher allocated management and operational expenses on our pipeline systems as performed by TransCanada.

Financial charges and other - The $5$3 million ~~increase~~decrease was ~~mainly~~primarily attributable to ~~additional borrowings to finance~~ the ~~2017 Acquisition.~~

~~Net-income attributable to non-controlling interests~~ ~~- The Partnership’s net income attributable to non- controlling interests was lower due to lower earnings from PNGTS~~full repayment of our $170 million term loan during the ~~period.~~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, ~~2017~~2019 compared to Same Period in ~~2016~~2018

~~Net income attributable to controlling interests~~ - The Partnership’s net income attributable to controlling interests ~~was lower~~decreased by $2$27 million in the nine months ended September 30, 2019 compared to ~~prior period~~2018, mainly due to the following:

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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 ~~lower revenues~~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 ~~overall higher costs partially offset by higher equity earnings.~~

~~Transmission revenues —~~ maintenance expenses~~Comparable to prior year~~ - The increase in operation and maintenance expenses was primarily due to ~~higher discretionary revenues on short-term services sold by GTN offset by lower discretionary revenues on short-term services sold by PNGTS and lower transportation rates on Tuscarora~~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 ~~settlement reached with its customers effective August 1, 2016.~~the long-lived asset impairment recognized during the fourth quarter of 2018 on Bison which effectively eliminated the depreciable base of the pipeline.

~~Equity Earnings -~~ ~~The $12 million increase was primarily due the addition of equity earnings from Iroquois, effective June 1, 2017.~~

~~Operating, maintenance and administrative costs -~~ The $7 million increase was mainly attributable to higher pipeline integrity on GTN and overall higher allocated management and operational expenses on our pipeline systems as performed by TransCanada.

Financial charges and other - The $6 million ~~increase~~decrease was ~~mainly~~primarily attributable to ~~additional borrowings to finance~~ the ~~2017 Acquisition.~~

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

~~2017~~

As discussed in Note 89 within Item 1.1 “Financial Statements,” we allocated $8$1 million of the Partnership’s net income attributable to controlling interests to the Class B units in the three and nine months ended September 30, ~~2017, respectively,~~2019, representing the excess of 30 percent of GTN’s distribution over the ~~2017~~2019 threshold level of $20 ~~million.~~million, which was further reduced by the estimated Class B Reduction for 2019. This allocation reduced net income attributable to the common units and accordingly, reduced net income per common unit by approximately ~~12 cents~~$0.01 cent for both the three and nine months ended September 30, ~~2017, respectively.~~2019.

~~2016~~

We allocated ~~$11 million and $12~~$4 million of the Partnership’s net income attributable to controlling interests to the Class B units in the three and nine months ended September 30, ~~2016, respectively,~~2018, representing the excess of 30 percent of GTN’s distribution over the ~~2016~~2018 threshold level of $20 ~~million.~~million, which was further reduced by the estimated Class B Reduction for 2018. This allocation reduced net income

attributable to the common units and accordingly, reduced net income per common unit by approximately 17$0.05 cents ~~and 19 cents~~ for both the three and nine months ended September 30, ~~2016, respectively.~~2018.

Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our principal sources of liquidity and cash flows 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. The Partnership funds its operating expenses, debt service and cash distributions (including those distributions made to ~~TransCanada~~TC Energy through our General Partner and as holder of all our Class B units) primarily with operating cash flow. ~~Long-term capital needs may be met through~~

At September 30, 2019, the ~~issuance~~balance of our cash and cash equivalents was higher than our position at December 31, 2018 by approximately $57 million and our long-term debt ~~and/or equity.~~ ~~Overall, we~~balance was lower by $115 million. We continue to use available cash to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics.

We believe ~~that~~ our ~~pipeline systems’ ability to obtain financing at reasonable rates, together with a history of consistent~~ cash ~~flow from~~position, remaining borrowing capacity on our Senior Credit Facility (see table below), and our operating ~~activities, provide a solid foundation to meet future liquidity and capital requirements. We expect to be able~~cash flows are sufficient to fund our short-term liquidity requirements, including distributions to our ~~distributions~~unitholders, ongoing capital expenditures and required debt ~~repayments, at the Partnership level over the next 12 months utilizing our cash flow and, if required, our existing Senior Credit Facility.~~repayments.

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

(unaudited) (millions of dollars)	September 30, 2017	December 31, 2016


(unaudited)
(millions of dollars)			September 30, 2019	December 31, 2018

Total capacity under the Senior Credit Facility	500	500	500	500
Less: Outstanding borrowings under the Senior Credit Facility	255	160	—	40
Available capacity under the Senior Credit Facility	245	340	500	460

~~Our pipeline systems’~~The 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 pipeline systems have historically funded operating expenses, debt service and cash distributions to their owners primarily with operating cash flow. However, since the fourth quarter of 2010, Great Lakes has funded its debt repayments with cash calls to its owners. Additionally, ~~on September 1, 2017, the Partnership made an equity contribution to~~in June 2019, Northern Border borrowed an additional $100 million under its $200 million revolving credit facility to finance a cash distribution of ~~$83 million. This amount represents~~$100 million, of which $50 million was received by the ~~Partnership’s 50 percent share of a one time $166~~Partnership. The Partnership used the $50 million ~~capital contribution request from Northern Border~~proceeds to ~~reduce the outstanding balance of~~partially pay its ~~revolver debt to increase its available borrowing capacity.~~2013 Term Loan Facility due in 2021.

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’~~systems' owners. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends on their financial position and general market 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 by FERC, allow them to request credit support as circumstances dictate.

Table of Contents

Cash Flow Analysis for the Nine ~~Months Ended~~months ended September 30, ~~2017~~2019 compared to Same Period in ~~2016~~2018

	Nine months ended

					Nine months ended
(unaudited)	September 30,				September 30,
(millions of dollars)	2017		2016 (a)		2019	2018


Net cash provided by (used in):
Operating activities	311		332		344	354
Investing activities	(756	)	(215	)	1	(24)
Financing activities	454		(95	)	(288)	(315)
Net decrease in cash and cash equivalents	9		22
Net increase in cash and cash equivalents					57	15
Cash and cash equivalents at beginning of the period	64		55		33	33
Cash and cash equivalents at end of the period	73		77		90	48

~~(a)~~ ~~Financial information was recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6 within Item 1. “Financial Statements”).~~

Operating Cash Flows

~~Net~~In the nine months ended September 30, 2019, the Partnership's net cash provided by operating activities decreased by ~~$21~~$10 million compared to the same period in 2018 primarily 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:

o lower maintenance capital spending during the nine months ended September 30, 2019 on Northern Border;
o net higher earnings generated by Northern Border and Great Lakes compared to the same period in the prior year;
o 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.
Investing Cash Flows
During the nine months ended September 30, 2019, the cash provided by our investing activities was a net cash inflow of $1 million compared to a net outflow of $24 million in the same period in 2018 primarily due to the net impact 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.
Financing Cash Flows
The Partnership's net cash used for financing activities was approximately $27 million lower in the nine months ended September 30, ~~2017~~2019 compared to the same period in ~~2016 primarily due to lower distributions from Great Lakes and Northern Border in 2017 partially offset by distributions received~~ from Iroquois, resulting from the addition of Iroquois to our portfolio of assets effective June 1, 2017. Distributions received in the first quarter of 2016 from Great Lakes were higher than on a run-rate basis due to the resolution of certain regulatory proceedings in the fourth quarter of 2015 which inflated its results during that period and resulted in higher cash flow which was paid to the Partnership in the first quarter of 2016 and not applicable in the first quarter of 2017. Additionally, the Partnership received lower distributions from Northern Border in the current 2017 period compared to the same period in 2016 primarily due to higher maintenance capital expenditures during the current 2017 period together with the change in Northern Border’s distribution policy during 2016 from a lagged quarterly distribution to a more timely monthly distribution that resulted in a larger distribution in the third quarter of 2016.
~~Investing Cash Flows~~
Net cash used in investing activities increased by $541 million in the nine months ended September 30, 2017 compared to the same period in 2016. On January 1, 2016, we invested $193 million to acquire a 49.9 percent interest in PNGTS and on June 1, 2017, we invested $593 million to acquire a 49.34 percent interest in Iroquois and $53 million to acquire an additional 11.81 percent of PNGTS. During the nine months ended September 30, 2017 compared to 2016, we incurred higher maintenance capital expenditures related to major compression equipment overhauls on GTN’s pipeline system and on September 1, 2017, we contributed $83 million to Northern Border representing our 50 percent share of a requested capital contribution to reduce the outstanding balance of its revolving credit facility.
~~Financing Cash Flows~~
~~The net change in cash from our financing activities was approximately $549 million in the nine months ended September 30, 2017 compared to the same period in 2016~~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.

· ~~$564 million increase in net issuances~~Table of ~~debt in 2017 primarily to finance the 2017 Acquisition;~~Contents

· ~~$26 million increase in distributions paid to our common units and to our General Partner in respect of its two percent general partner interest and IDRs;~~

· ~~$10 million increase in distributions paid to Class B units in 2017 as compared to 2016;~~

· ~~$8 million increase in our ATM equity issuances in 2017 as compared to 2016;~~

· ~~$7 million decrease in distributions paid to non-controlling interest due to lower revenues on PNGTS compared to the previous periods; and~~

· $8 million decrease in distributions paid to TransCanada as the former parent of PNGTS primarily due to the Partnership’s acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016 and additional 11.81 percent effective June 1, 2017.

Short-Term Cash Flow Outlook

Operating Cash Flow Outlook

Northern Border declared its September ~~2017~~2019 distribution of ~~$14~~$15 million on October ~~7, 2017,~~9, 2019, of which the Partnership received its 50 percent share or $7 million. The distribution was paid on October ~~31, 2017.~~18, 2019.

Iroquois declared its third quarter ~~2017~~2019 distribution of $28 million on ~~October 23, 2017,~~November 1, 2019, of which the Partnership ~~received~~will receive its 49.34 percent share or $14 million on ~~November 1, 2017.~~December 30, 2019.

~~Our equity investee Iroquois has $2.8 million of scheduled debt repayments for the remainder of 2017 and Iroquois’ debt repayments are expected to be funded through its cash flow from operations.~~

Investing Cash Flow Outlook

The Partnership made an equity contribution to Great Lakes of $4$5 million in the first quarter of ~~2017.~~2019. This amount represents the Partnership’s 46.45 percent share of ~~a $9~~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 ~~2017~~2019 to further fund debt repayments. This is consistent with prior years.

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

Our consolidated entities have commitments of $7$21 million as of September 30, ~~2017~~2019 in connection with various maintenance and general plant projects.

~~Our expected total growth and maintenance capital expenditures on~~In 2019, our pipeline systems ~~as outlined~~expect to invest approximately $97 million in maintenance of existing facilities and approximately $45 million in growth projects, of which the ~~Management Discussion~~Partnership’s share would be $78 million and ~~Analysis of Financial Condition and Results of Operations for~~$30 million, respectively. As our GTN XPress project progresses, we anticipate funding the ~~year ended December 31, 2016 Consolidated Financial Statements and Notes thereto included as Exhibit 99.3~~Partnership's share of the ~~Current Report~~required capital using cash on ~~Form 8-K filed with~~hand and the ~~SEC on August 3, 2017 remain materially unchanged.~~Senior Credit facility, if required.

Financing Cash Flow Outlook

On October ~~24, 2017,~~22, 2019, the board of directors of our General Partner declared the Partnership’s third quarter ~~2017~~2019 cash distribution in the amount of ~~$1.00~~$0.65 per common unit payable on November 14, ~~2017~~2019 to unitholders of record as of November ~~3, 2017.~~1, 2019. Please see Note 17 of the "Financial Statements" within Item 1 and “Recent Business ~~Developments.”~~Developments” within Item 2 for additional disclosures.

We currently intend to refinance GTN’s $100 million 5.29% Unsecured Senior Notes due June 1, 2020, and Tuscarora's $23 million variable rate Unsecured Term Loan due August 21, 2020 in full or at an amount based on our preferred capitalization levels.

Non-GAAP Financial Measures: 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, net income attributable to non-controlling interests, and includes earnings from our equity investments.

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 ~~amount~~amounts presented.

Total distributable cash flow includes EBITDA plus:

· ~~Distributions from our equity investments~~
● Distributions from our equity investments
less:
· ~~Earnings from our equity investments,~~
● Earnings from our equity investments,

· ~~Equity allowance for funds used during construction (Equity AFUDC),~~36

· ~~Interest expense,~~

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

· ~~Distributions to TransCanada as the former parent~~Table of ~~PNGTS, and~~Contents

●

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.

· ~~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 ~~effective~~ two percent interest plus, if applicable, an amount equal to incentive distributions. Distributions allocable to the Class B units in ~~2017~~2019 equal 30 percent of ~~GTN’s~~GTN's distributable cash flow less $20 ~~million.~~million and the Class B Reduction.

Distributable cash flow and EBITDA are performance measures presented to assist ~~investors’~~investors in evaluating our business performance. We believe these measures provide additional meaningful information in evaluating our financial performance and cash generating ~~performance.~~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 ~~Non-GAAP Financial Measures~~Net Income to 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:

	Three months ended				Nine months ended

									Three months ended		Nine months ended
(unaudited)	September 30,				September 30,				September 30,		September 30,
(millions of dollars)	2017		2016 (a)		2017		2016(a)		2019	2018	2019	2018
Net income	55		60		193		198		59	65	216	241


Add:
Interest expense(b)	23		18		60		55
Interest expense ^(a)									22	23	66	71
Depreciation and amortization	25		24		73		71		19	25	58	73
Income taxes	—		—		1		1		—	—	1	1


EBITDA	103		102		327		325		100	113	341	386


Add:
Distributions from equity investments(c)
Northern Border	21		23		61		67
Distributions from equity investments ^{(b) (f)}
Northern Border ^(c)									21	22	69	60
Great Lakes	1		5		28		28		7	10	39	49
Iroquois (d)	14		—		28		—		28	14	56	42
	36		28		117		95
									56	46	164	151
Less:
Equity earnings:
Northern Border	(16	)	(18	)	(50	)	(52	)	(15)	(16)	(50)	(49)
Great Lakes	(2	)	(4	)	(24	)	(23	)	(8)	(9)	(37)	(45)
Iroquois	(9	)	—		(13	)	—		(8)	(9)	(28)	(35)
	(27	)	(22	)	(87	)	(75	)
									(31)	(34)	(115)	(129)
Less:
Interest expense(b)	(23	)	(18	)	(60	)	(55	)
AFUDC equity									—	—	(1)	—
Interest expense ^(a)									(22)	(23)	(66)	(71)
Income taxes	—		—		(1	)	(1	)	—	—	(1)	(1)
Distributions to non-controlling interests(e)	(2	)	(3	)	(10	)	(11	)
Distributions to TransCanada as PNGTS’ former parent(f)	—		—		(1	)	(3	)
Maintenance capital expenditures (g)	(9	)	(3	)	(26	)	(9	)
	(34	)	(24	)	(98	)	(79	)

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	78		84		259		266		80	88	268	303
General Partner distributions declared (h)	(5	)	(4	)	(13	)	(9	)
Distributions allocable to Class B units (i)	(8	)	(11	)	(8	)	(12	)
General Partner distributions declared ^(g)									(1)	(1)	(3)	(3)
Distributions allocable to Class B units ^(h)									(1)	(4)	(1)	(4)
Distributable Cash Flow	65		69		238		245		78	83	264	296

(a)

Interest expense as presented includes net realized loss or gain related 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.

~~(a)~~ ~~Financial information was recast to consolidate PNGTS for all periods presented. Refer to Notes 2 and 6 within Item 1.” Financial Statements”.~~

~~(b)~~ ~~Interest expense as presented includes net realized loss related to the interest rate swaps and amortization~~Table of ~~realized loss on PNGTS’ derivative instruments. Refer to Note 14 within Item 1.” Financial Statements”.~~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.

~~(c)~~ 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 during the current reporting period.

~~(d)~~ This amount represents our proportional 49.34 percent share of the distribution declared by our equity investee Iroquois during the current reporting period and includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million and $5.2 million for the three and nine months ending September 30, 2017, respectively. Refer to Note 6 within Item 1. “Financial Statements”.
~~(e)~~ ~~Distributions to non-controlling interests represent the respective share of our consolidated entities’ distributable cash not owned by us during the periods presented.~~
~~(f)~~ ~~Distributions to TransCanada as PNGTS’ former parent represent TransCanada’s respective share of PNGTS’ distributable cash not owned by us during the periods presented.~~
~~(g)~~ The Partnership’s maintenance capital expenditures include cash 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.
~~(h)~~ Distributions declared to the General Partner for the three and nine months ended September 30, 2017 included an incentive distribution of approximately $3 million and $9 million, respectively (September 30, 2016 — $2 million and $5 million).
~~(i)~~ During the nine months ended September 30, 2017, 30 percent of GTN’s total distributions amounted to $28 million. As a result of exceeding the $20 million threshold during this quarter, $8 million was allocated to the Class B units for both the three and nine months ended September 30, 2017.
During the nine months ended September 30, 2016, 30 percent of GTN’s total distributions amounted to $32 million. As a result of exceeding the $20 million threshold since the end of the second quarter of 2016, $12 million was allocated to the Class B units at September 30, 2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively.
~~Please read Notes 7 and 8 within Item 1. “Financial Statements” for additional disclosures on the Class B units.~~

Three months ended September 30, ~~2017~~2019 Compared to Same Period in ~~2016~~2018

Our EBITDA was ~~comparable~~lower for the third quarter of 2019 compared to the same period in ~~2016.~~2018. The ~~slight increase~~$13 million decrease was primarily due to lower revenue and equity earnings and higher operation and maintenance expenses during the ~~addition of our equity interest on Iroquois effective June 1, 2017 offset by lower revenues and an increase in operational costs~~period as discussed in more detail under the ~~Results~~“Results of ~~Operations~~Operations” section.
Our distributable cash flow decreased by $4$5 million in the third quarter of ~~2017~~2019 compared to the same period in ~~2016~~2018 due to the net effect of:
·    ~~addition of 49.34 percent share of Iroquois’ third quarter 2017 distribution;~~
·    ~~lower distributions from Great Lakes and Northern Border due to their higher pipeline integrity and other operating costs;~~
·    ~~higher maintenance capital expenditures related to major compression equipment overhauls on GTN’s pipeline system;~~
·    ~~increased interest expense due to additional borrowings to finance the 2017 Acquisition;~~
· ~~higher IDRs declared to our General Partner during the current period; and~~
·    ~~lower distributions allocable to the Class B units during the period~~
● 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~~months ended September 30, ~~2017~~2019 Compared to Same Period in ~~2016~~2018
Our EBITDA was ~~comparable~~lower for the nine months ended September 30, 2019 compared to the same period in ~~prior year~~2018. The $45 million decrease was primarily due to ~~the addition of~~lower revenue, lower equity earnings ~~on Iroquois effective June 1, 2017~~and higher operation and maintenance expenses offset by lower ~~revenues and an increase in operational costs~~property taxes during the period as discussed in more detail under the ~~Results~~“Results of ~~Operations~~Operations” section.

Our distributable cash flow decreased by $7$32 million in the nine months ended September 30, ~~2017~~2019 compared to the same period in ~~2016~~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 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.
·    ~~addition~~

Table of ~~49.34 percent share of Iroquois’ second and third quarter 2017 distribution;~~Contents

· ~~higher maintenance capital expenditures related to major compression equipment overhauls on GTN’s pipeline system;~~

· ~~lower distributable cash flow from Northern Border primarily due to its higher operating costs and higher maintenance capital expenditures;~~

· ~~higher IDRs declared to our General Partner during the current period; and~~

· ~~lower distributions allocable to the Class B units during the period.~~

Contractual Obligations

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

The ~~Partnership’s~~Partnership's contractual obligations ~~related to debt~~ as of September 30, ~~2017~~2019 included the following:

	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 Nine Months Ended September 30, 2017

							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	255	—	—	—	255	2.34%	—	—	—	—	—	— %
2013 Term Loan Facility due October 2022	500	—	—	—	500	2.26%
2015 Term Loan Facility due October 2020	170	—	—	170	—	2.15%
2013 Term Loan Facility due 2022							450	—	—	450	—	3.66%
4.65% Senior Notes due 2021	350	—	—	350	—	4.65%(a)	350	—	350	—	—	4.65%	^(a)
4.375% Senior Notes due 2025	350	—	—	—	350	4.375%(a)	350	—	—	—	350	4.375%	^(a)
3.9% Senior Notes due 2027	500	—	—	—	500	3.90%(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)	100	100	—	—	—	5.29%	^(a)
5.69% Unsecured Senior Notes due 2035	150	—	—	—	150	5.69%(a)	150	—	—	—	150	5.69%	^(a)
Unsecured Term Loan Facility due 2019	55	20	35	—	—	1.95%
PNGTS
5.90% Senior Secured Notes due December 2018	36	30	6	—	—	5.90%(a)
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 August 2020	25	1	24	—	—	2.18%
	2,491	51	165	520	1,755
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.

~~(a)~~ ~~Fixed interest rate~~

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 ~~the~~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 30, ~~2017~~2019 was ~~$2,555~~$2,100 million.

Please read Note 57 within Item 1. “Financial Statements” for additional information regarding the ~~Partnership’s~~Partnership's debt.

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

Northern ~~Border’s~~Border's contractual obligations ~~related to debt~~ as of September 30, ~~2017~~2019 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 Nine
Months Ended
September 30,
2017

$200 million Credit Agreement due 2020

16

—

—

16

—

2.11%

7.50% Senior Notes due 2021

250

—

—

250

—

7.50%(b)

266

—

—

266

—

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) 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.
(d) On October 1, 2019, Northern Border's $200 million Credit Agreement was extended to mature on October 1, 2024.
(a) ~~Represents 100 percent of Northern Border’s debt obligations.~~
~~(b)~~ ~~Fixed interest rate~~
~~On September 1, 2017, Northern Border’s $100 million 364-day revolving credit facility was terminated.~~
As of September 30, ~~2017, $16~~2019, $115 million was outstanding under Northern ~~Border’s~~Border's $200 million revolving credit agreement, leaving ~~$184~~$85 million available for future borrowings. At September 30, ~~2017,~~2019, Northern Border was in compliance with all of its financial covenants.

Northern Border has commitments of ~~$12~~$3 million as of September 30, ~~2017~~2019 in connection with compressor station ~~overhaul project~~overhauls and other capital projects.

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

Great ~~Lakes’~~Lakes' contractual obligations ~~related to debt~~ as of September 30, ~~2017~~2019 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 Nine
Months
Ended
September
30, 2017

6.73% series Senior Notes due 2017 to 2018

9

9

—

—

—

6.73%(b)

9.09% series Senior Notes due 2017 and 2021

50

10

20

20

—

9.09%(b)

6.95% series Senior Notes due 2019 and 2028

110

—

22

22

66

6.95%(b)

8.08% series Senior Notes due 2021 and 2030

100

—

—

20

80

8.08%(b)

269

19

42

62

146

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

(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.
(a) ~~Represents 100 percent of Great Lakes’ debt obligations.~~
~~(b)~~ ~~Fixed interest rate~~

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately ~~$145~~$123 million of Great ~~Lakes’ partners’~~Lakes' partners' capital was restricted as to distributions as of September 30, ~~2017~~2019 (December 31, ~~2016~~2018 — ~~$150~~$129 million). Great Lakes was in compliance with all of its financial covenants at September 30, ~~2017.~~2019.

Great Lakes has commitments of $2$5 million as of September 30, ~~2017~~2019 in connection with pipeline integrity program spending, major overhaul projects, and right of way renewals.

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

~~Iroquois’~~Iroquois' contractual obligations ~~related to debt~~ as of September 30, ~~2017~~2019 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 Nine
Months Ended
September 30,
2017

6.63% series Senior Notes due 2019

140

—

140

—

—

6.63%(b)

4.84% series Senior Notes due 2020

150

—

150

—

—

4.84%(b)

6.10% series Senior Notes due 2027

42

5

10

7

20

6.10%(b)

332

5

300

7

20

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.
(a) ~~Represents 100 percent of Iroquois’ debt obligations.~~
~~(b)~~ ~~Fixed interest rate~~

Iroquois has commitments of $2$54 million as of September 30, ~~2017 relative~~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.

Iroquois is restricted under the terms of its note purchase agreement from making cash distributions to its partners unless certain conditions are ~~met.~~met, which remained unchanged with the refinancing transaction. Before a distribution can be made, the debt/capitalization ratio must be below ~~75%,~~75 percent and the debt service coverage ratio must be at least 1.25 times for the four preceding quarters. At September 30, ~~2017,~~2019, the
debt/capitalization ratio was ~~47.6%~~52.2 percent and the debt service coverage ratio was ~~8.04 times,~~5.31 times; therefore, Iroquois was not restricted from making any cash distributions.

~~Critical Accounting Policies and Estimates~~
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to the Partnership’s critical accounting estimates during the three and nine months ended September 30, 2017. Information about our critical accounting estimates is included in our Annual Report on Form 10-K for the year ended December 31, 2016.
Our significant accounting policies have remained unchanged since December 31, 2016 except as described in Note 3 within Item 1. “Financial Statements,” of this quarterly report on Form 10-Q. A summary of our significant accounting policies can be found in our audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-Kdated August 3, 2017. (Refer also to Note 2 in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q).
RELATED PARTY TRANSACTIONS

Please read ~~Notes 6 and 11~~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.

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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 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 LIBOR phase-out will affect the Partnership, but we currently do not expect the impact to be material.

As of September 30, ~~2017,~~2019, the ~~Partnership’s~~Partnership's interest rate exposure resulted from our floating rate ~~Senior Credit Facility, 2015 Term Loan Facility, GTN’s~~on North Baja's Unsecured Term Loan Facility, PNGTS' Revolving Credit Facility and ~~Tuscarora’s~~Tuscarora's Unsecured Term Loan Facility, under which ~~$505~~$103 million, or 205 percent, of our outstanding debt was subject to variability in LIBOR interest ~~rates. As of December~~rates (December 31, 2016, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN’s Unsecured Term Loan Facility and Tuscarora’s Unsecured Term Loan Facility, under which $4052018- $168 million or ~~21 percent of our outstanding debt was subject to variability in LIBOR interest rates.~~8 percent).

As of September 30, ~~2017,~~2019, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was ~~2.31~~3.26 percent. If interest rates hypothetically increased (decreased) on these facilities by one percent ~~100~~(100 basis ~~points,~~points), compared with rates in effect at September 30, ~~2017,~~2019, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $5$1 million.

As of September 30, ~~2017, $16~~2019, $115 million, or 632 percent, of Northern ~~Border’s~~Border's outstanding debt was at floating rates. If interest rates hypothetically increased (decreased) by one percent ~~100~~(100 basis ~~points,~~points), compared with rates in effect at September 30, ~~2017,~~2019, Northern ~~Border’s~~Border's annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately ~~nil~~$1 million.

~~GTN’s~~GTN's Unsecured Senior Notes, Northern ~~Border’s~~Border's and ~~Iroquois’~~Iroquois' Senior Notes, and all of Great ~~Lakes’~~Lakes' and ~~PNGTS’~~PNGTS' Notes represent fixed-rate debt; therefore, they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison, ~~and North Baja,~~ as ~~they currently do~~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's interest rate swaps mature on October 2, 2022 and are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The ~~Partnership hedged~~fixed weighted average interest ~~payments~~rate on these instruments is 3.26 percent. On June 26, 2019, in conjunction with the ~~variable-rate~~Partnership's $50 million repayment on its 2013 Term Loan Facility, ~~with~~the Partnership also terminated an equivalent amount in interest rate swaps ~~maturing July 1, 2018,~~that were used to hedge this facility at a ~~weighted average fixed interest~~ rate of ~~2.31 percent.~~ 2.81 percent (See also Note 13 within Item 1. "Financial Statements").

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At September 30, ~~2017,~~2019, the fair value of the interest rate swaps accounted for as cash flow hedges was ~~an asset~~a liability of $2$8 million (both on a gross and net basis)~~. At December~~ (December 31, ~~2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an~~2018 - asset of ~~$1 million and a liability~~$8 million), the net change of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net income related to ineffectiveness for interest rate hedges for the three and nine months ended September 30, 2017 and 2016. The change in fair value of interest rate derivative instrumentswhich is recognized in other comprehensive ~~income was nil and a gain of $1 million for the three and nine months ended September 30, 2017, respectively (September 30, 2016 — gain of $2 million and a loss of $1 million).~~income. For the three and nine months ended September 30, ~~2017,~~2019, the net realized ~~loss~~gain related to the interest rate swaps was nil and $1 million, respectively, and was included in financial charges and other (September 30, ~~2016 —$1~~2018 - nil and gain of $2 million, ~~and $2 million). Refer to Note 14 within Item 1. “Financial Statements”~~respectively).

~~As discussed in Note 5 within Item 1. Financial Statements,~~COMMODITY PRICE RISK

The Partnership is influenced by the ~~Partnership’s 2013 Term Loan~~same factors that ~~was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. As a result~~influence our pipeline systems. None of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the timeour pipeline systems own any of the ~~refinancing and recorded the realized loss in accumulated other comprehensive income as~~natural gas they transport; therefore, they do not assume any of the termination date. The previously recorded loss is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes. At September 30, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in other comprehensive income was $1 million (December 31, 2016 - $2 million). For the three and nine months ended September 30, 2017, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil and $1 million, respectively (September 30, 2016 —nil and $1 million).related natural gas commodity price risk with respect to transported natural gas volumes.

~~OTHER RISKS~~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
● the fair value of derivative assets

At September 30, 2019, we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired. Additionally, during the three and nine months ended September 30, 2019 and at September 30, 2019, no customer accounted for more than 10 percent of our consolidated revenue and accounts receivable, respectively.

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 customers. The Partnership closely monitors the creditworthiness of our counterparties, including financial ~~institutions.~~institutions, reviews accounts receivable regularly and, if needed, records allowances for doubtful accounts using the specific identification method. However, we cannot predict to what extent our business would be impacted by uncertainty in energy commodity prices, including possible declines in our ~~customers’~~customers' creditworthiness.
Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At September 30, 2017, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At September 30, 2017, we had a credit risk concentration on one of our customers, Anadarko Energy Services Company, which owed us approximately $4 million and this amount represented greater than 10 percent of our trade accounts receivable.

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. ~~Our approach to managing~~We manage our liquidity risk isby continuously forecasting our cash flow on a regular basis to ensure ~~that~~ we ~~always~~ have ~~sufficient~~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, without incurring unacceptable losses or damage~~conditions. Refer to “Liquidity and Capital Resources” section for more information about our reputation. At September 30, 2017, the Partnership had a Senior Credit Facility of $500 million maturing in 2021 and the outstanding balance on this facility was $255 million. In addition, Northern Border had a committed revolving bank line of $200 million maturing in 2020 with $16 million drawn at September 30, 2017. Both the Senior Credit Facility and the Northern Border $200 million credit facility have accordion features for additional capacity of $500 million and $100 million respectively, subject to lender consent.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”)~~(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

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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 30, ~~2017,~~2019, 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~~Partnership's Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2018.

~~Great Lakes v. Essar Steel Minnesota LLC, et al~~~~. —~~
~~A description of this legal proceeding can be found in Note 15 within Item 1, “Financial Statements” of this Quarterly Report on Form 10-Q, and is incorporated herein by reference.~~
~~In addition to the above written matter, we and our pipeline systems are parties to lawsuits and governmental proceedings that arise in the ordinary course of our business.~~
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 Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2018.

~~Following the closing of the 2017 Acquisition, we will~~We do not own ~~a controlling interest in Iroquois, and we will be unable to cause certain actions to take place without~~ the ~~agreement of the other partners.~~
The major policies of Iroquois are established by its management committee, which consists of individuals who are designated by each of the partners and includes one individual designated by us. The management committee requires at least the affirmative vote of a majority of the ~~partners’ percentage interests~~land on which our pipeline systems are located, which could result in higher costs and disruptions to ~~take any action. Because~~our operations, particularly with respect to easements and rights-of-way across Indian tribal lands.

We do not own the majority of the land on which our pipeline systems are located. We obtain easements, rights-of-way and other rights to construct and operate our pipeline systems from individual landowners, Native American tribes, governmental authorities and other third parties. Some of these ~~provisions, without~~rights expire after a specified period of time. As a result, we are subject to the ~~concurrence~~possibility of more onerous terms and increased costs to renew expiring easements, rights-of-way and other ~~partners,~~land use rights. While we ~~would be unable~~are generally able to ~~cause Iroquois to take~~obtain these rights through agreement with land owners or ~~not to take certain actions, even though those actions may be in the best interests~~legal process if necessary, rights-of-way across Indian tribal land require approval of the ~~Partnership~~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 systems could also be subject to a disruption of operations and increased costs to re-route the applicable portion of our pipeline system located on tribal land. Increased costs associated with renewing or ~~Iroquois. Further, Iroquois may seek additional capital contributions. Our funding~~obtaining new easements or rights-of-way and any disruption of ~~these capital contributions would reduce~~operations could negatively impact the ~~amount~~results of operations and cash ~~otherwise~~ 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 ~~our unitholders. In~~obtain new rights-of-way with the ~~event~~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 ~~elected not~~could be required or choose to remove and relocate a portion or ~~were unable~~portions of the Great Lakes pipeline system from the tribal lands at a significant cost. While the outcome of these negotiations or the ability to ~~make~~reach agreements is uncertain, the impact of a ~~capital contribution~~disruption of operations and cost of relocating a portion of the Great Lakes pipeline or significantly increased costs to ~~Iroquois; our ownership interest would be diluted.~~

~~Changes in TransCanada’s costs or their cost allocation practices~~renew the rights-of-way could have ana material adverse effect on our financial condition, results of operations ~~financial position~~ and cash flows.

~~Under~~Chemical substances in the ~~Partnership Agreement, the Partnership’s~~natural gas our pipeline systems ~~operated~~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 ~~TransCanada~~GTN satisfies the standards of its tariff, and that GTN disagrees with any assertions to the contrary. Additionally, GTN and TC Energy are ~~allocated certain costs~~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 ~~operations at TransCanada’s sole discretion. Accordingly, revisions~~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 ~~allocation process or changes to corporate structure may impact the Partnership’s operating results. TransCanada reviews any changes and their prospective impact for reasonableness, however there~~matter. There can be no assurance that ~~allocated operating~~significant additional costs will ~~remain consistent from period~~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 ~~period.~~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.

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.

~~No.~~
~~Description~~
~~2.1~~
Agreement for Purchase and Sale of Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
~~2.1.1~~
First Amendment to Purchase and Sale Agreement by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 31, 2017 (Incorporated by reference from Exhibit 2.1.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~2.2~~
Option Agreement Relating to Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TransCanada Iroquois Ltd. and TC Pipelines Intermediate Limited Partnership as dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.2 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
~~2.3~~
Agreement for Purchase and Sale of Partnership Interest in Portland Natural Gas Transmission System, by and between TCPL Portland Inc., as Seller and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.3 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
3.1

Third Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated April 1, 2015 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed April 1, 2015).
~~3.2~~
Certificate of Limited Partnership of TC PipeLines, LP (Incorporated by reference to Exhibit 3.2 to TC PipeLines, ~~LP’s~~LP's Form S-1 Registration Statement, filed on December 30, 1998).
3.2

Fourth Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated December 31, 2018 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP's Form 8-K filed January 2, 2019).
4.1

~~Portland Natural Gas Transmission System Senior Secured Note Purchase Agreement~~Indenture, dated as of ~~April 10, 2003~~June 17, 2011, between the Partnership and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to TC PipeLines, LP's Form 8-K filed on June 17, 2011).
4.2

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~~LP's Form ~~10-Q~~8-K filed ~~August 3, 2017)~~March 13, 2015).
~~4.2~~4.6

~~Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement~~Third Supplemental Indenture, dated as of May ~~13, 2009~~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 10-Q filed August 3, 2017).~~
~~4.3~~
~~Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement dated as of April 27,~~
~~2010(Incorporated by reference from Exhibit 4.3 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).~~
~~4.4~~
Indenture dated as of May 30, 2000, between Iroquois Gas Transmission System, L.P. and The Chase Manhattan Bank (Incorporated by reference from Exhibit 4.4 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.4.1~~
Second Supplemental Indenture dated as of August 13, 2002, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank) (Incorporated by reference from Exhibit 4.4.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.5~~
Credit Agreement dated as of June 26, 2008, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent (Incorporated by reference from Exhibit 4.5 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.5.1~~
Amendment No. 1 to Credit Agreement dated as of June 25, 2009, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent for the lenders (Incorporated by reference from Exhibit 4.5.1to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.6~~
~~Second Amendment to TC PipeLines LP’s July 1, 2013 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.1 to TC PipeLines, LP’s~~LP's Form 8-K filed ~~October 3,~~May 25, 2017).
~~4.7~~
Amendment No. 1 to TC PipeLines LP’s September 30, 2015 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.2 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
~~4.8~~
First Amendment to TC PipeLines, LP’s Third Amended and Restated Revolving Credit Agreement, dated September 29, 2017(Incorporated by reference from Exhibit 99.3 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
10.1*
~~Transportation Service Agreement FT18966 between Great Lakes Gas Transmission Limited Partnership and TransCanada Pipelines Limited, effective August 4, 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 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.
99.1*

~~Transportation Service Agreement FT18759 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 26, 2017.~~
101.INS*101

~~XBRL Instance Document.~~The following materials from TC Pipelines, LP's Quarterly Report on Form 10-Q for the period ended September 30, 2019 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 Notes to Consolidated Financial Statements (Unaudited).
101.SCH*104

Cover Page Interactive Data File (embedded within the Inline XBRL ~~Taxonomy Extension Schema Document.~~
101.CAL*
~~XBRL Taxonomy Extension Calculation Linkbase Document.~~
101.DEF*
~~XBRL Taxonomy Definition Linkbase Document.~~
101.LAB*
~~XBRL Taxonomy Extension Label Linkbase Document.~~
101.PRE*
~~XBRL Taxonomy Extension Presentation Linkbase Document.~~document)

Table of Contents

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 67^th day of November ~~2017.~~2019.

TC PIPELINES, LP

(A Delaware Limited Partnership)

by its General Partner, TC PipeLines GP, Inc.

By:
/s/ ~~Brandon Anderson~~Nathaniel A. Brown

~~Brandon Anderson~~Nathaniel A. Brown

President

TC PipeLines GP, Inc. (Principal Executive Officer)

By:
/s/ ~~Nathaniel A. Brown~~William C. Morris

~~Nathaniel A. Brown~~William C. Morris

~~Controller~~Vice President and Treasurer

TC PipeLines GP, Inc. (Principal Financial Officer)
~~EXHIBIT INDEX~~

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.
~~No.~~
~~Description~~
~~2.1~~
Agreement for Purchase and Sale of Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
~~2.1.1~~
First Amendment to Purchase and Sale Agreement by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 31, 2017 (Incorporated by reference from Exhibit 2.1.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~2.2~~
Option Agreement Relating to Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TransCanada Iroquois Ltd. and TC Pipelines Intermediate Limited Partnership as dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.2 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
~~2.3~~
Agreement for Purchase and Sale of Partnership Interest in Portland Natural Gas Transmission System, by and between TCPL Portland Inc., as Seller and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.3 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
~~3.1~~
Third Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated April 1, 2015 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed April 1, 2015).
~~3.2~~
~~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).~~
~~4.1~~
Portland Natural Gas Transmission System Senior Secured Note Purchase Agreement dated as of April 10, 2003 (Incorporated by reference from Exhibit 4.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.2~~
~~Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement dated as of May 13, 2009 (Incorporated by reference from Exhibit 4.2 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).~~
~~4.3~~
~~Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement dated as of April 27, 2010(Incorporated by reference from Exhibit 4.3 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).~~
~~4.4~~
Indenture dated as of May 30, 2000, between Iroquois Gas Transmission System, L.P. and The Chase Manhattan Bank (Incorporated by reference from Exhibit 4.4 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.4.1~~
Second Supplemental Indenture dated as of August 13, 2002, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank) (Incorporated by reference from Exhibit 4.4.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.5~~
Credit Agreement dated as of June 26, 2008, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent (Incorporated by reference from Exhibit 4.5 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.5.1~~
Amendment No. 1 to Credit Agreement dated as of June 25, 2009, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent for the lenders (Incorporated by reference from Exhibit 4.5.1to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.6~~
Second Amendment to TC PipeLines LP’s July 1, 2013 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.1 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
~~4.7~~
Amendment No. 1 to TC PipeLines LP’s September 30, 2015 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.2 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
~~4.8~~
First Amendment to TC PipeLines, LP’s Third Amended and Restated Revolving Credit Agreement, dated September 29, 2017(Incorporated by reference from Exhibit 99.3 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
10.1*
~~Transportation Service Agreement FT18966 between Great Lakes Gas Transmission Limited Partnership and TransCanada Pipelines Limited, effective August 4, 2017.~~
31.1*
~~Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.~~
31.2*
~~Certification of Principal 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.~~
99.1*
~~Transportation Service Agreement FT18759 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 26, 2017.~~
101.INS*
~~XBRL Instance Document.~~
101.SCH*
~~XBRL Taxonomy Extension Schema Document.~~
101.CAL*
~~XBRL Taxonomy Extension Calculation Linkbase Document.~~
101.DEF*
~~XBRL Taxonomy Definition Linkbase Document.~~
101.LAB*
~~XBRL Taxonomy Extension Label Linkbase Document.~~
101.PRE*
~~XBRL Taxonomy Extension Presentation Linkbase Document.~~

49

			Page No.
PART I	FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (Unaudited)	67
~~Item 2.~~	~~Management’s~~Notes to Consolidated Financial Statements	12
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2928
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4142
Item 4.	Controls and Procedures	4344

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	43
~~Item 1A.~~	~~Risk Factors~~	45
Item 6.1A.	~~Exhibits~~Risk Factors	45
Item 6.	~~Signatures~~Exhibits	47
	Signatures	48

	Limited Partners
	Common Units			Class B Units			General Partner		Accumulated Other Comprehensive Loss (a) (b)		Non- Controlling Interest(b)		Equity of former parent of PNGTS(b)		Total Equity(b)
(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		millions of dollars

Partners’ Equity at December 31, 2016	67.4	1,002		1.9	117		27		(2	)	97		31		1,272
Net income (b)	—	164		—	8		12		—		7		2		193
Other comprehensive income	—	—		—	—		—		2		—		—		2
ATM equity issuances, net (Note 7)	2.2	124		—	—		2		—		—		—		126
Reclassification of common units no longer subject to rescission (Note 7)	—	81		—	—		2		—		—		—		83
Acquisition of interests in PNGTS and Iroquois (Note 6)	—	(383	)	—	—		(8	)	—		—		(32	)	(423	)
Distributions (b)	—	(198	)	—	(22	)	(12	)	—		(2	)	(1	)	(235	)

Partners’ Equity at September 30, 2017	69.6	790		1.9	103		23		—		102		—		1,018

	Three months ended								Nine months ended
(unaudited)	September 30,				$		%		September 30,				$		%
(millions of dollars)	2017		2016(a)		Change*		Change*		2017		2016(a)		Change*		Change*

Transmission revenues	100		103		(3	)	(3	)	313		315		(2	)	(1	)
Equity earnings	27		22		5		23		87		75		12		16
Operating, maintenance and administrative	(24	)	(23	)	(1	)	(4	)	(74	)	(67	)	(7	)	(10	)
Depreciation	(25	)	(24	)	(1	)	(4	)	(73	)	(71	)	(2	)	(3	)
Financial charges and other	(23	)	(18	)	(5	)	(3	)	(59	)	(53	)	(6	)	(11	)
Net income before taxes	55		60		(5	)	(8	)	194		199		(5	)	(3	)
State income taxes	—		—		—		—		(1	)	(1	)	—		—
Net income	55		60		(5	)	(8	)	193		198		(5	)	(3	)
Net income attributable to non-controlling interests	1		2		1		50		7		10		3		30
Net income attributable to controlling interests	54		58		(4	)	7		186		188		(2	)	1

	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 Nine Months Ended September 30, 2017
$200 million Credit Agreement due 2020	16	—	—	16	—	2.11%
7.50% Senior Notes due 2021	250	—	—	250	—	7.50%(b)
	266	—	—	266	—


	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

~~No.~~		~~Description~~
~~2.1~~		Agreement for Purchase and Sale of Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
~~2.1.1~~		First Amendment to Purchase and Sale Agreement by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 31, 2017 (Incorporated by reference from Exhibit 2.1.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~2.2~~		Option Agreement Relating to Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TransCanada Iroquois Ltd. and TC Pipelines Intermediate Limited Partnership as dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.2 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
~~2.3~~		Agreement for Purchase and Sale of Partnership Interest in Portland Natural Gas Transmission System, by and between TCPL Portland Inc., as Seller and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.3 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
3.1		Third Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated April 1, 2015 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed April 1, 2015).
~~3.2~~		Certificate of Limited Partnership of TC PipeLines, LP (Incorporated by reference to Exhibit 3.2 to TC PipeLines, ~~LP’s~~LP's Form S-1 Registration Statement, filed on December 30, 1998).
3.2		Fourth Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated December 31, 2018 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP's Form 8-K filed January 2, 2019).
4.1		~~Portland Natural Gas Transmission System Senior Secured Note Purchase Agreement~~Indenture, dated as of ~~April 10, 2003~~June 17, 2011, between the Partnership and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to TC PipeLines, LP's Form 8-K filed on June 17, 2011).
4.2		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~~LP's Form ~~10-Q~~8-K filed ~~August 3, 2017)~~March 13, 2015).
~~4.2~~4.6		~~Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement~~Third Supplemental Indenture, dated as of May ~~13, 2009~~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 10-Q filed August 3, 2017).~~
~~4.3~~		~~Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement dated as of April 27,~~

		~~2010(Incorporated by reference from Exhibit 4.3 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).~~
~~4.4~~		Indenture dated as of May 30, 2000, between Iroquois Gas Transmission System, L.P. and The Chase Manhattan Bank (Incorporated by reference from Exhibit 4.4 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.4.1~~		Second Supplemental Indenture dated as of August 13, 2002, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank) (Incorporated by reference from Exhibit 4.4.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.5~~		Credit Agreement dated as of June 26, 2008, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent (Incorporated by reference from Exhibit 4.5 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.5.1~~		Amendment No. 1 to Credit Agreement dated as of June 25, 2009, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent for the lenders (Incorporated by reference from Exhibit 4.5.1to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
~~4.6~~		~~Second Amendment to TC PipeLines LP’s July 1, 2013 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.1 to TC PipeLines, LP’s~~LP's Form 8-K filed ~~October 3,~~May 25, 2017).
~~4.7~~		Amendment No. 1 to TC PipeLines LP’s September 30, 2015 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.2 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
~~4.8~~		First Amendment to TC PipeLines, LP’s Third Amended and Restated Revolving Credit Agreement, dated September 29, 2017(Incorporated by reference from Exhibit 99.3 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
10.1*		~~Transportation Service Agreement FT18966 between Great Lakes Gas Transmission Limited Partnership and TransCanada Pipelines Limited, effective August 4, 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 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.
99.1*		~~Transportation Service Agreement FT18759 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 26, 2017.~~
101.INS*101		~~XBRL Instance Document.~~The following materials from TC Pipelines, LP's Quarterly Report on Form 10-Q for the period ended September 30, 2019 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 Notes to Consolidated Financial Statements (Unaudited).
101.SCH*104		Cover Page Interactive Data File (embedded within the Inline XBRL ~~Taxonomy Extension Schema Document.~~
101.CAL*		~~XBRL Taxonomy Extension Calculation Linkbase Document.~~
101.DEF*		~~XBRL Taxonomy Definition Linkbase Document.~~
101.LAB*		~~XBRL Taxonomy Extension Label Linkbase Document.~~
101.PRE*		~~XBRL Taxonomy Extension Presentation Linkbase Document.~~document)


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

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

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