UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM10-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 June 30, ~~2018~~2019

or☐

oTRANSITION 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 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 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).
Yesx⌧ 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 ~~August 1, 2018,~~July 30, 2019, there were 71,306,396 of the registrant’s common units outstanding.

Table of Contents
TC PIPELINES, LP
TABLE OF CONTENTS

Page No.
PART I
FINANCIAL INFORMATION

Item 1.
Consolidated Financial Statements (Unaudited)
7
~~Item 2.~~
~~Management’s~~Notes to Consolidated Financial Statements
12
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
3028
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
4341
Item 4.
Controls and Procedures
4544

PART II
OTHER INFORMATION

Item 1.
Legal Proceedings
4544
Item 1A.
Risk Factors
4544
Item 6.
Exhibits
4846

Signatures
5047

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

2
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 term loan credit facility under a term loan agreement as amended, dated September 29, 2017~~
~~2015 GTN Acquisition~~
~~Partnership’s acquisition of the remaining 30 percent interest in GTN on April 1, 2015~~
~~2015 Term Loan Facility~~
~~TC PipeLines, LP’s~~LP's term loan credit facility under a term loan agreement as amended, dated September 29, 2017
2017 ~~Acquisition~~
~~Partnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017~~
~~2017 Great Lakes Settlement~~
~~Stipulation and Agreement of Settlement for Great Lakes regarding its rates and terms and conditions of service approved by FERC on February 22, 2018~~
~~2017 Northern Border Settlement~~
~~Stipulation and Agreement of Settlement for Northern Border regarding its rates and terms and conditions of service approved by FERC on February 23, 2018~~
~~2017~~ Tax Act

~~H.R.1, originally~~Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act, enacted on December 22, 2017
2018 FERC Actions

~~FERC’s March 15,~~FERC's 2018 issuance of ~~(1) a revised~~Revised Policy Statement ~~to address the treatment~~on Treatment of ~~income taxes for ratemaking purposes for master limited partnerships (MLPs), (2)~~Income Taxes (Revised Policy Statement) and a ~~Notice of Proposed Rulemaking (NOPR) proposing~~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, ~~to quantify~~called FERC Form No. 501-G, that quantified the rate impact of the ~~federal income tax rate reduction~~2017 Tax Act on FERC-regulated pipelines and the revised Policy Statement could have on pipelines’ revenue requirements, and (3) a Notice of Inquiry (NOI) seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation; and FERC’s July 18, 2018 issuance of (1) an Order on Rehearingimpact of the Revised Policy Statement ~~dismissing rehearing related~~on pipelines held by an MLP
2019 Iroquois Settlement

An uncontested settlement filed by Iroquois with FERC to address the ~~revised Policy Statement~~issues contemplated by the 2017 Tax Act and ~~(2) a Final Rule adopting procedures from,~~2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
2019 Tuscarora Settlement

An uncontested settlement filed by Tuscarora with FERC to address the issues contemplated by the 2017 Tax Act and ~~clarifying aspects of, the NOPR~~2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
ADIT

Accumulated Deferred Income Tax
ASC

Accounting Standards Codification
~~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
~~C2C Contracts~~Class B Reduction

~~PNGTS’ Continent-to-Coast Contracts with several shippers~~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 ~~a term~~any particular calendar year until distributions payable in respect of ~~15 years~~common units for ~~approximately 82,000 Dth/day~~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
IDRs

Incentive Distribution Rights
ILPs

Intermediate Limited Partnerships
Iroquois

Iroquois Gas Transmission System, L.P.
LIBOR

London Interbank Offered Rate
~~MLPs~~
~~Master limited partnerships~~
~~NGA~~
~~Natural Gas Act of 1938~~
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
~~PHMSA~~
~~U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration~~
PNGTS

Portland Natural Gas Transmission System
PXP

Portland XPress Project
3
Table of Contents
~~Term Loan Facilities~~ROU

~~The 2013 Term Loan Facility and the 2015 Term Loan Facility, collectively~~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
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).

4
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;
● the impact of Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act (“2017 Tax Act”) enacted on December 22, 2017 on our future operating performance;
● 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), TransCanada Corporation, now known as 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;
5
Table of ~~our pipeline systems to sell available capacity on favorable terms and renew expiring contracts which are affected by, among other factors:~~Contents
● 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.
·        ~~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;~~
·        ~~the impact of the 2017 Tax Act and the 2018 FERC Actions on our future operating performance;~~
·        ~~other potential changes in taxation of master limited partnerships (MLPs) by state or federal governments;~~
·        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;~~
·        ~~the ability to maintain secure operation of our information technology including management of cybersecurity threats, acts of terrorism and related distractions;~~
·        ~~the expected impact of future accounting changes, commitments and contingent liabilities (if any);~~
·        ~~operating hazards, casualty losses and other matters beyond our control;~~
·        ~~the level of our indebtedness, including the indebtedness of our pipeline systems, and the availability of capital;~~
·        ~~unfavorable conditions in capital and credit markets, inflation and fluctuations in interest rates; and~~
·        ~~the overall increase in the allocated management and operational expenses on our pipeline systems for functions 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 1A1A. “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, ~~2017~~2018 as filed with the SEC on February ~~26, 2018.~~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.

6
Table of Contents
PART I — FINANCIAL INFORMATION

Item 1.Financial Statements

TC PIPELINES, LP
CONSOLIDATED STATEMENTS OF INCOME

Three months ended

Six months ended

(unaudited)

June 30,

June 30,

(millions of dollars, except per common unit amounts)

2018

2017

2018

2017

Transmission revenues

111

101

226

213

Equity earnings (Note 5)

36

24

95

60

Operation and maintenance expenses

(17
)
(17
)
(33
)
(31
)
Property taxes

(7
)
(7
)
(14
)
(14
)
General and administrative

(1
)
(2
)
(2
)
(4
)
Depreciation

(24
)
(25
)
(48
)
(49
)
Financial charges and other (Note 15)

(23
)
(19
)
(46
)
(36
)
Net income before taxes

75

55

178

139

Income taxes (Note 18)

—

—

(1
)
(1
)
Net income

75

55

177

138

Net income attributable to non-controlling interests

2

—

8

6

Net income attributable to controlling interests

73

55

169

132

Net income attributable to controlling interest allocation (Note 9)

Common units

72

50

166

122

General Partner

1

5

3

8

TransCanada and its subsidiaries

—

—

—

2

73

55

169

132

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

$
1.00

$
0.73

$
2.33

$
1.78

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

71.3

68.9

71.2

68.6

Common units outstanding, end of period (millions)

71.3

69.0

71.3

69.0

T~~he accompanying notes are an integral part of these consolidated financial statements.~~
~~TC PIPELINES, LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

Three months ended

Six months ended

(unaudited)

June 30,

June 30,

(millions of dollars)

2018

2017

2018

2017

Net income

75

55

177

138

Other comprehensive income

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

(1
)
—

6

1

Amortization of realized loss on derivative financial instruments (Note 13)

2

1

2

1

Reclassification to net income of gains and losses on cash flow hedges (Note 13)

3

(1
)
3

(1
)
Comprehensive income

79

55

188

139

Comprehensive income attributable to non-controlling interests

3

—

9

6

Comprehensive income attributable to controlling interests

76

55

179

133

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

Three months ended

Six months ended
(unaudited)

June 30,

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

2019

2018

2019

2018

Transmission revenues

93

111

206

226
Equity earnings (Note 5)

30

36

84

95
Operation and maintenance expenses

(17)

(17)

(33)

(33)
Property taxes

(6)

(7)

(13)

(14)
General and administrative

(2)

(1)

(4)

(2)
Depreciation and amortization

(19)

(24)

(39)

(48)
Financial charges and other (Note 15)

(21)

(23)

(43)

(46)
Net income before taxes

58

75

158

178
Income taxes

(1)

—

(1)

(1)
Net income

57

75

157

177
Net income attributable to non-controlling interest

2

2

9

8
Net income attributable to controlling interests

55

73

148

169

Net income attributable to controlling interest allocation (Note 9)

Common units

54

72

145

166
General Partner

1

1

3

3

55

73

148

169

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

$
0.75

$
1.00

$
2.03

$
2.33

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

71.3

71.3

71.3

71.2

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)

June 30, 2018

December 31, 2017

ASSETS

Current Assets

Cash and cash equivalents

51

33

Accounts receivable and other (Note 14)

40

42

Inventories

8

8

Other

9

7

108

90

Equity investments (Note 5)

1,211

1,213

Plant, property and equipment (Net of $1,229 accumulated depreciation; 2017 - $1,181)

2,086

2,123

Goodwill

130

130

Other assets

11

3

3,546

3,559

LIABILITIES AND PARTNERS’ EQUITY

Current Liabilities

Accounts payable and accrued liabilities

27

31

Accounts payable to affiliates (Note 12)

6

5

Distribution payable

—

1

Accrued interest

12

12

Current portion of long-term debt (Note 7)

36

51

81

100

Long-term debt, net (Note 7)

2,272

2,352

Deferred state income taxes (Note 18)

10

10

Other liabilities

28

29

2,391

2,491

Partners’ Equity

Common units

912

824

Class B units (Note 8)

95

110

General partner

22

24

Accumulated other comprehensive income (AOCI)

15

5

Controlling interests

1,044

963

Non-controlling interests

111

105

1,155

1,068

3,546

3,559

~~Contingencies~~ ~~(Note 16)~~
~~Variable Interest Entities~~ ~~(Note 17)~~
~~Subsequent Events~~ ~~(Note 19)~~

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

7
Table of Contents
TC PIPELINES, LP
CONSOLIDATED ~~STATEMENT~~STATEMENTS OF ~~CASH FLOWS~~COMPREHENSIVE INCOME

Six months ended

(unaudited)

June 30,

(millions of dollars)

2018

2017

Cash Generated From Operations

Net income

177

138

Depreciation

48

49

Amortization of debt issue costs reported as interest expense

1

1

Amortization of realized loss on derivative instrument (Note 13)

2

1

Accrual for costs related to the 2017 Acquisition

—

1

Equity earnings from equity investments (Note 5)

(95
)
(60
)
Distributions received from operating activities of equity investments (Note 5)

96

68

Change in other long term liabilities

(1
)
—

Change in operating working capital (Note 11)

(5
)
7

223

205

Investing Activities

Investment in Great Lakes

(4
)
(4
)
Acquisition of a 49.34 percent in Iroquois and an additional 11.81 percent in PNGTS

—

(605
)
Distribution received from Iroquois as return of investment (Note 5)

5

—

Capital expenditures

(9
)
(16
)

(8
)
(625
)
Financing Activities

Distributions paid (Note 10)

(123
)
(135
)
Distributions paid to Class B units (Note 8)

(15
)
(22
)
Distributions paid to non-controlling interests

(3
)
(5
)
Distributions paid to former parent of PNGTS

—

(1
)
Common unit issuance, net (Note 8)

40

92

Long-term debt issued, net (Note 7)

130

607

Long-term debt repaid (Note 7)

(225
)
(128
)
Debt issuance costs

(1
)
(1
)

(197
)
407

Decrease in cash and cash equivalents

18

(13
)
Cash and cash equivalents, beginning of period

33

64

Cash and cash equivalents, end of period

51

51

Three months ended

Six months ended
(unaudited)

June 30,

June 30,
(millions of dollars)

2019

2018

2019

2018

Net income

57

75

157

177
Other comprehensive income

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

(9)

(1)

(14)

6
Amortization of realized loss on derivative financial instruments

—

2

—

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

1

3

1

3
Comprehensive income

49

79

144

188
Comprehensive income attributable to non-controlling interests

2

3

9

9
Comprehensive income attributable to controlling interests

47

76

135

179

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

8
Table of Contents
TC PIPELINES, LP
CONSOLIDATED ~~STATEMENT OF CHANGES IN PARTNERS’ EQUITY~~BALANCE SHEETS

Limited Partners

General

Accumulated
Other
Comprehensive

Non-
Controlling

(unaudited)

Common Units

Class B Units

Partner

Income (a)

Interest

Total Equity

millions
of units

millions of
dollars

millions
of units

millions of
dollars

millions of
dollars

millions of
dollars

millions of
dollars

millions of
dollars

Partners’ Equity at December 31, 2017

70.6

824

1.9

110

24

5

105

1,068

Net income

—

166

—

—

3

—

8

177

Other comprehensive income

—

—

—

—

—

10

1

11

ATM equity issuances, net (Note 8)

0.7

39

—

—

1

—

—

40

Distributions

—

(117
)
—

(15
)
(6
)
—

(3
)
(141
)

Partners’ Equity at June 30, 2018

71.3

912

1.9

95

22

15

111

1,155

(unaudited)

(millions of dollars)

June 30, 2019

December 31, 2018

ASSETS

Current Assets

Cash and cash equivalents

45

33
Accounts receivable and other (Note 14)

33

48
Inventories

9

8
Other

3

8

90

97

Equity investments (Note 5)

1,118

1,196
Property, plant and equipment

(Net of $1,145 accumulated depreciation; 2018 - $1,110)

1,520

1,529
Goodwill

71

71
Other assets

—

6
TOTAL ASSETS

2,799

2,899

LIABILITIES AND PARTNERS' EQUITY

Current Liabilities

Accounts payable and accrued liabilities

26

36
Accounts payable to affiliates (Note 12)

6

6
Accrued interest

11

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

101

36

144

90
Long-term debt, net (Note 7)

1,892

2,072
Deferred state income taxes

9

9
Other liabilities

34

29

2,079

2,200
Partners’ Equity

Common units

514

462
Class B units (Note 8)

95

108
General partner

14

13
Accumulated other comprehensive income (loss) (AOCI)

(5)

8
Controlling interests

618

591
Non-controlling interests

102

108

720

699
TOTAL LIABILITIES AND PARTNERS' EQUITY

2,799

2,899
~~(a)~~     Gains (Losses) related to cash flow hedges reported in Accumulated Other Comprehensive Income and expected to be reclassified to Net income in the next 12 months are 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.
Variable Interest Entities (Note 16)
Subsequent Events (Note 17)

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

9
Table of Contents
TC PIPELINES, LP
CONSOLIDATED STATEMENT OF CASH FLOWS

Six months ended
(unaudited)

June 30,
(millions of dollars)

2019

2018

Cash Generated from Operations

Net income

157

177
Depreciation and amortization

39

48
Amortization of debt issue costs reported as interest expense

1

1
Amortization of realized losses

—

2
Equity earnings from equity investments (Note 5)

(84)

(95)
Distributions received from operating activities of equity investments (Note 5)

112

96
Change in other long-term liabilities

—

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

(1)

—
Change in operating working capital (Note 11)

4

(5)

228

223
Investing Activities

Investment in Great Lakes (Note 5)

(5)

(4)
Distribution received from Iroquois as return of investment (Note 5)

5

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

50

—
Capital expenditures

(29)

(9)
Customer advances for construction

1

—

22

(8)
Financing Activities

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

(95)

(123)
Distributions paid to Class B units (Note 8)

(13)

(15)
Distributions paid to non-controlling interests

(15)

(3)
Common unit issuance, net

—

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

20

130
Long-term debt repaid (Note 7)

(135)

(225)
Debt issuance costs

—

(1)

(238)

(197)
Increase in cash and cash equivalents

12

18
Cash and cash equivalents, beginning of period

33

33
Cash and cash equivalents, end of period

45

51

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

millions

millions

millions

millions
(unaudited)

of units

of dollars

of units

of dollars

of dollars

of dollars

of dollars

of dollars

Partners' Equity at December 31, 2018

71.3

462

1.9

108

13

8

108

699
Net income

145

—

3

—

9

157
Other comprehensive income (loss)

—

—

—

(13)

—

(13)
Distributions (Note 10)

(93)

(13)

(2)

—

(15)

(123)
Partners' Equity at June 30, 2019

71.3

514

1.9

95

14

(5)

102

720
(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 $2 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

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 an intermediate general partnership, TC PipeLines Intermediate GP, LLC and three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership.

NOTE 2SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three and six months ended June 30, ~~2018~~2019 and ~~2017~~2018 are not necessarily indicative of the results that may be expected ~~over~~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, ~~2017~~2018 included in our Annual Report on Form 10-K. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying consolidated financial statements contain all of the appropriate adjustments, ~~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 Annual Report on Form 10-K for the year ended December 31, ~~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.

U.S. federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of operations, is includable in the U.S. federal income tax returns of each partner.

In instances where the Partnership’s consolidated entities are subject to state income taxes, the asset-liability method is used to account for taxes. This method requires recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are classified as non-current on our consolidated balance sheets.
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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, ~~2018~~2019

~~Revenue from contracts with customers~~Leases

In ~~2014,~~February 2016, the Financial Accounting Standards Board (FASB) ~~issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue from these contracts in accordance with a~~
prescribed model. This model is used to depict the transfer of promised goods or services to customers in amounts that reflect the total consideration to which it expects to be entitled during the term of the contract in exchange for those promised goods or services. Goods or services that are promised to a customer are referred to as the Partnership’s “performance obligations.” The total consideration to which the Partnership expects to be entitled can include fixed and variable amounts. The Partnership has variable revenue that is subject to factors outside the Partnership’s influence, such as market volatility, actions of third parties and weather conditions. The Partnership considers this variable revenue to be “constrained” as it cannot be reliably estimated, and therefore recognizes variable revenue when the service is provided.
The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue recognition and the related cash flows. Effective January 1, 2018, the new guidance was applied using the modified retrospective transition method, and did not result in any material differences in the amount and timing of revenue recognition. Refer to Note 6 - Revenues, for further information related to the impact of adopting the new guidance and the Partnership’s updated accounting policies related to revenue recognition from contracts with customers.
~~Hedge Accounting~~
In August 2017, the FASB issued new guidance on hedge accounting, making more financial 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 with early adoption permitted. The Partnership has elected to prospectively apply this guidance effective January 1, 2018. Application of this guidance did not have a material impact on its consolidated financial statements.
~~Future accounting changes~~
~~Leases~~
~~In February 2016, the FASB~~ issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for ~~the~~an arrangement to qualify as a lease, the ~~lessor~~lessee is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 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.

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In the application of the new guidance, assumptions and judgments are used to determine the following:

● whether a contract contains a lease and the duration of the lease term including exercising lease renewal options. The lease term for all of the Partnership’s leases includes the non-cancellable period of the lease plus any additional periods covered by either the Partnership’s option to extend (or not to terminate) the lease that the Partnership is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor; and
● the discount rate for the lease.

The standard did not impact our previously reported results and did not have a material impact on the Partnership's consolidated balance sheets, consolidated statements of income or consolidated statement of cash flows at the date of adoption.

The most significant change as a result of the adoption was the recognition of ROU assets and lease liabilities for operating leases which was approximately $0.6 million at January 1, 2019 and $0.5 million at June 30, 2019. For the three and six months ended June 30, 2019, the Partnership’s operating lease cost was not material to the Partnership’s consolidated results. The weighted average remaining term and discount rate of the Partnership’s operating leases was approximately 2.41 years and 3.57 percent, respectively.

Fair Value Measurement

In ~~January~~August 2018, the FASB issued new guidance ~~on accounting~~that amends certain disclosure requirements for ~~land easements which provides an optional transition practical expedient to not evaluate existing or expired land easements not accounted for~~the fair value measurements as ~~leases prior to entity’s adoption of the new guidance. An entity that elects this practical expedient is required to apply it consistently to all~~part of its ~~existing or expired land easements not previously accounted for as leases. The Partnership continues to monitor and analyze additional guidance and clarifications provided by the FASB.~~
The new guidance is effective on January 1, 2019, with early adoption permitted. 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. The Partnership has substantially completed an analysis and preliminary inventory listing of existing lease agreements, and continues to analyze contracts that may contain leases. The Partnership continues to evaluate the financial impact of the application of the new guidance on its consolidated financial statements. The Partnership has also selected a system solution and is in the testing stage of its implementation. The Partnership continues to assess process changes necessary to compile the information to meet the recognition and disclosure ~~requirements of the new guidance.~~
~~Goodwill Impairment~~
In January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement 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.framework project. This new guidance is effective January 1, 2020, ~~and will be applied prospectively,~~ however, early adoption of certain or all requirements is permitted. The Partnership ~~is currently evaluating~~elected to adopt this guidance effective first quarter 2019. The guidance was applied retrospectively and did not have a material effect on the ~~timing and impact of the adoption of this guidance.~~Partnership’s consolidated financial statements.

Future accounting changes

Measurement of credit losses on financial instruments

In June 2016, the FASB issued new guidance that significantly changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net ~~income.~~income (loss). The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write down of the amortized cost basis. The new guidance is effective January 1, 2020 and will be applied using a modified retrospective approach. We have determined which of our assets are ~~currently evaluating~~within the scope of the new standard and have started to compile historical credit loss information. We are also assessing our current process to determine if any changes are required as a result. We continue to evaluate the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

~~NOTE 4   REGULATORY~~Consolidation

In ~~December 2016, FERC~~October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties under common control. This new guidance is effective January 1, 2020, and will be applied on a ~~Notice of Inquiry (NOI) Regarding the Commission’s Policy for Recovery of Income Tax Costs (Docket No. PL17-1-000) requesting initial comments regarding how~~retrospective basis, however early adoption is permitted. The Partnership has determined that there is no impact to ~~address any “double recovery” resulting from FERC’s current income tax allowance and rate of return policies that had been in effect since 2005.~~
~~Docket No. PL17-1-000 is a direct response to~~ ~~United Airlines, Inc., et al. v. FERC (United)~~, a decision issued by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016 in which the D.C. Circuit directed FERC to explain how a pass-through entity such as an MLP receiving a tax allowance and a return on equity derived from the discounted cash flow (DCF) methodology did not result in “double recovery” of taxes.
On December 22, 2017, the President of the United States signed into law H.R.1, originally known as the Tax Cuts and Jobs Act (the “2017 Tax Act”). This legislation provides for major changes to U.S. corporate federal tax law including a reduction of the federal corporate income tax rate. We are a non-taxable limited partnership for federal income tax purposes, and federal income taxes owedits consolidated financial statements as a result of ~~our earnings are~~this new guidance.

NOTE 4     REGULATORY

Iroquois, Tuscarora, and Northern Border took the ~~responsibility of our partners, therefore no amounts have been recorded in~~actions listed below to conclude the ~~Partnership’s financial statements with respect to federal income taxes~~issues impacting their pipelines as ~~a result of~~contemplated by the 2017 Tax ~~Act.~~
OnAct and certain FERC actions that began in March ~~15,~~of 2018, ~~FERC issued (1) a~~namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) to address the treatment of income taxes for ratemaking purposes for MLPs, (2) a Notice of Proposed Rulemaking (NOPR) proposing interstate pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the Revised Policy Statement could have on a pipeline’s Return on Equity (ROE) assuming a single-issue adjustment to a pipeline’s rates, and (3) an NOI seeking comment on how FERC should address changes related to accumulated deferred income taxes (ADIT) and bonus depreciation. On July 18, 2018, FERC issued (1) an Order on Rehearing of the Revised Policy Statement (Order on Rehearing) dismissing rehearing requests related to the Revised Policy Statement and (2) a Final Rule adopting and revising procedures from, and clarifying aspects of, the NOPR (collectively, the “2018 FERC Actions”). The Final Rule will become effective September 13, 2018, and is subject to requests for further rehearing and clarification. Each is further described below.
~~FERC Revised Policy Statement on Income Tax Allowance Cost Recovery in MLP Pipeline Rates~~
The Revised Policy Statement changes FERC’s long-standing policy allowing income tax amounts to be included in rates subject to cost-of-service rate regulation for pipelines owned by an MLP. The Revised Policy Statement creates a presumption that ~~entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in their regulated cost-of-service rates.~~
On July 18, 2018, FERC dismissed requests for rehearing and provided clarification of the Revised Policy Statement. In this Order on Rehearing, FERC noted that an MLP is not automatically precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance in its cost-of-service rates. Additionally, FERC provided guidance with regard to ADIT for MLP pipelines and other pass through entities. FERC found that to the extent an entity’s income tax allowance should be eliminated from rates, it must also eliminate its existing ADIT balance from its rate base. As a result, the Revised Policy Statement also precludes the recognition and subsequent amortization of any related regulatory assets or liabilities that might have otherwise impacted rates charged to customers as the refund or collection of excess or deficient deferred income tax assets or liabilities.
~~Final Rule on Tax Law Changes for Interstate Natural Gas Companies~~
~~The Final Rule~~ established a schedule
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by which interstate pipelines must either (i) file a new uncontested ~~rates~~rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that ~~quantifies~~quantified the ~~isolated~~ rate impact of the
2017 Tax Act on ~~FERC regulated~~FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by ~~MLPs. Pipelines filing the one-time report will have four options:~~
·        make a limited Natural Gas Act (NGA) Section 4 filing to reduce its rates by the reduction in its cost of service shown in its FERC Form No. 501-G. For any pipeline electing this option, FERC guarantees a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s FERC Form 501-G shows the pipeline’s estimated ROE as being12 percent or less. Under the Final Rule and notwithstanding the Revised Policy Statement, a pipeline organized as an MLP ~~is not required~~(collectively “2018 FERC Actions”).

Iroquois

On February 28, 2019, Iroquois filed an uncontested settlement with FERC to ~~eliminate its income tax allowance but, instead, can reduce its rates to reflect~~address the reduction in the maximum corporate tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance, along with its ADIT used for rate-making purposes. In situations where the ADIT balance is a liability, this elimination would have the effect of increasing the pipeline’s rate base used for rate-making purposes;
·        commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. If the pipeline commits to file eitherissues contemplated by ~~December 31, 2018, FERC will not initiate a Section 5 investigation of its rates prior to that date;~~
·        ~~file a statement explaining its rationale for why it does not believe the pipeline’s rates must change; and~~
·        take no other action. FERC would then consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate filing or committed to file a general Section 4 rate case.
We continue to evaluate this Final Rule and our next course of action, however, we do not expect an immediate or a retroactive impact from the Final Rule or the Revised Policy Statement described above.
~~NOI Regarding the Effect of~~ the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (2019 Iroquois Settlement). Among the terms of the 2019 Iroquois Settlement, Iroquois agreed to reduce its existing maximum system rates by 6.5 percent to be implemented in two phases, (i) effective March 1, 2019, a 3.25 percent rate reduction and (ii) effective April 1, 2020, an additional 3.25 percent rate reduction, which will conclude the total 6.5 percent rate reduction from the 2016 settlement rates. The 2019 Iroquois Settlement, which was approved by FERC on ~~Commission-Jurisdictional Rates~~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

InOn March 15, 2019, Tuscarora filed an uncontested settlement with FERC to address the ~~NOI, FERC sought comments to determine what additional action as a result of~~issues contemplated by the 2017 Tax Act if any, is required by FERC related to the ADIT that were reserved in anticipation of being paid to the Internal Revenue Service (IRS), but which no longer accurately reflect the future income tax liability. The NOI also sought comments on the elimination of bonus depreciation for regulated natural gas pipelines and ~~other effects of the 2017 Tax Act on regulated rates or earnings.~~
As noted above, FERC’s Order on Rehearing provided guidance with regard to ADIT for MLP pipelines, finding that if an MLP pipeline’s income tax allowance is eliminated from its cost-of-service rates, then its existing ADIT balance used for rate-making purposes should also be eliminated from its cost-of-service rates.
~~Impairment Considerations~~
As noted under Note 2, 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 at the date of the financial statements. Although we believe these estimates and assumptions are reasonable, actual results could differ.
~~We review property, plant and equipment and equity investments for impairment whenever events or changes in circumstances indicate the carrying value of the asset may not be recoverable.~~
Goodwill is tested for impairment on an annual basis or more frequently if events or changes in circumstance indicate that it might be impaired. We can initially make this assessment based on qualitative factors. If we conclude that it is not more likely than not that the fair value of the reporting unit is less than its carrying value, an impairment test is not performed.
~~Until the~~ 2018 FERC Actions ~~are implemented~~via an amendment to its prior 2016 settlement (2019 Tuscarora Settlement). Among the terms of the 2019 Tuscarora Settlement, Tuscarora agreed to reduce its existing maximum system rates by 1.7 percent effective February 1, 2019 through ~~individual~~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 ~~proceedings or settlements, and we have fully evaluated our respective alternatives to minimize any negative impact~~changes until January 31, 2023. The 2019 Tuscarora Settlement, which was approved by FERC on our future operating performance and cash flows, we believe that it is not more likely than not that the fair values of our reporting units are less than their respective carrying values. Therefore, a goodwill impairment test was not performed. Also, we have determined there is no indication that the carrying values of property, plant and equipment and equity investments potentially impacted by the 2018 FERC Actions are not recoverable.
~~We will continue to monitor developments and assess our goodwill for impairment. We~~May 2, 2019, will also ~~review our property, plant~~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 ~~equipment and equity investments for recoverability as new information becomes available.~~
~~At December 31, 2017, the estimated fair value of our investment in Great Lakes exceeded~~ its ~~carrying value~~501-G proceeding was terminated. Until superseded by ~~less than 10 percent. There is~~ a ~~risk that the 2018 FERC Actions, once implemented through the individual~~subsequent rate ~~proceeding~~case or settlement, ~~could result in an impairment charge~~effective January 1, 2020, the amended settlement agreement extends the two percent rate reduction implemented on February 1, 2019 to our equity method goodwill on Great Lakes which amounted to $260 million at June 30, 2018 (December 31, 2017 — $260 million). Additionally, given that the estimated fair value of Tuscarora exceeded its carrying value by less than 10 percent in its most recent valuation, there is also a risk that the $82 million goodwill at June 30, 2018 (December 31, 2017 - $82 million) related to Tuscarora could be negatively impacted by the 2018 FERC Actions once implemented through the individual rate proceeding or settlement.July 1, 2024.

NOTE 5EQUITY INVESTMENTS

The Partnership has equity interests in Northern Border, Great Lakes and Iroquois. The pipeline systems owned by these entities are regulated by FERC. The 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

Six Months

Ownership

Equity Earnings

Equity Investments

Interest at

Three months ended

Six months ended

(unaudited)

June 30,

ended June 30,

ended June 30,

June 30,

December 31,

June 30,

June 30,

June 30,

June 30,

December 31,
(millions of dollars)

2018

2018

2017

2018

2017

2018

2017


2019

2019

2018

2019

2018

2019

2018

Northern Border (a)

50
%
15

15

32

34

505

512

Northern Border

50
%
14

15

35

32

431

497
Great Lakes

46.45
%
12

6

36

23

485

479

46.45
%
9

12

29

36

484

489
Iroquois(b)

49.34
%
9

3

27

3

221

222

36

24

95

60

1,211

1,213

Iroquois

49.34
%
7

9

20

27

203

210

30

36

84

95

1,118

1,196

15
~~(a)~~              ~~Equity earnings from Northern Border is net~~Table of ~~the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent interest in April 2006.~~Contents
~~(b)~~             ~~Equity earnings from Iroquois is net of the 29-year amortization of a $10 million purchase price discrepancy assumed by the Partnership from TransCanada at the time of the 2017 Acquisition.~~
Distributions from Equity Investments

Distributions received from equity investments ~~for~~in the three and six months ended June 30, 2019 were $108 million and $167 million, respectively (June 30, 2018 ~~were~~- $56 million and $101 million, ~~respectively (2017 — $40~~respectively), of which $52.6 million and ~~$68 million) of which~~$55.2 million, respectively (June 30, 2018 - $2.6 million and $5.2 million, ~~respectively, (2017 - none) was~~respectively), were considered a return of capital and is included in ~~Investing Activities~~“Investing Activities” in the Partnership’s consolidated statement of cash flows. The return of capital was related to our investment in Northern Border and Iroquois (see further discussion below).

Northern Border

During the three and six months ended June 30, 2019, the Partnership received distributions from Northern Border amounting to $72 million and $100 million, respectively (June 30, 2018 - $17 million and $39 million, respectively) which includes the Partnership’s 50 percent share of the Northern Border’s $100 million distribution on June 26, 2019. The $100 million was 100 percent financed by borrowing on its $200 million revolving credit facility. The $50 million cash the Partnership received did not represent a distribution of operating cash flow during the period and therefore it was reported as a return of investment in the Partnership’s consolidated statement of cash flows.

The Partnership did not have undistributed earnings from Northern Border for the three and six months ended June 30, ~~2018~~2019 and ~~2017.~~2018.

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

(unaudited)

(millions of dollars)

June 30, 2018

December 31, 2017


June 30, 2019

December 31, 2018

ASSETS

Cash and cash equivalents

11

14

26

10
Other current assets

34

36

33

36
Plant, property and equipment, net

1,056

1,063

Property, plant and equipment, net

1,008

1,037
Other assets

14

14

13

13

1,115

1,127

1,080

1,096

LIABILITIES AND PARTNERS’ EQUITY

Current liabilities

37

38

46

34
Deferred credits and other

33

31

37

35
Long-term debt, net (a)

264

264

365

264
Partners’ equity

Partners’ capital

782

795

633

764
Accumulated other comprehensive loss

(1
)
(1
)

(1)

(1)

1,115

1,127

1,080

1,096

Three months ended

Six months ended
(unaudited)

June 30,

June 30,
(millions of dollars)

2019

2018

2019

2018

Transmission revenues

67

68

148

140
Operating expenses

(20)

(19)

(40)

(38)
Depreciation

(16)

(15)

(31)

(30)
Financial charges and other

(4)

(4)

(8)

(7)
Net income

27

30

69

65
~~(a)~~
(a) No current maturities as of June 30, 2019 and December 31, 2018. At June 30, 2019, Northern Border is in compliance with all its financial covenants.

16
Table of ~~June 30, 2018 and December 31, 2017.~~Contents

Three months ended

Six months ended

(unaudited)

June 30,

June 30,

(millions of dollars)

2018

2017

2018

2017

Transmission revenues

68

69

140

144

Operating expenses

(19
)
(18
)
(38
)
(36
)
Depreciation

(15
)
(15
)
(30
)
(30
)
Financial charges and other

(4
)
(5
)
(7
)
(9
)
Net income

30

31

65

69

Great Lakes

The Partnership made an equity contribution to Great Lakes of $4$5 million in the first quarter of ~~2018.~~2019 (June 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 six months ended June 30, ~~2018~~2019 and ~~2017.~~2018.

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

(unaudited)

(millions of dollars)

June 30, 2018

December 31, 2017


June 30, 2019

December 31, 2018

ASSETS

Current assets

89

107

56

75
Plant, property and equipment, net

695

701

784

808

Property, plant and equipment, net

687

689

743

764

LIABILITIES AND PARTNERS’ EQUITY

Current liabilities

49

75

26

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

250

259

229

240
Other long term liabilities

—

1

4

4
Partners’ equity

485

473

784

808

Partners' equity

484

494

743

764

Three months ended

Six months ended
(unaudited)

June 30,

June 30,
(millions of dollars)

2019

2018

2019

2018

Transmission revenues

51

53

123

134
Operating expenses

(19)

(15)

(35)

(32)
Depreciation

(8)

(8)

(16)

(16)
Financial charges and other

(5)

(5)

(9)

(9)
Net income

19

25

63

77
(a) Includes current maturities of $21 million as of June 30, 2019 and as of December 31, 2018. At June 30, 2019, Great Lakes is in compliance with all its financial covenants.
~~(a)~~              ~~Includes current maturities of $21 million as of June 30, 2018 (December 31, 2017 - $19 million).~~

Three months ended

Six months ended

(unaudited)

June 30,

June 30,

(millions of dollars)

2018

2017

2018

2017

Transmission revenues

53

41

134

103

Operating expenses

(15
)
(17
)
(32
)
(30
)
Depreciation

(8
)
(7
)
(16
)
(14
)
Financial charges and other

(5
)
(5
)
(9
)
(10
)
Net income

25

12

77

49

Iroquois

~~On June 1, 2017, the Partnership, through its interest in TC PipeLines Intermediate Limited Partnership acquired a 49.34 percent interest in Iroquois.~~ During the three and six months ended June 30, ~~2018,~~2019, the Partnership received distributions from Iroquois amounting to $14 million and $28 million, respectively (June 30, 2018 - $14 million and $28 million, respectively), which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million and $5.2 million, ~~respectively.~~respectively (June 30, 2018 - $2.6 million and $5.2 million, respectively). The unrestricted cash ~~does~~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 second quarter ~~2018~~2019 distribution of ~~$29~~$28 million on July ~~25, 2018,~~24, 2019, of which the Partnership received its 49.34 percent share ofor $14 million on August 1, ~~2018.~~2019. The distribution includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million. The Partnership did not have undistributed earnings from Iroquois for the three and six months ended June 30, ~~2018~~2019 and ~~2017.~~2018.

17
Table of Contents
The summarized financial information provided to us by Iroquois ~~for the period from the June 1, 2017 acquisition date through June 30, 2018~~ is as follows:

(unaudited)

(millions of dollars)

June 30, 2018

December 31, 2017


June 30, 2019

December 31, 2018

ASSETS




Cash and cash equivalents

100

86

73

80
Other current assets

26

36

25

32
Plant, property and equipment, net

584

591

Property, plant and equipment, net

573

581
Other assets

10

8

14

8

720

721

685

701

LIABILITIES AND PARTNERS’ EQUITY

Current liabilities

17

17

15

19
Net long-term debt, including current maturities (a)

327

329

Long-term debt, net ^(a)

319

325
Other non-current liabilities

13

9

21

14
Partners’ equity

363

366

720

721

Partners' equity

330

343

685

701

Three months ended

Six months ended
(unaudited)

June 30,

June 30,
(millions of dollars)

2019

2018

2019

2018

Transmission revenues

40

44

92

105
Operating expenses

(13)

(14)

(28)

(28)
Depreciation

(8)

(7)

(15)

(15)
Financial charges and other

(4)

(4)

(7)

(7)
Net income

15

19

42

55
(a) Includes current maturities of $4 million as of June 30, 2019 (December 31, 2018 - $146 million). At June 30, 2019, Iroquois is in compliance with all its financial covenants.
~~(a)~~              ~~Includes current maturities of $145 million as of June 30, 2018 (December 31, 2017 - $4 million).~~
(unaudited)
(millions of dollars)

Three months
ended June 30,
2018

One month
ended June 30,
2017

Six months
ended June 30,
2018

One month
ended June
30, 2017

Transmission revenues

44

14

105

14

Operating expenses

(14
)
(5
)
(28
)
(5
)
Depreciation

(7
)
(2
)
(15
)
(2
)
Financial charges and other

(4
)
(1
)
(7
)
(1
)
Net income

19

6

55

6

NOTE 6REVENUES

In 2014, the FASB issued new guidance on revenue from contracts with customers. The Partnership adopted the new guidance on January 1, 2018 using the modified retrospective transition method for all contracts that were in effect on the date of adoption. The reported results for all periods in 2018 reflect the application of the new guidance, while the reported results for all periods in 2017 were prepared under previous revenue recognition guidance which is referred to herein as “legacy U.S. GAAP”.
Disaggregation of Revenues

For the three and six months ended June 30, 2019 and 2018, ~~virtually~~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~~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~~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
18
Table of Contents
the time a regulatory decision becomes final. As of June 30, 2019, the Partnership does not have any outstanding refund obligations related to any rate proceedings. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.

~~Financial Statement Impact of Adopting Revenue from Contracts with Customers~~Contract Balances

The Partnership adopted the new guidance using the modified retrospective transition method. As a practical expedient under this transition method, the Partnership is not required to analyze completed contracts at the date of adoption. The adoptionAll of the ~~new guidance did not have a material impact on the~~ Partnership’s ~~previously reported consolidated financial statements~~contract balances pertain to receivables from contracts with customers amounting to $31 million at ~~December 31, 2017.~~
~~Pro-forma Financial Statements under Legacy U.S. GAAP~~
At June 30, 2019 (December 31, 2018 ~~had legacy U.S. GAAP been applied, there would be no change in the Partnership’s reported balance sheet~~- $44 million) and ~~income statement line items.~~
~~Contract Balances~~
(unaudited-millions of dollars)

June 30, 2018

January 1, 2018

Receivables from contracts with customers(a)

37

40

Contract assets(b)

—

—

~~(a)~~ ~~Recorded~~are recorded as Trade accounts receivable and reported as ~~Accounts~~“Accounts receivable and ~~other~~other” in the Partnership’s consolidated balance sheet (Refer ~~also~~ to Note 14).

~~(b)~~ ~~Contract assets primarily relate to~~Additionally, our accounts receivable represent the Partnership’s unconditional right to ~~recognize revenues~~consideration for services completed ~~but not invoiced at the reporting date. Any change in Contract assets is primarily related to the transfer to Accounts receivable when the right to recognize revenue becomes unconditional~~which includes billed and ~~the customer is invoiced as well as when revenue increases but remains to be invoiced. The Partnership did not have any Contract assets at January 1, 2018 and June 30, 2018.~~unbilled accounts.

Future revenue from remaining performance obligations

~~As required by~~When the ~~new revenue recognition guidance, the Partnership is required~~right to provide disclosure on future revenue allocated to remaining performance obligations on our contracts with customers that have not yet been recognized. However, all of the Partnership’s contracts qualify for the use of ainvoice practical expedient ~~listed below and therefore no~~is applied, the guidance does not require disclosure onof information related to future ~~revenues~~revenue from remaining performance obligations, therefore, no additional disclosure is ~~necessary:~~
1)       ~~The original expected duration of the contract is one year or less.~~required.
~~2) The Partnership recognizes revenue from the contract that is equal to the amount invoiced. This is referred to as the ‘right to invoice’ practical expedient.~~
3)       The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligationAdditionally, in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time.
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. In addition, the Partnership considers interruptible transportation service revenues to be variable revenues as volumes cannot be estimated. These variable revenues are recognized on a monthly basis when the Partnership’s performance obligation of natural gas deliveries is made at the agreed-upon delivery point.

~~Lastly,~~ future revenues from the Partnership’s firm capacity contracts include fixed revenues for the time periods when current rate settlements are in effect, which is approximately one to four years. Many of these contracts are long-term in nature and revenues from the remaining performance obligations on these contracts will be recognized using the FERC approved rates once the performance obligation to provide capacity has been satisfied.
NOTE 7DEBT AND CREDIT FACILITIES

(unaudited)
(millions of dollars)

June 30,
2018

Weighted Average
Interest Rate for the
Six Months Ended
June 30, 2018

December 31,
2017

Weighted Average
Interest Rate for the
Year Ended December
31, 2017

TC PipeLines, LP

Senior Credit Facility due 2021

140

2.99
%
185

2.41
%
2013 Term Loan Facility due 2022

500

3.02
%
500

2.33
%
2015 Term Loan Facility due 2020

170

2.91
%
170

2.22
%
4.65% Unsecured Senior Notes due 2021

350

4.65
%(a)
350

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

350

4.375
%(a)
350

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

500

3.90
%(a)
500

3.90
%(a)
GTN

5.29% Unsecured Senior Notes due 2020

100

5.29
%(a)
100

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

150

5.69
%(a)
150

5.69
%(a)
Unsecured Term Loan Facility due 2019

35

2.71
%
55

2.02
%
PNGTS

Revolving Credit Facility due 2023

—

—

—

—

5.90% Senior Secured Notes due 2018

—

—

30
(b)
5.90
%(a)
Tuscarora

Unsecured Term Loan due 2020

25

2.87
%
25

2.27
%

2,320

2,415

Less: unamortized debt issuance costs and debt discount

12

12

Less: current portion

36

51
(b)

2,272

2,352




Weighted Average



Weighted Average

Interest Rate for the

Interest Rate for the
(unaudited)

Six Months Ended

December 31,

Year Ended
(millions of dollars)

June 30, 2019

June 30, 2019

2018

December 31, 2018
TC PipeLines, LP

Senior Credit Facility due 2021

—

3.61
%

40

3.14
%

2013 Term Loan Facility due 2022

450

3.73
%

500

3.23
%

4.65% Unsecured Senior Notes due 2021

350

4.65
%
^(a)

350

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

350

4.375
%
^(a)

350

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

500

3.90
%
^(a)

500

3.90
%
^(a)
GTN

5.29% Unsecured Senior Notes due 2020

100

5.29
%
^(a)

100

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

150

5.69
%
^(a)

150

5.69
%
^(a)
Unsecured Term Loan Facility due 2019

—

—

35

2.93
%

PNGTS

Revolving Credit Facility due 2023

29

3.74
%

19

3.55
%

Tuscarora

Unsecured Term Loan due 2020

24

3.62
%

24

3.10
%

North Baja

Unsecured Term Loan due 2021

50

3.56
%

50

3.54
%

2,003

2,118

Less: unamortized debt issuance costs and debt discount

10

10

Less: current portion

101

36

1,892

2,072

~~(a)~~
(a) Fixed interest rate
19
Table of Contents

~~(b)~~             ~~Includes the PNGTS portion due at December 31, 2017 amounting to $5.8 million that was paid on January 2, 2018.~~
TC PipeLines, LP

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 10, ~~2021,~~2021. In March 2019, the Partnership repaid all amounts outstanding under ~~which $140 million~~its Senior Credit Facility and there was no outstanding balance at June 30, ~~2018~~2019 (December 31, ~~2017~~2018 - ~~$185~~$40 million)~~, leaving $360 million available for future borrowing.~~ .

The LIBOR-based interest rate onapplicable to the Senior Credit Facility was ~~3.24~~3.77 percent at December 31, 2018.

On June ~~30, 2018 (December 31, 2017 — 2.62 percent)~~26, 2019, the Partnership repaid $50 million of the principal balance under its 2013 Term Loan Facility using proceeds from Northern Border's special distribution (see Note 5).
Additionally, in conjunction with this repayment, the Partnership also terminated an equivalent amount in interest rate swaps that were used to hedge this facility at a rate of 2.81 percent. As of June 30, ~~2018,~~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, ~~2017 — 2.31~~2018 –3.26 percent). Prior to hedging activities, the LIBOR-based interest rate on the 2013 Term Loan Facility was ~~3.24~~3.69 percent at June 30, ~~2018~~2019 (December 31, ~~2017 — 2.62~~2018 - 3.60 percent).

The ~~LIBOR-based interest rate on the 2015 Term Loan Facility was 3.13 percent at June 30, 2018 (December 31, 2017 — 2.51 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 to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains]) of no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions ~~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 ~~4.28~~2.78 to 1.00 as of June 30, ~~2018.~~2019.

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 June 30, ~~2018~~2019 was ~~42.3~~39.9 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 ~~2.93~~3.30 percent at ~~June 30, 2018 (December~~December 31, ~~2017 — 2.31 percent).~~2018.

PNGTS

~~On April 5, 2018, PNGTS entered into a revolving credit agreement under which PNGTS has the ability to borrow up to $125 million with a variable interest rate based on LIBOR (Revolving~~PNGTS’ Revolving Credit ~~Facility). The credit agreement matures on April 5, 2023 and~~Facility requires PNGTS to maintain a leverage ratio not greater than 5.00 to 1.00. The ~~facility will be utilized primarily~~leverage ratio was 0.5 to ~~fund the costs~~1.00 as of ~~the PXP expansion project and~~June 30, 2019.

The LIBOR-based interest rate applicable to ~~finance~~ PNGTS’ ~~other funding needs.~~Revolving Credit Facility was 3.69 percent at June 30, 2019 (December 31, 2018 - 3.60 percent).
~~On May 10, 2018, PNGTS paid the remaining principal balance of its 5.90% Senior Secured Notes due 2018 (2003 Senior Secured Notes) using its available cash.~~

Tuscarora

Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of June 30, ~~2018,~~2019, the ratio was ~~11.2~~9.44 to 1.00.

The LIBOR-based interest rate ~~on the~~applicable to Tuscarora’s Unsecured Term Loan Facility was ~~3.11~~3.57 percent at June 30, ~~2018~~2019 (December 31, ~~2017 — 2.49~~2018 - 3.47 percent).

North Baja

North Baja’s Term Loan Facility contains a covenant that limits total debt to no greater than 70 percent of North Baja’s total capitalization. North Baja’s total debt to total capitalization ratio at June 30, 2019 was 39.06 percent.
20
Table of Contents

The LIBOR-based interest rate applicable to North Baja’s Term Loan Facility was 3.52 percent at June 30, 2019 (December 31, 2018 - 3.54 percent).

Partnership (TC PipeLines, LP and its subsidiaries)

At June 30, ~~2018,~~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. Refer also to Note 19 for important information relating to a distribution reduction to retain cash that will be used to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics in response to the impact of the 2018 FERC Actions on our future operating performance and cashflows.

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

(unaudited)

(millions of dollars)

2018

1

2019

36

2020

293

2021

490

2022

500

Thereafter

1,000

2,320

(unaudited)

(millions of dollars)

Principal Payments
2019

1
2020

123
2021

400
2022

450
2023

29
Thereafter

1,000

2,003

NOTE 8PARTNERS’ EQUITY

ATM equity issuance program (ATM program)

During the six months ended June 30, ~~2018, we issued 0.7 million~~2019, no common units were issued under our ATM program (none during the three months ended June 30, 2018) generating net proceeds of approximately $39 million, plus $1 million contributed by the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the six months ended June 30, 2018 were nil. The net proceeds were used for general partnership purposes.this program.

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

The Class B ~~Units 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~~Distribution will be further reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units iswere reduced ~~for the calendar year~~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~~ended December 31, ~~2018,~~2019, the Class B units’ equity account will be increased by the ~~excess of 30 percent of GTN’s distributions~~Class B Distribution, less ~~the annual threshold of $20 million and~~ the Class B Reduction, ~~and~~ until such amount is declared for distribution and paid in the first quarter of ~~2019.~~2020. During the six months ended June 30, ~~2018,~~2019, the Class B threshold was not exceeded.

For the year ended December 31, ~~2017,~~2018, the Class B distribution was ~~$15~~$13 million and was declared and paid in the first quarter of ~~2018.~~2019.

NOTE 9NET 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.

21
Table of Contents
The amount allocable to the General Partner equals an amount based upon the General Partner’s ~~effective~~ two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership ~~Agreement.~~Agreement.

The amount allocable to the Class B units in ~~2018~~2019 equals 30 percent of GTN’s distributable cash flow during the year ended December 31, ~~2018~~2019 less $20 million and is further reduced by the estimated Class B Reduction for 2019 (December 31, ~~2017 —$~~2018-$20 ~~million)~~million less Class B Reduction). During the three and six months ended June 30, ~~2018~~2019 and ~~2017,~~2018, no amounts were allocated to the Class B units as the annual threshold was not exceeded.

Net income per common unit was determined as follows:

Three months ended

Six months ended

(unaudited)

June 30,

June 30,

(millions of dollars, except per common unit amounts)

2018

2017

2018

2017

Net income attributable to controlling interests

73

55

169

132

Net income attributable to PNGTS’ former parent (a)

—

—

—

(2
)
Net income attributable to General and Limited Partners

73

55

169

130

Incentive distributions allocated to the General Partner (b)

—

(3
)
—

(5
)
Net income attributable to the General Partner and common units

73

52

169

125

Net income attributable to General Partner’s two percent interest

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

72

50

166

122

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

71.3

68.9

71.2

68.6

Net income per common unit – basic and diluted

$
1.00

$
0.73

$
2.33

$
1.78

(unaudited)

Three months ended June 30,

Six months ended June 30,
(millions of dollars, except per common unit amounts)

2019

2018

2019

2018

Net income attributable to controlling interests

55

73

148

169
Net income attributable to the General Partner

(1)

(1)

(3)

(3)
Net income attributable to common units

54

72

145

166
Weighted average common units outstanding (millions) – basic and diluted

71.3

71.3

71.3

71.2
Net income per common unit – basic and diluted

$
0.75

$
1.00

$
2.03

$
2.33
~~(a)~~                   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 or Class B units.
~~(b)~~                  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.

NOTE 10     CASH DISTRIBUTIONS PAID TO COMMON UNITS

2019

During the three and six months ended June 30, 2019, the Partnership distributed $0.65 and $1.30 per common unit, respectively, for a total of $47 million and $95 million, respectively.

The total distribution paid above includes our General Partner’s share during the three and six months ended June 30, 2019 for its two percent general partner interest, which was $1 million and $2 million, respectively. The General Partner did not receive any distributions in respect of its IDRs during the three and six months ended June 30, 2019.

2018

During the three and six months ended June 30, 2018, the Partnership distributed $0.65 and $1.65 per common unit, respectively, ~~(June 30, 2017 — $0.94 and $1.88 per common unit, respectively)~~ for a total of $47 million and $123 million, ~~respectively, (June 30, 2017 - $68 million and $135 million, respectively).~~respectively.

The total distribution paid toabove includes our General ~~Partner~~Partner’s share during the three ~~months ended June 30, 2018 for its effective two percent general partner interest was $1 million (June 30, 2017 - $1 million for the effective two percent interest~~ and ~~a $2 million IDR payment). The General Partner did not receive any distributions in respect of its IDRs in the second quarter 2018.~~
~~The distribution paid to our General Partner during the~~ six months ended June 30, 2018 for its ~~effective~~ two percent general partner interest, which was $1 million and $3 million, ~~along with an IDR payment~~respectively. The distributions paid to our General Partner in respect of IDRs during the three and six months ended June 30, 2018 were nil and $3 million, ~~for a total distribution of $6 million (June 30, 2017 - $2 million for the effective two percent interest and a $4 million IDR payment).~~respectively.

NOTE 11     CHANGE IN OPERATING WORKING CAPITAL

(unaudited)

Six months ended June 30,

Six months ended June 30,
(millions of dollars)

2018

2017


2019

2018

Change in accounts receivable and other

2

11

15

2
Change in inventories

(1)

—
Change in other current assets

(1
)
2

3

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

(6
)
(5
)
Change in accounts payable to affiliates

—

(2
)
Change in accounts payable and accrued liabilities

(12)

(6)
Change in accrued interest

—

1

(1)

—
Change in operating working capital

(5
)
7

4

(5)

22
~~(a)~~              ~~Excludes certain non-cash items primarily related to capital accruals.~~Table of Contents

NOTE 12     RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to conduct the business
of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. For both the three and six months ended June 30, ~~2018~~2019 and ~~2017,~~2018, total costs charged to the Partnership by the General Partner were $1 million and $2 million, respectively.

As operator of our pipelines, except Iroquois ~~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 six months ended June 30, 2019 and 2018 ~~and 2017~~ by ~~TransCanada’s~~TC Energy’s subsidiaries and amounts payable to ~~TransCanada’s~~TC Energy’s subsidiaries at June 30, ~~2018~~2019 and December 31, ~~2017~~2018 are summarized in the following tables:

Three months ended

Six months ended

Three months ended

Six months ended
(unaudited)

June 30,

June 30,

June 30,

June 30,
(millions of dollars)

2018

2017

2018

2017


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)

16

9

24

17

12

16

23

24
Northern Border (a)

9

10

18

20

10

9

19

18
GTN

8

9

16

16

11

8

21

16
Bison

1

1

3

2

—

1

1

3
North Baja

1

1

2

2

2

1

3

2
Tuscarora

1

1

2

2

1

1

2

2
PNGTS

2

2

4

4

PNGTS ^(a)

1

2

3

4
Impact on the Partnership’s net income:

Great Lakes (a)

7

4

11

7

Northern Border (a)

4

4

8

7

Great Lakes

5

7

10

11
Northern Border

5

4

9

8
GTN

7

7

14

14

8

7

16

14
Bison

1

1

3

2

—

1

1

3
North Baja

1

1

2

2

1

1

2

2
Tuscarora

1

1

2

2

1

1

2

2
PNGTS

1

1

2

2

1

1

2

2

(unaudited)

(millions of dollars)

June 30, 2018

December 31, 2017

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

Great Lakes (a) (b)

3

3

Northern Border (a)

3

4

GTN

3

3

Bison

1

1

North Baja

—

—

Tuscarora

—

—

PNGTS(a)

1

1

(unaudited)

(millions of dollars)

June 30, 2019

December 31, 2018

Net amounts payable to TC Energy’s subsidiaries are as follows:

Great Lakes ^(a)

5

3
Northern Border ^(a)

4

3
GTN

4

4
Bison

—

1
North Baja

1

—
Tuscarora

—

1
PNGTS ^(a)

1

1
~~(a)~~
(a) Represents 100 percent of the costs.
23
Table of ~~the costs.~~Contents
~~(b)~~             ~~Excludes any amounts owed to affiliates relating to revenue sharing. See discussion below.~~

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 six months ended June 30, ~~2018,~~2019, Great
Lakes earned 73 percent of its transportation revenues from TC Energy and its affiliates (June 30, 2018 - 72 percent and 70 percent, ~~respectively, of transportation revenues from TransCanada and its affiliates (2017 — 43 percent and 57 percent,~~ respectively).

At June 30, ~~2018, $3~~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, ~~2017 — $20~~2018 - $18 million).
During 2017, Great Lakes operated under a FERC approved 2013 rate settlement that included a revenue sharing mechanism that required Great Lakes to share with its customers certain percentages of any qualifying revenues earned above certain ROEs. For the year ended December 31, 2017, Great Lakes recorded an estimated revenue sharing provision amounting to $40 million. During the second quarter of 2018, the refund was settled with its customers and a significant portion of the refund was with its affiliates. Under the terms of the 2017 Great Lakes Settlement, beginning in 2018, its revenue sharing provision was eliminated (Refer to our Annual Report on Form 10-K for the year ended December 31, 2017).

During the second quarter of 2018, Great Lakes reached an agreement on the terms of a new long-term transportation capacity contracts with its affiliate, ANR Pipeline ~~Company (ANR).~~Company. The contracts are for a term of 15 years from November 2021 to October 31, 2036 with a total contract value of approximately $1.3 billion. The contracts contain reduction options (i) at ~~anytime~~any time on or before April 1, 2019 for any reason and (ii) ~~anytime~~any time before April 2021, if ~~ANR~~TC Energy is not able to secure the required regulatory approval related to anticipated expansion projects. During the first quarter of 2019, Great Lakes reached an agreement to amend volume reduction “for any reason” option by extending the period “on or before” April 1, 2019 to “on or before” April 1, 2020. All the other terms remained the same.

PNGTS

PNGTS earns transportation revenues from ~~TransCanada~~TC Energy and its affiliates. For ~~both~~the three and six months ended June 30, ~~2018,~~2019, PNGTS earned approximately ~~$1 million~~nil of its transportation revenues from ~~TransCanada~~TC Energy and its affiliates ~~(2017 — nil)~~(June 30, 2018 - $1 million).

At June 30, ~~2018,~~2019, nil was included in ~~PNGTS’~~PNGTS' outstanding receivables ~~in regards~~with regard to the transportation contracts with ~~TransCanada~~TC Energy and its affiliates (December 31, ~~2017 —~~2018 – nil).

In connection with ~~anticipated future commercial opportunities,~~the Portland XPress expansion project, PNGTS has entered into an arrangement with its affiliates regarding the construction of certain facilities on their systems that will be required to fulfill future contracts on the ~~PNGTS’~~PNGTS system. In the event the anticipated developments do not proceed, PNGTS will be required to reimburse its affiliates for any costs incurred related to the development of these facilities. At June 30, ~~2018,~~ 2019, the total costs incurred by these affiliates was approximately ~~$15~~$99 million.

NOTE 13     FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

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

● Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.
● Level 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 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.~~
·      ~~Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.~~
·      ~~Level 3 inputs are unobservable inputs for the asset or liability.~~

When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used.

24
Table of Contents
(b) Fair Value of Financial Instruments

The carrying value of ~~cash~~“cash and cash ~~equivalents, accounts~~equivalents”, “accounts receivable and ~~other, accounts~~other”, ”accounts payable and accrued ~~liabilities, accounts~~liabilities”, “accounts payable to ~~affiliates~~affiliates” and ~~accrued interest~~“accrued interest” approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach, which uses period-end market rates and applies a discounted cash flow valuation model.

The Partnership has classified the fair value of natural gas imbalances as a Level 2 of the fair value hierarchy for fair value disclosure purposes, as the valuation approach includes quoted prices in the market index and observable volumes for the imbalance.

Long-term debt is recorded at amortized cost and classified as Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified as Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market
prices. The estimated fair value of the Partnership’s debt as at June 30, ~~2018~~2019 and December 31, ~~2017~~2018 was ~~$2,311~~$2,064 million and ~~$2,475~~$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% (See also Note 7).

At June 30, ~~2018,~~2019, the fair value of the interest rate swaps accounted for as cash flow hedges was ~~an asset~~ a liabilityof ~~$15~~$5 million (both on a gross and net basis)~~. At December~~ (December 31, ~~2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an~~2018 - asset of ~~$5 million (on both gross and net basis)~~$8 million).

The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $1$9 million and ~~a gain of $6~~$14 million for the three and six months ended June 30, 2019, respectively (June 30, 2018 ~~respectively (2017 — nil~~- loss of $1 million and gain of ~~$1 million)~~$6 million, respectively). During the three and six months ended June 30, ~~2018,~~2019, a gain of $3$1 million was reclassified from other comprehensive income to net income ~~(2017 — loss~~(June 30, 2018 - gain of $1$3 million). For the three and six months ended June 30, ~~2018,~~2019, the net realized gain related to the interest rate swaps was ~~$1 million~~nil and $2$1 million, respectively, and was included in ~~financial~~“financial charges and ~~other (2017~~other” (June 30, 2018 - ~~nil)~~gain of $1 million and $2 million, respectively) (Refer to Note 15).
The Partnership’s $500 million 2013 Term Loan is hedged using fixed interest rate swaps until July 1, 2018 at an average rate of 2.31 percent. During the fourth quarter of 2017, the Partnership implemented an interest rate hedging strategy that hedged the $500 million 2013 Term Loan 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 June 30, ~~2018 (net asset of $5 million as of~~2019 and December 31, ~~2017).~~2018.

~~In anticipation~~25
Table 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 Accounting Standards Codification (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 was amortized against earnings over the life of the PNGTS Senior Secured Notes. On May 10, 2018, PNGTS paid the remaining principal balance of its 2003 Senior Secured Notes using its available cash and, as a result, our 61.71 percent proportionate share of the net unamortized loss on PNGTS included in other comprehensive income was all amortized against earnings (December 31, 2017 - $1 million). For the three and six months ended June 30, 2018, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $1 million (2017 - $1 million).Contents

NOTE 14     ACCOUNTS RECEIVABLE AND OTHER


(unaudited)

(millions of dollars)

June 30, 2018

December 31, 2017


June 30, 2019

December 31, 2018

Trade accounts receivable, net of allowance of nil

37

40

31

44
Imbalance receivable from affiliates

1

1

1

2
Other

2

1

1

2

40

42

33

48

NOTE 15     FINANCIAL CHARGES AND OTHER

Three months ended

Six months ended

Three months ended

Six months ended
(unaudited)

June 30,

June 30,

June 30,

June 30,
(millions of dollars)

2018

2017

2018

2017


2019

2018

2019

2018

Interest Expense (a)

24

19

48

36

PNGTS’ amortization of loss on derivative instruments (Note 13)

2

1

2

1

Interest expense ^(a)

22

24

45

48
PNGTS' amortization of loss on derivative instruments

—

2

—

2
Net realized gain related to the interest rate swaps

(1
)
—

(2
)
—

—

(1)

(1)

(2)
Other Income

(2
)
(1
)
(2
)
(1
)

23

19

46

36

Other income

(1)

(2)

(1)

(2)

21

23

43

46
(a) Includes amortization of debt issuance costs and discount costs.

~~(a)~~              ~~Includes amortization of debt issuance costs and discount costs.~~
~~NOTE 16    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. In September 2015, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes. Essar successfully appealed this decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and various other rulings by the federal district judge. The Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. In May 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the premium for the performance bond Essar was required to post pending appeal.
Essar Minnesota filed for bankruptcy in July 2016. Following Essar’s successful appeal and award of $1.2 million of costs, Great Lakes was required to release the $1.2 million into the bankruptcy estates. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court. The bankruptcy court approved Great Lakes’ unsecured claim in the amount of $31.5 million in April 2017. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.
The Foreign Essar Affiliates have not filed for bankruptcy and Great Lakes’ case against the Foreign Essar Affiliates in Minnesota state court remains pending. The Foreign Essar Affiliates gave an offer of judgment (Offer of Judgment) in the federal district court proceeding whereby the Foreign Essar Affiliates agreed to satisfy any judgment awarded to Great Lakes. The Foreign Essar Affiliates dispute that the Offer of Judgment is enforceable because the federal court judgment was vacated on appeal. Great Lakes has obtained a consent order from the bankruptcy court permitting it to petition the state court to enforce the Offer of Judgment. If unsuccessful in state court, Great Lakes can return to bankruptcy court for an order permitting it to proceed to trial in state court on its claims under the transportation services agreement against the Foreign Essar Affiliates.
At June 30, 2018, Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings, therefore, it did not recognize any gain contingency on its outstanding claim against Essar.
Additionally, at June 30, 2018, the Partnership is not aware of any contingent liabilities that would have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.
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 economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

As a result of its analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but has a variable interest in the entity, are accounted for as equity investments.

Consolidated VIEs

The Partnership’s consolidated VIEs consist of the intermediate partnerships and mainly the Partnership’s ILPs that hold interests in the Partnership’s pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability ~~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
26
Table of Contents
Lakes, PNGTS, Iroquois and ~~Iroquois~~North Baja due to their third party debt. The following table presents the total assets and liabilities of these entities that are included in the Partnership’s consolidated balance sheets:

(unaudited)

(millions of dollars)

June 30, 2018

December 31, 2017


June 30, 2019

December 31, 2018

ASSETS (LIABILITIES) *

ASSETS (LIABILITIES) ^(a)

Cash and cash equivalents

7

19

14

16
Accounts receivable and other

27

30

29

39
Inventories

7

6

9

8
Other current assets

6

5

3

6
Equity investments

1,211

1,213

1,118

1,196
Plant, property and equipment, net

1,117

1,133

Property, plant and equipment, net

1,240

1,240
Other assets

2

1

1

1
Accounts payable and accrued liabilities

(18
)
(24
)

(22)

(33)
Accounts payable to affiliates, net

(44
)
(42
)

(87)

(40)
Distributions payable

—

(1
)
Accrued interest

(3
)
(2
)

(2)

(2)
Current portion of long-term debt

(36
)
(51
)

(101)

(36)
Long-term debt

(273
)
(308
)

(251)

(341)
Other liabilities

(27
)
(26
)

(28)

(27)
Deferred state income tax

(10
)
(10
)

(9)

(9)
(a) Bison, an asset held through our consolidated VIEs, is excluded at June 30, 2019 and at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations.

*North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE’s obligations.
~~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 June 30, 2018 and December 31, 2017 relate primarily to utility plant. At June 30, 2018 and December 31, 2017 the New Hampshire BPT effective tax rate was 3.8 percent for both periods and was applied to PNGTS’ taxable income.

Three months ended

Six months ended

(unaudited)

June 30,

June 30,

(millions of dollars)

2018

2017

2018

2017

State income taxes

Current

—

—

1

1

Deferred

—

—

—

—

—

—

1

1

NOTE 1917     SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through August ~~2, 2018,~~1, 2019, the date the consolidated financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

On July ~~26, 2018,~~23, 2019, the board of directors of the General Partner declared the Partnership’s second quarter ~~2018~~2019 cash distribution in the amount of $0.65 per common unit payable on August ~~15, 2018~~14, 2019 to unitholders of record as of August ~~6, 2018.~~2, 2019. The declared distribution totaled $47 million and is payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of ~~TransCanada~~TC Energy as holder of 11,287,725 common units) and $1 million to the General Partner for its ~~effective~~ two percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the second quarter ~~2018. This distribution and our first quarter 2018 distribution each represent a 35 percent reduction compared to the Partnership’s fourth quarter 2017 distribution~~ of $1.00 per common unit. Cash retained by the Partnership will be used to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage our financial metrics in response to the impact of the 2018 FERC Actions on our future operating performance and cash flows.2019.

Northern Border declared its June ~~2018~~2019 distribution of ~~$12~~$15 million on July ~~11, 2018,~~8, 2019, of which the Partnership received its 50 percent share or $6$7 million on July 31, ~~2018.~~2019.

Great Lakes declared its second quarter ~~2018~~2019 distribution of ~~$29~~$20 million on July ~~17, 2018,~~16, 2019, of which the Partnership received its 46.45 percent share or ~~$13~~$9 million on August 1, ~~2018.~~2019.

Iroquois declared its second quarter 2019 distribution of $28 million on July 24, 2019, of which the Partnership received its 49.34 percent share or $14 million on August 1, 2019. The $14 million includes our proportionate share of Iroquois’ unrestricted cash amounting to $2.6 million (Refer to Note 5).

PNGTS declared its second quarter ~~2018~~2019 distribution of $3$7 million on July ~~20, 2018,~~12, 2019, of which $1$3 million ~~will be~~was paid to its non-controlling interest owner on August 1, ~~2018.~~2019.

27
Table of Contents
Item 2.  ~~Management’s~~Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and notes included in Item 11. “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, ~~2017.~~2018.

RECENT BUSINESS DEVELOPMENTS

~~In December 2016, FERC issued Docket No. PL17-1-000 requesting initial comments regarding how~~Cash Distributions

On April 23, 2019, the board of directors of our General Partner declared the Partnership's first quarter 2019 cash distribution in the amount of $0.65 per common unit, payable on May 13, 2019 to ~~address any “double recovery” resulting from FERC’s current income tax allowance~~unitholders of record as of May 3, 2019. The declared distribution totaled $47 million and ~~rate~~was payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of ~~return policies that had been~~5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest.

On July 23, 2019, the board of directors of our General Partner declared the Partnership's second quarter 2019 cash distribution in ~~effect since 2005.~~
~~Docket No. PL17-1-000 is~~the amount of $0.65 per common unit, payable on August 14, 2019 to unitholders of record as of August 2, 2019. The declared distribution totaled $47 million and was payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a ~~direct response~~holder of 5,797,106 common units and $7 million to ~~United Airlines, Inc., et al. v. FERC~~~~, a decision issued by the U.S. Court~~another subsidiary of ~~Appeals~~TC Energy as holder of 11,287,725 common units) and $1 million to our General Partner for the District of Columbia Circuit in July 2016 in which the D.C. Circuit directed FERC to explain how a pass-through entity such as an MLP receiving a tax allowance and a return on equity derived from the DCF methodologyits two percent general partner interest. The General Partner did not ~~result~~receive any distributions in ~~“double recovery”~~respect of ~~taxes.~~its IDRs in 2019 year-to-date.

On December 22, 2017, the President of the United States signed into law the 2017 Tax Act. This legislation provides for major changes to U.S. corporate federal tax law including a reduction of the federal corporate income tax rate. We are a non-taxable limited partnership for federal income tax purposes, and federal income taxes owed as a result of our earnings are the responsibility of our partners, therefore no amounts have been recorded in the Partnership’s financial statements with respect to federal income taxes as a result of the 2017 Tax Act.
On March 15, 2018, FERC issued the following: (1) the Revised Policy Statement, (2) the NOPR and (3) the NOI. On July 18, 2018, FERC issued (1) Order on Rehearing and (2) a Final Rule adopting and revising procedures from, and clarifying aspects of, the NOPR. The Final Rule will become effective September 13, 2018, and is subject to requests for further rehearing and clarification. Each of the 2018 FERC Actions ~~is further described below.~~Updates from our 2018 Annual Report on Form 10-K:

~~FERC Revised Policy Statement on Income Tax Allowance Cost Recovery in MLP Pipeline Rates~~
~~The Revised Policy Statement changes FERC’s long-standing policy allowing income tax amounts~~Iroquois, Tuscarora, and Northern Border took the actions listed below to ~~be included in rates subject to cost-of-service rate regulation for~~conclude the issues impacting their pipelines ~~owned~~as contemplated by an MLP. The Revised Policy Statement creates a presumption that entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in their regulated cost-of-service rates.
On July 18, 2018, FERC dismissed requests for rehearing and provided clarification of the Revised Policy Statement. In this Order on Rehearing, FERC noted that an MLP is not automatically precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance in its cost-of-service rates. Additionally, FERC provided guidance with regard to ADIT for MLP pipelines and other pass through entities. FERC found that to the extent an entity’s income tax allowance should be eliminated from rates, it must also eliminate its existing ADIT balance from its rate base. As a result, the Revised Policy Statement also precludes the recognition and subsequent amortization of any related regulatory assets or liabilities that might have otherwise impacted rates charged to customers as the refund or collection of excess or deficient deferred income tax assets or liabilities.
~~Final Rule on Tax Law Changes for Interstate Natural Gas Companies~~
The Final Rule established a schedule by which interstate pipelines must either (i) file a new uncontested rates settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantifies the rate impact of the 2017 Tax Act ~~on FERC regulated pipelines~~ and ~~the impact of the Revised Policy Statement on pipelines held by MLPs. Pipelines filing the one-time report will have four options:~~
· make a limited NGA Section 4 filing to reduce its rates by the reduction in its cost of service shown in its FERC Form No. 501-G. For any pipeline electing this option, FERC guarantees a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s FERC Form 501-G shows the pipeline’s estimated ROE as being 12 percent or less. Under the Final Rule and notwithstanding the Revised Policy Statement, a pipeline organized as an MLP is not required to eliminate its income tax allowance but, instead can reduce its rates to reflect the reduction in the maximum corporate tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance, along with its ADIT used for rate-making purposes. In situations where the ADIT balance is a
~~liability, this elimination would have the effect of increasing the pipeline’s rate base used for rate-making purposes;~~
· commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. If the pipeline commits to file either by December 31, 2018, FERC will not initiate a Section 5 investigation of its rates prior to that date;
· ~~file a statement explaining its rationale for why it does not believe the pipeline’s rates must change; and~~
· take no action. FERC would then consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate filing or committed to file a general Section 4 rate case.
We continue to evaluate this Final Rule and our next course of action, however, we do not expect an immediate or a retroactive impact from the Final Rule or the Revised Policy Statement described above.
~~NOI Regarding the Effect of the 2017 Tax Act on Commission-Jurisdictional Rates~~
In the NOI, FERC sought comments to determine what additional action as a result of the 2017 Tax Act, if any, is required by FERC related to the ADIT that were reserved in anticipation of being paid to the IRS, but which no longer accurately reflect the future income tax liability. The NOI also sought comments on the elimination of bonus depreciation for regulated natural gas pipelines and other effects of the 2017 Tax Act on regulated rates or earnings.
As noted above, FERC’s Order on Rehearing provided guidance with regard to ADIT for MLP pipelines, finding that if an MLP pipeline’s income tax allowance is eliminated from its cost-of-service rates, then its existing ADIT balance used for rate-making purposes should also be eliminated from its cost-of-service rates.
~~Partnership Specific Considerations~~
~~While certain uncertainties exist with respect to changes resulting from~~ the 2018 FERC ~~Actions, the net effect of the potential reduction of~~Actions. FERC has now closed all 501-G dockets for our pipeline ~~systems’ maximum allowable or recourse rates on~~systems with the ~~Partnership’s revenues could have a material negative impact on the earnings, cash flow, and financial position~~exception of ~~the Partnership and could diminish its relative ability~~Great Lakes.

Iroquois - On February 28, 2019, Iroquois filed an uncontested settlement with FERC to attract capital to fund future growth. The Partnership’s pipeline systems do not currently have a requirement to file for new rates earlier than 2022 as a result of their existing rate settlements. However, the timing may be accelerated by the Final Rule and represents a revision of our previous expectations. Proceedings related the 2018 FERC Actions could begin as early as late 2018 and could result in a reset of certain of our pipelines’ maximum allowable rates.
While the Partnership does not anticipate any FERC mandated action to reduce recourse rates in 2018, the Partnership believes that any impact would take effect prospectively upon the completion or settlement of a rate case, including one that may be initiated by the FERC or customers. Should the Partnership choose to proactively address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions ~~prospective~~via an amendment to its prior 2016 settlement. Among the terms of the 2019 Iroquois Settlement, Iroquois agreed to reduce its existing maximum system rates by 6.5 percent to be implemented in two phases, (i) effective March 1, 2019, a 3.25 percent rate reduction and (ii) effective April 1, 2020, an additional 3.25 percent rate reduction, which will conclude the total 6.5 percent rate reduction from the 2016 settlement rates. The 2019 Iroquois Settlement, which was approved by FERC on May 2, 2019, preserved the 2016 settlement moratorium on further rate changes until September 1, 2020. Unless superseded by a subsequent rate case or settlement, Iroquois will be required to have new rates in ~~our pipeline systems’ revenues could occur as early as late 2018.~~effect by March 1, 2023.

~~The~~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 ~~directly address two components~~via an amendment to its prior 2016 settlement. Among the terms of ~~our pipeline systems’ cost~~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 ~~service based rates:~~ the ~~allowance for income taxes~~settlement. Tuscarora is required to have new rates in effect on February 1, 2023. Tuscarora and ~~the amount of ADIT. The 2018 FERC Actions~~its customers also ~~noted that precise treatment of entities with more ambiguous ownership structures must be separately resolved~~agreed on a ~~case-by-case basis, including those partially owned~~moratorium on rate changes until January 31, 2023. The 2019 Tuscarora Settlement, which was approved by ~~corporations such as Great Lakes, Northern Border, Iroquois and PNGTS pipelines. Additionally,~~ FERC ~~has indicated that any rate reduction is not expected to affect negotiated rate or non-recourse rate contracts.~~
~~Given the potential variability of outcomes arising from the 2018 FERC Actions, we are unable to precisely quantify the ultimate timing and amount of the reductions in revenue and earnings~~ on our future operating performance and cash flows. The Partnership continues to re-examine its next steps following the changes noted above and alternatives now available under the Final Rule. As noted above, the change in the Final Rule to allow MLPs to remove the ADIT liability from rate base, and thus increase net recoverable rate base, would partially mitigate the lossMay 2, 2019, will also reflect an elimination of the tax allowance previously recovered in ~~cost-of-service based rates. Various uncertainties still exist around~~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, effective January 1, 2020, the amended settlement agreement extends the two percent rate reduction implemented on February 1, 2019 to July 1, 2024.

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Financing Updates:

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

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

Partnership’s 2013 $500 Million Term Loan Facility - In June 2019, the Partnership repaid $50 million of ~~possible outcomes has improved when compared to~~outstanding borrowings under its 2013 $500 Million Term Loan Facility using the ~~estimated outcomes based~~proceeds received from the Northern Border distribution on the 2018 FERC Actions proposed in March 2018. Currently, the estimated overall impact of the tax-related changes to our revenue and cashflow is in a range of negative $40 million to $60 million per year as we execute our regulatory strategies through the process initiated by these FERC Actions. These estimates could change due to numerous assumptions around the resolution of related issues as they are applied individually across our pipeline systems. In addition, approximately half of the Partnership’s share of revenues (including those accounted for in the earnings of our equity investments) are derived from contracts that are non-recourse, which are not expected to be impacted by the 2018
~~FERC Actions. Accordingly, any reduction to the recourse rates would not have a proportional reduction on overall revenues.~~
~~Partnership Response and~~ ~~Outlook of Our Business~~
~~While revenues from our pipeline systems are not expected to decrease prior to individual rate proceedings,~~same date. Additionally, the Partnership ~~took proactive measures~~terminated an equivalent amount in interest rate swaps that were used to ~~conserve capital for near-term capital requirements~~hedge this facility at a rate of 2.81%.

Partnership’s Senior Credit Facility and Overall Debt Level - We continue to ~~manage its leverage metrics given~~deleverage our balance sheet. At June 30, 2019 and August 1, 2019, there was no outstanding balance under the ~~magnitude and timing of~~Partnership's Senior Credit Facility. Additionally, the ~~potential future cash flow decreases~~Partnership's overall consolidated debt was reduced by $115 million from $2,118 million at December 31, 2018 to $2,003 million at June 30, 2019 as a result of (a) $40 million net repayment from cash flow of the ~~2018 FERC Actions.~~
~~Accordingly,~~outstanding balance under the ~~Partnership reduced its first~~ Partnership's Senior Credit facility; (b) $50 million partial repayment of the Partnership's 2013 $500 Million Term Loan Facility;and second quarter 2018 cash distributions to unitholders to $0.65 per quarter representing a 35 percent reduction from its fourth quarter 2017 distribution of $1.00 per common unit. Cash retained by the Partnership will be used to fund ongoing capital expenditures and(c) the repayment of ~~debt~~$35 million due upon maturity of GTN's $75 million Unsecured Term Loan Facility offset by $10 million of additional borrowings on PNGTS's revolving credit facility.

Credit Rating Upgrade - On July 23, 2019, Standard & Poor's upgraded the Partnership’s credit rating to ~~levels that prudently manage~~BBB/Stable from BBB-/Stable primarily due to the improvement in our financial ~~metrics in anticipation~~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 ~~the reduction of revenues should our pipeline systems’ rates be reset~~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 ~~2018 FERC Actions that could begin as early as late 2018.~~
~~TransCanada,~~project was concluded in April of 2019 and the ultimate parent company of our General Partner, has historically viewed us as an element of its capital financing strategy. Following the 2018 FERC Actions initially proposed in March 2018, TransCanada stated that further dropdownsestimated in-service date is November 1, 2022, subject to the ~~Partnership were no longer considered to be a viable funding lever. As a result~~satisfaction or waiver of ~~the Final Rule issued on July 18, 2018, TransCanada continues to monitor developments~~certain conditions precedent.

PNGTS’ Portland XPress (PXP) Project - Our Portland XPress Project or “PXP” was initiated in ~~the Partnership~~2017 in order to ~~determine whether~~expand deliverability on the ~~Partnership might~~PNGTS system to Dracut through re-contracting and construction of incremental compression within PNGTS’ existing footprint in Maine. The PXP project was designed to be ~~restored as a competitive financing option~~phased in the future. Therefore, our traditional source of growth is currently not accessible under the current circumstances, and our options for further growth could be significantly limited. We are continuing to consider various options that would best position the Partnership for the long term to further minimize any negative effects of the 2018 FERC Actions. To respond to new information or changes in strategies in the future, the Partnership may consider further distribution level changes, either as a standalone action or in combination with other strategies.
~~Our focus remains on safe and reliable operations of our pipeline assets and we expect our assets to continue to serve their customers as designed.~~
~~Impairment Considerations~~
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.
~~We review property, plant and equipment and equity investments for impairment whenever events or changes in circumstances indicate the carrying value of the asset may not be recoverable.~~
Goodwill is tested for impairment on an annual basis or more frequently if events or changes in circumstance indicate that it might be impaired. We can initially make this assessment based on qualitative factors. If we conclude that it is not more likely than not that the fair value of the reporting unit is less than its carrying value, an impairment test is not performed.
Until the 2018 FERC Actions are implemented through individual proceedings or settlements, and we have fully evaluated our respective alternatives to minimize any negative impact, we believe that it is not more likely than not that the fair values of our reporting units are less than their respective carrying values. Therefore, a goodwill impairment test was not performed. Also, we have determined there is no indication that the carrying values of property, plant and equipment and equity investments potentially impacted by the 2018 FERC Actions are not recoverable. We will continue to monitor developments and assess our goodwill for impairment. We will also review our property, plant and equipment and equity investments for recoverability as new information becomes available.
At December 31, 2017, the estimated fair value of our investment in Great Lakes exceeded its carrying value by less than 10 percent. There is a risk that the 2018 FERC Actions, once implemented through the individual rate proceeding or settlement, could result to an impairment charge to our equity method goodwill on Great Lakes amounting to $260 million at June 30, 2018 (December 31, 2017 — $260 million). Additionally, since the estimated fair value of Tuscarora exceeded its carrying value by less than 10 percent in its most recent valuation, there is also a risk that the $82 million goodwill at June 30, 2018 (December 31, 2017 - $82 million) related to Tuscarora could be negatively impacted by the 2018 FERC Actions once implemented through the individual rate proceeding or settlement.
~~Other Business Developments~~
~~NOI on Certificate Policy Statement -~~ FERC issued a Notice of Inquiry on April 19, 2018 (“Certificate Policy Statement NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Certificate Policy Statement NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Any proposed changes to the current policy will be prospective only and it is expected that FERC will take many months to determine whether it will change anything for proposed natural gas pipeline projects. We do not expect that any change in this policy would affect us in a materially different manner than any other similarly sized natural gas pipeline company operating in the United States.
~~Portland XPress Project~~ ~~- As noted in our Annual Report for the year ended December 31, 2017, the in-service dates of PXP are being phased-in~~ over a three-year period ~~beginning~~which began November 1, ~~2018.~~2018 (Phase I). Phases II and III of the project are expected to be in-service on November 1, 2019 and 2020, respectively. Beginning 2021, the project is expected to generate approximately $50 million in annual revenue for PNGTS. During ~~the second quarter,~~2018, PNGTS filed the required applications with FERC for all three phases of the project, which ~~includes~~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 ~~volumes of~~ 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.

The PXP project is secured by long-term agreements and when all phases of the project are in service, PNGTS will be effectively fully contracted until 2032.

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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 with Phases 1, 2 and 3 estimated in-service dates of November 2019, 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 Portland XPress, will increase PNGTS' capacity by 90 percent from 210,000 Dth/day to approximately 400,000 Dth/day.

FERC issued an Order Granting Certificate on July 2, 2019, approving PNGTS' request to increase its certificated capacity under Westbrook Phase1, effective November 1, 2019.

Iroquois Gas Transmission ExC Project (Iroquois ExC Project) - In May 2019, one of Iroquois' customers, Consolidated Edison, Inc., announced that they had reached a precedent agreement to develop and permit incremental pipeline delivery capacity into New York City. Iroquois' "Expansion through Compression" or ExC Project 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. If successful, the project's total capacity is expected to be approximately 125,000 Dth/day with an estimated in-service date in November 2023. The capital cost of this project is still to be determined as the optimal facility set is finalized during the course of the regulatory process for this potential expansion. This project would be 100% underpinned with 20-year contracts.

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.

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RESULTS OF OPERATIONS

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

Three months
ended

Six months
ended

(unaudited)

June 30,

$

%

June 30,

$

%

(millions of dollars)

2018

2017

Change (a)

Change(a)

2018

2017

Change(a)

Change(a)

Transmission revenues

111

101

10

10

226

213

13

6

Equity earnings

36

24

12

50

95

60

35

58

Operating, maintenance and administrative

(25
)
(26
)
1

4

(49
)
(49
)
—

—

Depreciation

(24
)
(25
)
1

4

(48
)
(49
)
1

2

Financial charges and other

(23
)
(19
)
(4
)
(21
)
(46
)
(36
)
(10
)
(28
)
Net income before taxes

75

55

20

36

178

139

39

28

State income taxes

—

—

—

—

(1
)
(1
)
—

—

Net income

75

55

20

177

138

39

Net income attributable to non-controlling interests

2

—

2

—

8

6

2

(33
)
Net income attributable to controlling interests

73

55

18

33

169

132

37

28

Three months ended

Six months ended

(unaudited)

June 30,

$

%

June 30,

$

%
(millions of dollars)

2019

2018

Change ^(a)

Change ^(a)

2019

2018

Change ^(a)

Change ^(a)

Transmission revenues

93

111

(18)

(16)

206

226

(20)

(9)
Equity earnings

30

36

(6)

(17)

84

95

(11)

(12)
Operating, maintenance and administrative costs

(25)

(25)

—

—

(50)

(49)

(1)

(2)
Depreciation

(19)

(24)

5

21

(39)

(48)

9

19
Financial charges and other

(21)

(23)

2

9

(43)

(46)

3

7
Net income before taxes

58

75

(17)

(23)

158

178

(20)

(11)
Income taxes

(1)

—

(1)

—

(1)

(1)

—

—
Net income

57

75

(18)

(24)

157

177

(20)

(11)
Net income attributable to non-controlling interests

2

2

—

—

9

8

1

(13)
Net income attributable to controlling interests

55

73

(18)

(25)

148

169

(21)

(12)
~~(a)~~
(a) Positive number represents a favorable change; bracketed or negative number represents an unfavorable change.

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

The ~~Partnership’s~~Partnership's net income attributable to controlling interests ~~increased~~decreased by $18 million in the three months ended June 30, ~~2018~~2019 compared to ~~2017, an increase of $0.27 per common unit,~~2018, mainly due to the following:

Transmission revenues — - Revenues were ~~higher~~lower due largely to ~~incremental long-term services sold~~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. Revenues were also reduced by ~~GTN associated with~~ the increased available upstream capacity following debottlenecking activities on TransCanada’s pipelines offset by lower revenues from GTN’s short-term discretionary services. Additionally, PNGTS’ revenue increased primarily due to incremental contracting from PNGTS’ Continent-to-Coast contracts with several shippers for a term of 15 years for approximately 82,000 Dth/day (C2C contracts).following:

● lower revenue on GTN due to its scheduled 10 percent rate decrease effective January 1, 2019 as part of the settlement reached with its customers in 2018; and
● lower revenue from PNGTS primarily due to the expiration of its legacy recourse rate firm contracts partially offset by revenues from Phase 1 of its Portland XPress (PXP) project that went into service November 1, 2018.
Equity Earnings -The ~~$12~~$6 million ~~increase~~decrease was primarily due to the ~~inclusion of equity earnings from Iroquois for the full three months~~following:

● decrease in Great Lakes’ and Northern Border’s equity earnings as a result of rate reductions in early 2019 related to the 2018 FERC actions, together with an increase in operating costs related to compliance programs and allocated management and operational expenses 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 Iroquois Settlement.
Depreciation - The decrease in depreciation expense was a direct result of the ~~second~~long-lived asset impairment recognized during the fourth quarter of 2018 ~~compared to only one month in 2017 (our 49.34 percent ownership was effective June 1, 2017) and higher equity earnings from Great Lakes as a result of incremental seasonal winter sales during~~on Bison which effectively eliminated the ~~current period and the elimination of Great Lakes’ revenue sharing mechanism beginning in 2018 as part~~depreciable base of the ~~2017 Great Lakes Settlement.~~pipeline.

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Financial charges and other - The $4$2 million ~~increase~~decrease was primarily attributable to ~~additional~~the repayment of our $170 million Term Loan during the fourth quarter of 2018 and the net $40 million repayment of borrowings ~~to finance~~under our Senior Credit Facility during the ~~2017 Acquisition.~~first quarter of 2019.

~~Net income attributable to non-controlling interests~~ ~~- The Partnership’s net income attributable to non-controlling interests was higher due to the increase in PNGTS’ net income as a result of its higher revenue.~~
Six Months Ended June 30, ~~2018~~2019 compared to Same Period in ~~2017~~2018

The Partnership’s net income attributable to controlling interests ~~increased~~decreased by ~~$37~~$21 million in the six months ended June 30, ~~2018~~2019 compared to ~~2017, an increase of $0.55 per common unit,~~2018, mainly due to the following:

Transmission revenues — - Revenues were ~~higher~~lower due largely to ~~incremental long-term services sold by GTN~~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 ~~with the increased available upstream capacity following debottlenecking activities on TransCanada’s pipelines. Additionally, PNGTS’ revenue increased primarily~~transportation agreements. The decrease was also due to ~~incremental contracting from PNGTS’ C2C contracts partially offset by certain expiring winter contracts and North Baja experienced an increase in short-term firm transportation services.~~the following:

● increased contracting from GTN, offset by its scheduled 10 percent rate decrease effective January 1, 2019 as part of the settlement reached with its customers in 2018; and
● additional revenue from PNGTS from Phase 1 of its PXP project that went into service November 1, 2018 and higher discretionary revenues, offset by the expiration of its legacy recourse rate firm contracts.
Equity Earnings - The ~~$35~~$11 million ~~increase~~decrease was primarily due to the ~~inclusion~~net effect of ~~equity earnings from Iroquois for~~ the ~~full~~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;
● 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 and allocated management and operational expenses from TC Energy; and
● higher earnings from Northern Border resulting from an increase in its revenue from short-term firm services, partially offset by its scheduled rate reduction that became effective April 1, 2018 and an increase in its operating costs related to its compliance programs and allocated management and operational expenses from TC Energy.
Depreciation - The decrease in depreciation expense during the six months ~~of 2018 compared to only one month in 2017 (our 49.34 percent ownership~~ended June 30, 2019 was ~~effective June 1, 2017), as well as the increase in Iroquois’ short-term discretionary services during the 2018 period as~~ a direct result of the ~~colder winter weather in the Northeast. Additionally, equity earnings from Great Lakes increased as a result of incremental~~
~~seasonal winter sales~~long-lived asset impairment recognized during the ~~current period and~~fourth quarter of 2018 on Bison which effectively eliminated the ~~elimination of Great Lakes’ revenue sharing mechanism beginning in 2018 as part~~depreciable base of the 2017 Great Lakes Settlement. The additional earnings were partially offset by lower revenues and earnings from Northern Border resulting from its rate reduction as part of the 2017 Northern Border Settlement.pipeline.

Financial charges and other - The ~~$10~~$3 million ~~increase~~decrease was primarily attributable to ~~additional~~the repayment of our $170 million Term Loan during the fourth quarter of 2018 and repayment of borrowings ~~to finance~~under our Senior Credit Facility during the ~~2017 Acquisition.~~first quarter of 2019.
~~Net income attributable to non-controlling interests~~ ~~- The Partnership’s net income attributable to non-controlling interests was higher due to the increase in PNGTS’ net income as a result of its higher revenue.~~

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

As discussed in Note 9 within Item 11. “Financial Statements,” we will allocate a portion of the ~~Partnership’s~~Partnership's income to the Class B ~~Units~~units after the annual threshold is exceeded which will effectively reduce the income allocable to the common units and net income per common unit. Currently, we expect to allocate a portion of the ~~Partnership’s~~Partnership's income to the Class B units at the end of the ~~third~~fourth quarter of ~~2018.~~2019. Please also read Note 8 within Item 11. “Financial Statements,” for additional disclosures on the Class B units.

32
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.

~~The Partnership reduced its~~At June 30, 2019, the balance of our cash and cash equivalents was higher than our position at December 31, 2018 ~~quarterly distribution~~by approximately $12 million and our debt balance was lower by $115 million. We continue to ~~$0.65 per common unit, a 35 percent reduction from the fourth quarter 2017 distribution of $1.00 per common unit. Cash retained by the Partnership will be used~~use available cash to fund ongoing capital expenditures and the repayment of debt to levels that prudently manage ~~its~~our financial ~~metrics given the magnitude and timing of the potential future cash flow decreases as a result of the 2018 FERC Actions.~~metrics.

As of June 30, 2018, we had $51 million of cash and cash equivalents, an increase of $18 million or 55 percent from December 31, 2017, and we have reduced the outstanding balance of our Senior Credit Facility by 24 percent, from $185 million at December 31, 2017 to $140 million at June 30, 2018.  We believe our cash position, remaining borrowing capacity on our Senior Credit Facility (see table below), and our operating cash flows are ~~adequate~~sufficient to fund our short-term liquidity requirements, ~~over the next twelve months,~~ including ~~the revised~~ distributions to our unitholders, ongoing capital expenditures and required debt repayments.

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

(unaudited)
(millions of dollars)

June 30, 2018

December 31, 2017

(unaudited)




(millions of dollars)

June 30, 2019

December 31, 2018

Total capacity under the Senior Credit Facility

500

500

500

500
Less: Outstanding borrowings under the Senior Credit Facility

140

185

—

40
Available capacity under the Senior Credit Facility

360

315

500

460

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, in June 2019, Northern Border borrowed an additional $100 million under its $200 million revolving credit facility to finance a cash distribution of $100 million, of which $50 million was received by the Partnership. The Partnership used the $50 million proceeds to partially pay its 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.

33
Table of Contents
Cash Flow Analysis for the Six ~~Months Ended~~months ended June 30, ~~2018~~2019 compared to Same Period in ~~2017~~2018

Six months ended

Six months ended
(unaudited)

June 30,

June 30,
(millions of dollars)

2018

2017


2019

2018

Net cash provided by (used in):




Operating activities

223

205

228

223
Investing activities

(8
)
(625
)

22

(8)
Financing activities

(197
)
407

(238)

(197)
Net increase in cash and cash equivalents

18

(13
)

12

18
Cash and cash equivalents at beginning of the period

33

64

33

33
Cash and cash equivalents at end of the period

51

51

45

51

Operating Cash Flows

~~Net~~The Partnership's net cash provided by operating activities increased by ~~$18~~$5 million in the six months ended June 30, ~~2018~~2019 compared to the same period in ~~2017~~2018 primarily due to the net effect of:
·    ~~higher cash flow from operations at GTN, PNGTS and North Baja primarily resulting from an increase in their revenues;~~
·    ~~distributions received from Iroquois resulting from the addition of Iroquois to our portfolio of assets effective June 1, 2017;~~
·   higher interest expense attributable to additional borrowings to finance the acquisition of a 49.34 percent interest in Iroquois and an additional 11.81 percent interest in PNGTS (the 2017 Acquisition); and
·    ~~higher distributions received from Great Lakes due to an increase in its revenue in the fourth quarter of 2017 and first quarter of 2018 compared to the same periods of the previous years.~~
● amount and timing of earnings and cash distributions received from equity investments as a result of:
o lower capital spending related to compressor maintenance costs on Northern Border;
o net higher earnings generated by Northern Border and Great Lakes from the fourth quarter of 2018 to first quarter of 2019 compared to the same period in the prior year;
o higher distributions from our equity investments;
● lower net cash flow from operations of our consolidated subsidiaries primarily due to the decrease in Bison’s and GTN's revenues partially offset by an increase in PNGTS’ revenue; and
● positive impact from amount and timing of operating working capital changes.
Investing Cash Flows
~~Net cash used in investing activities decreased by $617 million during~~During the six months ended June 30, ~~2018~~2019, the cash provided by our investing activities was a net cash inflow of $22 million compared to a net outflow of $8 million in the same period in ~~2017~~2018 primarily due to the net ~~effect of:~~
·    ~~$605 million cash payment on June 1, 2017 to TransCanada for~~impact of the ~~2017 Acquisition;~~following:
·    ~~lower capital maintenance expenditures in the first six months of 2018 compared to 2017, during which period there were major compression equipment overhauls on GTN; and~~
·    ~~$5 million unrestricted cash distribution we received from Iroquois during the six months ended June 30, 2018 representing a return of investment (none received in 2017).~~
● $50 million distribution received from Northern Border that was considered as a return of investment during the second quarter of 2019; partially offset by
● higher capital maintenance expenditures on our consolidated subsidiaries and continued capital spending on our PXP project.
Financing Cash Flows
The Partnership's net ~~increase in~~ cash used infor financing activities was approximately ~~$604~~$41 million higher in the six months ended June 30, ~~2018~~2019 compared to the same period in ~~2017~~2018 primarily due to the net effect of:
● $20 million increase in net debt repayments;
● $28 million decrease in distributions paid primarily due to the $0.35 per common unit reduction in distribution payments during the second quarter of 2019 related to performance during the first quarter of 2019 as compared to the same period in 2018 in response to the 2018 FERC Actions;
● $2 million decrease in distributions paid to Class B units in 2019 as compared to 2018;
● no ATM equity issuances in 2019 year-to-date; and
● $12 million increase in distributions paid to non-controlling interests during the six months ended June 30, 2019 compared to the six months ended June 30, 2018 resulting from PNGTS' higher revenue in the first quarter of 2019 compared to its revenue in the first quarter of 2018.
34
·   ~~$95 million in net debt repayments in 2018 compared to $479 million net debt issuance in 2017 primarily due to the issuance~~Table of ~~$500 million 3.90% Senior Notes on May 25, 2017 to partially finance the 2017 Acquisition;~~Contents
·    $12 million decrease in distributions paid on our common units and to our General Partner in respect of its two percent general partner interest and IDRs as a result of the reduction in distributions declared and paid for the first quarter of 2018 as compared to 2017;
·    ~~$7 million decrease in distributions paid to Class B units in 2018 as compared to 2017;~~
·    ~~$52 million decrease in our ATM equity issuances in the six months ended June 30, 2018, as compared to the same period in 2017;~~
·    $2 million decrease in distributions paid to non-controlling interests due to lower distributions from PNGTS in the first six months of 2018 as compared to the first six months of 2017 to retain cash to repay the remaining balance on its Senior Notes; and
·    $1 million decrease in distributions paid to TransCanada as the former parent of PNGTS due to the Partnership’s acquisition of TransCanada’s then-remaining 11.81 percent interest in PNGTS effective June 1, 2017.
Short-Term Cash Flow Outlook
Operating Cash Flow Outlook
Northern Border declared its June ~~2018~~2019 distribution of ~~$12~~$15 million on July ~~11, 2018,~~8, 2019, of which the Partnership received its 50 percent share or $6$7 million. The distribution was paid on July 31, ~~2018.~~
2019.
Great Lakes declared its second quarter ~~2018~~2019 distribution of ~~$29~~$20 million on July ~~17, 2018,~~16, 2019, of which the Partnership received its 46.45 percent share or ~~$13~~$9 million. The distribution was paid on August 1, ~~2018.~~
2019.
Iroquois declared its second quarter ~~2018~~2019 distribution of ~~$29~~$28 million on July ~~25, 2018,~~24, 2019, of which the Partnership received its 49.34 percent share or $14 million on August 1, ~~2018.~~
~~Our equity investee Iroquois has $2 million of scheduled debt repayments for the remainder of 2018 and Iroquois’ debt repayments are expected to be funded through its cash flow from operations.~~
2019.
Investing Cash Flow Outlook
The Partnership made an equity contribution to Great Lakes of $4$5 million in the first quarter of ~~2018.~~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 ~~2018~~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 $3$20 million as of June 30, ~~2018~~2019 in connection with various maintenance and general plant projects.
In 2019, our pipeline systems expect to invest approximately $91 million in maintenance of existing facilities and approximately $40 million in growth projects, of which the Partnership’s share would be $73 million and $23 million, respectively.
Financing Cash Flow Outlook
On July ~~26, 2018,~~23, 2019, the board of directors of our General Partner declared the Partnership’s second quarter ~~2018~~2019 cash distribution in the amount of $0.65 per common unit payable on August ~~15, 2018~~14, 2019 to unitholders of record as of August ~~6, 2018.~~2, 2019. Please see Note 17 of the "Financial Statements" within Item 1 and “Recent Business Developments” ~~and Note 19~~ within Item ~~1 “Financial Statements”~~2 for additional disclosures.
~~On April 5, 2018, PNGTS entered into a $125~~We currently intend to refinance GTN’s $100 million Revolving Credit Facility. The facility will be utilized primarily to fund the costs of the PXP expansion project and to finance PNGTS’ other funding needs. As of August 2, 2018, PNGTS has not utilized its $125 million Revolving Credit Facility.
On ~~May 10, 2018, PNGTS paid the remaining principal balance of its 2003~~5.29% Unsecured Senior ~~Secured~~ Notes ~~using available cash.~~
~~PNGTS declared its second quarter 2018 distribution of $3 million~~due June 1, 2020, in full or at an amount based on ~~July 20, 2018, of which $1 million will be paid to its non-controlling interest owner on August 1, 2018.~~
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, ~~taxes,~~ 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,
● Equity allowance for funds used during construction (if any),
·                  ~~Earnings from our equity investments,~~35
·                  ~~Equity allowance for funds used during construction (Equity AFUDC),~~
·                  ~~Interest expense,~~
·                  ~~Income taxes,~~
·                  ~~Distributions to non-controlling interests,~~
·                  ~~Distributions to TransCanada as the former parent~~Table of ~~PNGTS, and~~Contents
● 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 ~~2018~~2019 equal 30 percent of ~~GTN’s~~GTN's distributable cash flow less $20 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.

36
Table of Contents
Reconciliations of 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

Six months ended
(unaudited)

June 30,

June 30,
(millions of dollars)

2019

2018

2019

2018
Net income

57

75

157

177

Add:








Interest expense ^(a)

22

25

44

48
Depreciation and amortization

19

24

39

48
Income taxes

1

—

1

1

EBITDA

99

124

241

274

Add:








Distributions from equity investments ^(b) (f)








Northern Border ^(c)

21

18

48

37
Great Lakes

9

14

32

39
Iroquois ^(d)

14

14

28

28

44

46

108

104
Less:








Equity earnings:








Northern Border

(14)

(15)

(35)

(32)
Great Lakes

(9)

(12)

(29)

(36)
Iroquois

(7)

(9)

(20)

(27)

(30)

(36)

(84)

(95)
Less:








AFUDC equity

(1)

—

(1)

—
Interest expense ^(a)

(22)

(25)

(44)

(48)
Income taxes

(1)

—

(1)

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

(3)

(2)

(10)

(9)
Maintenance capital expenditures ^(f)

(15)

(5)

(21)

(10)

(42)

(32)

(77)

(68)

Total Distributable Cash Flow

71

102

188

215
General Partner distributions declared ^(g)

(1)

(1)

(2)

(2)
Distributions allocable to Class B units ^(h)

—

—

—

—
Distributable Cash Flow

70

101

186

213
(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 and includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2 million and $5 million, respectively, for both the three and six months ended June 30, 2019 and 2018.
(e) Distributions to non-controlling interests represent the respective share of our consolidated entities' distributable cash not owned by us for the periods presented.
37

Three months ended

Six months ended

(unaudited)

June 30,

June 30,

(millions of dollars)

2018

2017

2018

2017

Net income

75

55

177

138

Add:

Interest expense(a)

25

20

48

37

Depreciation and amortization

24

25

48

49

Income taxes

—

—

1

1

EBITDA

124

100

274

225

Add:

Distributions from equity investments(b)

Northern Border

18

20

37

40

Great Lakes

14

7

39

27

Iroquois (c)

14

14

28

14

46

41

104

81

Less:

Equity earnings:

Northern Border

(15
)
(15
)
(32
)
(34
)
Great Lakes

(12
)
(6
)
(36
)
(23
)
Iroquois

(9
)
(3
)
(27
)
(3
)

(36
)
(24
)
(95
)
(60
)
Less:

Interest expense

(25
)
(20
)
(48
)
(37
)
Income taxes

—

—

(1
)
(1
)
Distributions to non-controlling interests(d)

(2
)
(3
)
(9
)
(8
)
Distributions to TransCanada as PNGTS’ former parent(e)

—

—

—

(1
)
Maintenance capital expenditures (f)

(5
)
(7
)
(10
)
(17
)

(32
)
(30
)
(68
)
(64
)

Total Distributable Cash Flow

102

87

215

182

General Partner distributions declared (g)

(1
)
(5
)
(2
)
(8
)
Distributions allocable to Class B units (h)

—

—

—

—

Distributable Cash Flow

101

82

213

174

~~(a)~~         ~~Interest expense as presented includes net realized loss or gain related to the interest rate swaps and amortization~~Table of ~~realized loss on PNGTS’ derivative instruments. Refer to Note 15 within Item 1 “Financial Statements”.~~Contents
(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 six months ended June 30, 2019 and 2018.
(h) For the six months ended June 30, 2019 and 2018, no distributions were allocated to the Class B units as the threshold was not exceeded. We expect the 2019 threshold will be exceeded during the fourth quarter of 2019. Please read Notes 8 and 9 within Item 1. “Financial Statements” for additional disclosures on the Class B units.
~~(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 during the current reporting period.
~~(c)~~         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, respectively, for the three and six months ended June 30, 2018 (2017 - $2.6 million for both periods).
~~(d)~~        ~~Distributions to non-controlling interests represent the respective share of our consolidated entities’ distributable cash not owned by us during the periods presented.~~
~~(e)~~         ~~Distributions to TransCanada as PNGTS’ former parent represent TransCanada’s respective share of PNGTS’ distributable cash not owned by us during 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)~~         ~~Distributions declared to the General Partner for the three and six months ended June 30, 2018 did not trigger any incentive distribution (2017 — $3 million and $5 million).~~
~~(h)~~        During the six months ended June 30, 2018 and 2017, no distributions were allocated to the Class B units as the annual threshold had not been exceeded. We expect the 2018 threshold will be exceeded at the end of the third quarter of 2018. Please read Notes 8 and 9 within Item 1 “Financial Statements” for additional disclosures on the Class B units.

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

Our EBITDA was ~~higher~~lower for the second quarter of ~~2018~~2019 compared to the same period in ~~2017~~2018. The $25 million decrease was primarily due to ~~higher~~lower revenue and equity earnings ~~and an overall increase in our revenues~~ during the period as discussed in more detail under the ~~Results~~“Results of ~~Operations~~Operations” section.
Our distributable cash flow ~~increased~~decreased by ~~$19~~$31 million in the second quarter of ~~2018~~2019 compared to the same period in ~~2017~~2018 due to the net effect of:
·    ~~higher EBITDA from GTN and PNGTS due to an increase in their revenues generated during the second quarter of 2018;~~
·    ~~higher distributions from Great Lakes due to the increase in revenue during the second quarter of 2018;~~
·    ~~lower maintenance capital expenditures compared to the second quarter of 2017, during which there were major compression equipment overhauls on GTN;~~
·    ~~increased interest expense due to additional borrowings to finance the 2017 Acquisition; and~~
·    ~~reduction in our declared distributions which did not result in any IDR allocation to our General Partner during the current period.~~
● lower EBITDA from our consolidated subsidiaries;
● higher maintenance capital expenditures related to major compression equipment overhauls on GTN and pipe integrity costs on Tuscarora, North Baja and GTN, all the result of higher transportation volumes of natural gas;
● lower interest expense due to repayment of the $170 million Term Loan during the fourth quarter of 2018 and the 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 partially offset by a decrease in its earnings as explained in the “Results of Operations” section; and
● lower distributions from our equity investment in Great Lakes primarily due to an increase in its capital spending on its compliance and integrity programs and decreased earnings as explained in the “Results of Operations” section.
Six months ended June 30, ~~2018~~2019 Compared to Same Period in ~~2017~~2018
~~Our~~Both our EBITDA ~~was higher~~and Distributable cash flow for the six months ended June 30, ~~2018~~2019 were lower compared to the same period in ~~2017 primarily due to higher equity earnings~~2018 and ~~an overall increase in~~were impacted by the same factors that impacted our ~~revenues during~~EBITDA and Distributable cashflow for the ~~period as discussed in more detail under the Results of Operations section.~~
~~Our distributable cash flow increased by $39 million in the six~~three months ended June 30, ~~2018~~2019 compared to ~~the same period in 2017 due to the net effect of:~~
·    ~~higher EBITDA from GTN, PNGTS and North Baja due to an increase in their revenues generated during the six~~three months ended June 30, ~~2018;~~2018.
·    ~~two quarters~~38
Table of distributions received from Iroquois during the six months ended June 30, 2018 compared to one distribution received during the previous period (ownership of 49.34 percent was effective June 1, 2017);Contents
·    ~~higher distributions from Great Lakes due to the increase in revenue generated during the six months ended June 30, 2018;~~
·    ~~lower maintenance capital expenditures compared to 2017 during which there were major compression equipment overhauls on GTN;~~
·    ~~increased interest expense due to additional borrowings to finance the 2017 Acquisition; and~~
·    ~~reduction in declared distributions which did not result in any IDR allocation to our General Partner during the current period.~~
Contractual Obligations

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

The ~~Partnership’s~~Partnership's contractual obligations ~~related to debt~~ as of June 30, ~~2018~~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 Six Months
Ended June 30,
2018

Payments Due by Period












Weighted Average

Interest Rate for

the Six Months
(unaudited)

Less than

1‑3

4‑5

More than 5

Ended June 30,
(millions of dollars)

Total

1 Year

Years

Years

Years

2019
TC PipeLines, LP












Senior Credit Facility due 2021

140

—

—

140

—

2.99
%

—

—

—

—

—

3.61 %
2013 Term Loan Facility due 2022

500

—

—

500

—

3.02
%

450

—

—

450

—

3.73 %
2015 Term Loan Facility due 2020

170

—

170

—

—

2.91
%
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

3.9%^(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

35

35

—

—

—

2.71
%
PNGTS












Revolving Credit Facility due 2023

—

—

—

—

29

—

—

29

—

3.74%
North Baja












Unsecured Term Loan due 2021

50

—

50

—

—

3.56%
Tuscarora












Unsecured Term Loan due 2020

25

1

24

—

—

2.87
%

24

1

23

—

—

3.62%

2,320

36

644

640

1,000

Partnership (TC PipeLines, LP and its subsidiaries)












Interest on Debt Obligations^(b)

488

89

145

93

161


Operating Leases

1

—

1

—

—


Right of Way commitments

4

1

—

1

2



2,496

191

569

573

1,163

(a) Fixed interest rate.
(b) Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at June 30, 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 June 30, ~~2018~~2019 was ~~$2,311~~$2,064 million.

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

39
Table of Contents
Summary of Northern ~~Border’s~~Border's Contractual Obligations

Northern ~~Border’s~~Border's contractual obligations ~~related to debt~~ as of June 30, ~~2018~~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 Six
Months Ended
June 30, 2018

Payments Due by Period ^(a)












Weighted Average

Interest Rate for the
(unaudited)

Less than

1‑3

4‑5

More than 5

Six Months Ended
(millions of dollars)

Total

1 Year

Years

Years

Years

June 30, 2019
$200 million Credit Agreement due 2020

15

—

15

—

—

2.94
%

115

—

115

—

—

3.70%
7.50% Senior Notes due 2021

250

—

—

250

—

7.50
%(b)

250

—

250

—

—

7.50%^(b)

265

—

15

250

—

Interest payments on debt ^(c)

44

11

33

—

—


Right of way commitments

47

2

5

5

35



456

13

403

5

35

(a) Represents 100 percent of Northern Border's debt obligations.
(b) Fixed interest rate.
(c) Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at June 30, 2019 and are therefore subject to change.
(a)   ~~Represents 100 percent of Northern Border’s debt obligations~~
~~(b)~~    ~~Fixed interest rate~~

As of June 30, ~~2018, $15~~2019, $115 million was outstanding under Northern ~~Border’s~~Border's $200 million revolving credit agreement, leaving ~~$185~~$85 million available for future borrowings. At June 30, ~~2018,~~2019, Northern Border was in compliance with all of its financial covenants.

Northern Border has commitments of $5$8 million as of June 30, ~~2018~~2019 in connection with ~~the meter station growth project, the~~ 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 June 30, ~~2018~~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 Six
Months
Ended June
30, 2018

9.09% series Senior Notes due 2018 - 2021

40

10

20

10

—

9.09
%(b)
6.95% series Senior Notes due 2019 - 2028

110

11

22

22

55

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

100

—

10

20

70

8.08
%(b)

250

21

52

52

125

Payments Due by Period ^(a)












Weighted Average

Interest Rate for the
(unaudited)

Less than

1‑3

4‑5

More than 5

Six Months Ended
(millions of dollars)

Total

1 Year

Years

Years

Years

June 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)

91

17

29

20

25


Right of way commitments

1

—

—

—

1



321

38

91

62

130

(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 ~~$135~~$123 million of Great ~~Lakes’ partners’~~Lakes' partners' capital was restricted as to distributions as of June 30, ~~2018~~2019 (December 31, ~~2017~~2018 — ~~$139~~$129 million). Great Lakes was in compliance with all of its financial covenants at June 30, ~~2018.~~2019.

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Great Lakes has commitments of $3$11 million as of June 30, ~~2018~~2019 in connection with pipeline integrity program spending, major overhaul projects, and right of way renewals.

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

~~Iroquois’~~Iroquois' contractual obligations ~~related to debt~~ as of June 30, ~~2018~~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 Six
Months Ended
June 30, 2018

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

37

5

9

7

16

6.10
%(b)

327

145

159

7

16

Payments Due by Period ^(a)












Weighted Average

Interest Rate for the
(unaudited)

Less than

1‑3

4‑5

More than 5

Six Months Ended
(millions of dollars)

Total

1 Year

Years

Years

Years

June 30, 2019
4.12% series Senior Notes due 2034

140

—

—

—

140

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

150

—

—

—

150

4.84%^(c)
6.10% series Senior Notes due 2027

32

5

7

8

12

6.1%^(b)
Interest payments on debt ^(d)

103

15

15

14

59


Transportation by others ^(e)

11

3

7

1

—


Operating leases

5

1

1

1

2


Pension contributions ^(f)

1

1

—

—

—



442

25

30

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 percent 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 June 30, 2019 and are therefore subject to change.
(f) Pension contributions cannot be reasonably estimated by Iroquois beyond 2019.
(a) ~~Represents 100 percent of Iroquois’ debt obligations.~~
~~(b)~~ ~~Fixed interest rate~~

Iroquois has commitments of $2$53 million as of June 30, ~~2018 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 June 30, ~~2018,~~2019, the debt/capitalization ratio was ~~47.4%~~49.2 percent and the debt service coverage ratio was ~~6.24 times,~~5.38 times; therefore, Iroquois was not restricted from making any cash distributions.

RELATED PARTY TRANSACTIONS

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

Item 3.Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

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

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 June 30, ~~2018,~~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’~~PNGTS's Revolving Credit Facility and ~~Tuscarora’s~~Tuscarora's Unsecured Term Loan Facility, under which ~~$370~~$103 million, or 165 percent, of our outstanding debt was subject to variability in LIBOR interest rates (December 31, ~~2017- $435~~2018- $168 million or 188 percent).

As of June 30, ~~2018,~~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 basis points), compared with rates in effect at June 30, ~~2018,~~2019, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $4$1 million.

As of June 30, ~~2018, $15~~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 basis points), compared with rates in effect at June 30, ~~2018,~~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' 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.
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Table of ~~payments over time according to specified terms.~~Contents

● 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% (See also Note 13 within Item 1. "Financial Statements").

At June 30, ~~2018,~~2019, the fair value of the interest rate swaps accounted for as cash flow hedges was ~~an asset~~a liability of ~~$15~~$5 million (both on a gross and net basis)~~. At December~~ (December 31, ~~2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an~~2018 - asset of ~~$5 million (on both gross and net basis)~~$8 million). The change in fair value of interest rate derivative instruments recognized in other comprehensive income was a loss of $1$9 million and ~~a gain of $6~~$14 million for the three and six months ended June 30, 2019, respectively (June 30, 2018 ~~respectively (2017 — nil~~- loss of $1 million and gain of $1$6 million). During the three and six months ended June 30, ~~2018,~~2019, a gain of $3$1 million was reclassified from other comprehensive income to net income ~~(2017 — loss~~(June 30, 2018 - gain of $1$3 million). For the three and six months ended June 30, ~~2018,~~2019, the net realized gain related to the interest rate swaps was ~~$1 million~~nil and $2a gain of $1 million, respectively, and was included in financial charges and other ~~(2017~~(June 30, 2018 - ~~nil)~~gain of $1 and gain of $2 million).
The Partnership’s $500 million 2013 Term Loan is hedged using fixed interest rate swaps until July 1, 2018 at an average rate of 2.31 percent. During the fourth quarter of 2017, the Partnership implemented an interest rate hedging strategy that hedged the $500 million 2013 Term Loan 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 June 30, ~~2018 (net asset of $5 million as of~~2019 and December 31, ~~2017).~~2018.

~~In anticipation~~COMMODITY PRICE RISK

The Partnership is influenced by the same factors that influence our pipeline systems. None 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~~our 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 was amortized against earnings over the life of the PNGTS Senior Secured Notes.~~ On May 10, 2018, PNGTS paid the remaining principal balance of its 2003 Senior Secured Notes using its available cash and, as a result, our 61.71 percent proportionate share of the net unamortized loss on PNGTS included in other comprehensive income was all amortized against earnings (December 31, 2017 - $1 million). For the three and six months ended June 30, 2018, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $1 million (2017 - $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 and our pipeline systems have significant credit exposure to financial institutions as they 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. 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 consolidated 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 June 30, ~~2018,~~2019, we had not incurred any significant credit losses and had no significant amounts past due or impaired. AtAdditionally, during the three and six months ended June 30, ~~2018 Anadarko Energy Services Company owed us approximately $4 million which represented greater~~2019 and at June 30, 2019, no customer accounted for more than 10 percent of our ~~trade~~consolidated revenue and accounts ~~receivable.~~receivable, respectively.

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
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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.~~liquidity.

At June 30, 2018, the Partnership had a Senior Credit Facility of $500 million maturing in 2021 and the outstanding balance on this facility was $140 million. In addition, PNGTS has a $125 million Revolving Credit Facility maturing in 2023 that has not been utilized at June 30, 2018 and Northern Border had a committed revolving bank line of $200 million maturing in 2020 with $15 million drawn at June 30, 2018. The Senior Credit Facility, the Northern Border $200 million credit facility and the PNGTS $125 million credit facility all have accordion features for additional capacity of $500 million, $100 million and $50 million, respectively, subject to lender consent.
Item 4.Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act) the management of our General Partner, including the principal executive officer and principal financial officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. The ~~Partnership’s~~Partnership's disclosure controls and procedures are designed to provide reasonable assurance of 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 June 30, ~~2018,~~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, ~~2017.~~2018.

~~Great Lakes v. Essar Steel Minnesota LLC, et al~~~~. —~~
~~A description of this legal proceeding can be found in Note 16 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 1A1A. “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~2018.

We do not own the majority of the land on which our pipeline systems are ~~exploring and evaluating potential mitigation strategies to the 2018 FERC Actions and other factors, including a possible reorganization that~~located, which could result in ~~us no longer being a master limited partnership.~~
~~Given the effects of a number of factors, including the 2017 Tax Act~~higher costs and the 2018 FERC Actions, which resulted in an uncertainty of whether we could be restored as a viable funding lever for TransCanada, we are evaluating potential strategic alternatives for the Partnership, including whether remaining a master limited partnership is the appropriate structure for us.
~~No decision has been made~~disruptions to our operations, particularly with respect to ~~any mitigation strategies~~easements and we cannot assure you that the exploration of mitigation strategies will result in the identification or consummation of any transaction that allows our unitholders to realize an increase in the value of their common units or provide any guidance on the timing of such action, if any. We also cannot assure you that any mitigation strategy, if identified, evaluated and consummated, will provide greater value to our unitholders than that reflected in the current price of our common units.rights-of-way across Indian tribal lands.

We do not ~~intend to comment regarding~~own the ~~evaluation of strategic alternatives until such time as the board of directors of our general partner has determined the outcome~~majority of the process or otherwise has deemed that disclosure is appropriate. As a consequence, perceived uncertainties related to our future may result in the loss of potential business opportunities and volatility in the market price of our common units.
~~Our strategy of providing stable cash distributions~~land on ~~our common units by expanding our business may be significantly inhibited by the 2018 FERC Actions.~~
TransCanada has historically sold certain FERC-regulated assets to the Partnership, subject to TransCanada’s funding needs and market conditions. Absent these dropdowns from TransCanada, our options for further growth could be significantly limited and there is uncertainty in whether we could be restored as a viable funding lever for TransCanada as a result of the 2018 FERC Actions. Also, market response to the 2018 FERC Actions has increased the relative cost of equity that the Partnership would incur to partially fund acquisitions or expansions in the future. Further deterioration of financial conditions could also raise the borrowing costs of the Partnership.
If we cannot successfully finance and complete expansion projects or make and integrate acquisitions that are accretive and the earnings of our existing pipeline systems are materially and adversely impacted as a result of the 2018 FERC Actions, we will not be able to maintain historical levels of cash flow and distributions. For example, if we are unable to replace revenues from Bison once its contracts expire in January of 2021 or we are unable to replace cash flow that may be reduced through future rate proceedings, we could be required to take additional proactive measures, including further reductions in distributions from the current level of $0.65 per common unit, to facilitate repayments of debt as may be needed to maintain compliance with financial covenants, in addition to taking other significant strategic actions.
~~Rates and other terms of service for~~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 rights expire after a specified period of time. As a result, we are subject to the possibility of more onerous terms and increased costs to renew expiring easements, rights-of-way and other land use rights. While we are generally able to obtain these rights through agreement with land owners or legal process if necessary, rights-of-way across Indian tribal land require approval of the applicable tribal governing authority and ~~potential adjustment by FERC, which~~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 ~~limit their ability~~also be subject to ~~recover all costs~~a disruption of ~~capital and~~ operations and increased costs to re-route the applicable portion of our pipeline system located on tribal land. Increased costs associated with renewing or obtaining new easements or rights-of-way and any disruption of operations could negatively impact ~~their rate of return,~~the results of operations and cash available for ~~distribution.~~distribution from our pipeline systems.
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Our Great Lakes pipeline ~~systems are subject to extensive regulation over virtually all aspects~~system had rights-of-way that expired during the second quarter of ~~their business, including~~2018 on approximately 7.6 miles of pipeline across tribal land located within the ~~types~~Fond du Lac Reservation and ~~terms of services they may offer to their customers, construction of new facilities, creation, modification or abandonment of services or facilities,~~Leech Lake Reservation in Minnesota and the ~~rates that they can charge~~Bad River Reservation in Wisconsin. We are negotiating to ~~shippers. Under~~renew the ~~Natural Gas Act, their rates must~~rights-of-way with the tribal authorities and expect to continue operating the Great Lakes pipeline while continuing good faith negotiations with the tribal authorities to obtain the necessary rights.

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 to resolve the lease issues for all three tribes.

If discussions with any of the three tribes ultimately are unsuccessful or the cost of renewal is significantly high, we could be ~~just, reasonable~~required or choose to remove and ~~not unduly discriminatory. Actions by FERC could adversely affect our~~relocate a portion or portions of the Great Lakes pipeline ~~systems’~~system from the tribal lands at a significant cost. While the outcome of these negotiations or the ability to ~~recover all~~reach agreements is uncertain, the impact of ~~their current~~a disruption of operations and cost of relocating a portion of the Great Lakes pipeline or ~~future~~significantly increased costs ~~and~~to renew the rights-of-way could ~~negatively impact their rate of return,~~have a material adverse effect on our financial condition, results of operations and cash ~~available for distribution.~~flows.

~~Due to~~Chemical substances in the ~~uncertainties surrounding~~natural gas our pipeline systems transport could cause damage or affect the ~~2018 FERC Actions, implementation~~ability of our ~~regulatory strategy~~pipeline systems' or third-party equipment to function properly, which may result in increased preventative and corrective action costs.

GTN identified the presence of a chemical substance, dithiazine, at several facilities on the GTN system and those of some upstream and downstream connecting pipeline facilities. 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 occur resulting in increased preventative and corrective action costs.

While we believe that the presence of dithiazine on our pipeline systems 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 ~~negative impact~~safety issues to people, equipment or the environment on our ~~future operating performance~~pipeline system. At least one over pressure incident potentially related to dithiazine has been reported on a customer's system. Until more information is gathered, we cannot speculate on the impact to customers, some of which may not have adequate overpressure protection. Additionally, our pipeline systems are also working with customers, and ~~cash flows~~other stakeholders, gathering information on the substance, seeking potential options to address the issue, and have informed federal and state regulators, trade associations, and other stakeholders of this information. Additionally, we are currently evaluating interim and long-term solutions to address the presence of dithiazine and, at this time, GTN continues to make capital expenditures to address the matter. In 2018, we incurred capital expenditures of approximately $5 million and, unless the issue is resolved, we expect to spend approximately $10 million to $12 million in 2019 and 2020 in aggregate to further mitigate the matter. There can be no assurance that significant additional costs will ~~take time. Moreover, we believe that future results of operations, cash flows and financial position of the Partnership could~~not be materially and negatively impacted once our pipelines’ rates are ultimately adjusted following these decisions. Our assumptions around the potential outcomes of the 2018 FERC Actions could be incorrect such that cash available for distributionincurred in the future or that dithiazine or other substances will not be identified on our other pipeline systems.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would ~~be lower than anticipated,~~affect publicly traded partnerships including legislative proposals that would have eliminated
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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 ~~could necessitate further action beyond our immediate responses described under Item~~is similar to legislation that was proposed during the Obama Administration, was introduced in the Senate on May 2, ~~“Management’s Discussion and Analysis of Financial Condition and Results of Operations” of~~2019. If enacted, this ~~Quarterly Report on Form 10-Q.~~
~~Future events, such as the outcome~~proposal would, among other things, repeal Section 7704(d)(1)(E) of the ~~2018 FERC Actions,~~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 ~~our estimates of fair~~the value of an investment in our ~~pipeline systems and equity investments, necessitating recognition of impairment.~~
We consider the carrying value of our assets, including goodwill and our equity method investments, whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments that we account for under the equity method, the impairment test requires uscommon units. You are urged to ~~consider whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Our assumptions related~~consult with your own tax advisor with respect to the ~~estimated fair value~~status of regulatory or administrative developments and proposals and their potential effect on your investment in our ~~remaining carrying value of each of our pipeline systems could be negatively impacted by near and long-term conditions including:~~common units.

· ~~future regulatory rate action or settlement,~~
· ~~valuation of assets in future transactions,~~
· ~~changes in customer demand for pipeline capacity and services,~~
· ~~changes in North American natural gas production in the major producing basins,~~
· ~~changes in natural gas prices and natural gas storage market conditions, and~~
· ~~changes in other long-term strategic objectives.~~
There is a risk that adverse changes in these key assumptions as a result of the 2018 FERC Actions or other circumstances could result in future impairment of the carrying value of our pipeline systems.
The development of fair value estimates requires significant judgment including estimates of future cash flows, which are dependent on internal forecasts, estimates of the long-term rate of growth, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. Following the 2018 FERC Actions, many of these elements will be revisited as individual rate proceedings clarify specific applications of the new policies and rules. At this time, we are unable to precisely calculate the impact on fair value, if any, due to uncertainties surrounding the 2018 FERC Actions.
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.

~~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).
~~3.1.1~~
Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated December 13, 2017 (incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed December 15, 2017).
~~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~~S1 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 8K filed January 2, 2019).
4.1

Indenture, dated as of June 17, 2011, between the Partnership and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to TC PipeLines, ~~LP’s~~LP's Form ~~8-K~~8K 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~~LP's Form ~~8-K~~8K 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~~LP's Form ~~8-K~~8K 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~~LP's Form ~~8-K~~8K 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 ~~8-K~~8K filed March 13, 2015).
4.6

Third Supplemental Indenture, dated as of May 25, 2017, relating to the issuance of $500,000,000 aggregate principal amount of 3.900% Senior Notes due 2027 (Incorporated by reference from Exhibit 4.2 to TC PipeLines, ~~LP’s~~LP's Form ~~8-K~~8K filed May 25, 2017).
~~4.7~~
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).
~~4.8~~
~~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).~~
~~4.9~~
~~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).~~
~~4.10~~
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).
~~4.10.1~~
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).
~~4.11~~
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).
~~4.11.1~~
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 4.5.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
10.1*
~~Transportation Service Agreement FT19214 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 16, 2018.~~
10.2*
~~Transportation Service Agreement FT19215 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 16, 2018.~~
10.3*
~~Amended Precedent Agreement by and between Portland Natural Gas Transmission System and TransCanada PipeLines Limited~~
10.4*
~~Amended Financial Assurances Agreement by and between Portland Natural Gas Transmission System and TransCanada PipeLines Limited~~
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.

~~101.INS~~101

~~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.~~The following materials from TC Pipelines, LP's Quarterly Report on Form 10-Q for the period ended June 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).

46
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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 2nd1^st day of August ~~2018.~~2019.

TC PIPELINES, LP

(A Delaware Limited Partnership)

by its General Partner, TC PipeLines GP, Inc.

By:
/s/ Nathaniel A. Brown

Nathaniel A. Brown

President

TC PipeLines GP, Inc. (Principal Executive Officer)

By:
/s/ William C. Morris

William C. Morris

Vice President and Treasurer

TC PipeLines GP, Inc. (Principal Financial Officer)

50

47

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 executive offices)		(Zip code)

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


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

Emerging growth companyo	☐

			Page No.
PART I	FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (Unaudited)	7
~~Item 2.~~	~~Management’s~~Notes to Consolidated Financial Statements	12
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	3028
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4341
Item 4.	Controls and Procedures	4544

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	4544
Item 1A.	Risk Factors	4544
Item 6.	Exhibits	4846
	Signatures	5047

2013 Term Loan Facility		TC PipeLines, ~~LP’s term loan credit facility under a term loan agreement as amended, dated September 29, 2017~~
~~2015 GTN Acquisition~~		~~Partnership’s acquisition of the remaining 30 percent interest in GTN on April 1, 2015~~
~~2015 Term Loan Facility~~		~~TC PipeLines, LP’s~~LP's term loan credit facility under a term loan agreement as amended, dated September 29, 2017
2017 ~~Acquisition~~		~~Partnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017~~
~~2017 Great Lakes Settlement~~		~~Stipulation and Agreement of Settlement for Great Lakes regarding its rates and terms and conditions of service approved by FERC on February 22, 2018~~
~~2017 Northern Border Settlement~~		~~Stipulation and Agreement of Settlement for Northern Border regarding its rates and terms and conditions of service approved by FERC on February 23, 2018~~
~~2017~~ Tax Act		~~H.R.1, originally~~Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act, enacted on December 22, 2017
2018 FERC Actions		~~FERC’s March 15,~~FERC's 2018 issuance of ~~(1) a revised~~Revised Policy Statement ~~to address the treatment~~on Treatment of ~~income taxes for ratemaking purposes for master limited partnerships (MLPs), (2)~~Income Taxes (Revised Policy Statement) and a ~~Notice of Proposed Rulemaking (NOPR) proposing~~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, ~~to quantify~~called FERC Form No. 501-G, that quantified the rate impact of the ~~federal income tax rate reduction~~2017 Tax Act on FERC-regulated pipelines and the revised Policy Statement could have on pipelines’ revenue requirements, and (3) a Notice of Inquiry (NOI) seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation; and FERC’s July 18, 2018 issuance of (1) an Order on Rehearingimpact of the Revised Policy Statement ~~dismissing rehearing related~~on pipelines held by an MLP
2019 Iroquois Settlement		An uncontested settlement filed by Iroquois with FERC to address the ~~revised Policy Statement~~issues contemplated by the 2017 Tax Act and ~~(2) a Final Rule adopting procedures from,~~2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
2019 Tuscarora Settlement		An uncontested settlement filed by Tuscarora with FERC to address the issues contemplated by the 2017 Tax Act and ~~clarifying aspects of, the NOPR~~2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
ADIT		Accumulated Deferred Income Tax
ASC		Accounting Standards Codification
~~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
~~C2C Contracts~~Class B Reduction		~~PNGTS’ Continent-to-Coast Contracts with several shippers~~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 ~~a term~~any particular calendar year until distributions payable in respect of ~~15 years~~common units for ~~approximately 82,000 Dth/day~~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
IDRs		Incentive Distribution Rights
ILPs		Intermediate Limited Partnerships
Iroquois		Iroquois Gas Transmission System, L.P.
LIBOR		London Interbank Offered Rate
~~MLPs~~		~~Master limited partnerships~~
~~NGA~~		~~Natural Gas Act of 1938~~
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

~~PHMSA~~		~~U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration~~
PNGTS		Portland Natural Gas Transmission System
PXP		Portland XPress Project

~~Term Loan Facilities~~ROU		~~The 2013 Term Loan Facility and the 2015 Term Loan Facility, collectively~~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
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

	Three months ended						Six months ended
(unaudited)	June 30,						June 30,
(millions of dollars, except per common unit amounts)	2018			2017			2018			2017

Transmission revenues	111			101			226			213
Equity earnings (Note 5)	36			24			95			60
Operation and maintenance expenses	(17		)	(17		)	(33		)	(31		)
Property taxes	(7		)	(7		)	(14		)	(14		)
General and administrative	(1		)	(2		)	(2		)	(4		)
Depreciation	(24		)	(25		)	(48		)	(49		)
Financial charges and other (Note 15)	(23		)	(19		)	(46		)	(36		)
Net income before taxes	75			55			178			139
Income taxes (Note 18)	—			—			(1		)	(1		)
Net income	75			55			177			138

Net income attributable to non-controlling interests	2			—			8			6
Net income attributable to controlling interests	73			55			169			132

Net income attributable to controlling interest allocation (Note 9)
Common units	72			50			166			122
General Partner	1			5			3			8
TransCanada and its subsidiaries	—			—			—			2
	73			55			169			132

Net income per common unit (Note 9) – basic and diluted	$	1.00		$	0.73		$	2.33		$	1.78

Weighted average common units outstanding – basic and diluted (millions)	71.3			68.9			71.2			68.6

Common units outstanding, end of period (millions)	71.3			69.0			71.3			69.0

(unaudited)
(millions of dollars)	June 30, 2018	December 31, 2017

ASSETS
Current Assets
Cash and cash equivalents	51	33
Accounts receivable and other (Note 14)	40	42
Inventories	8	8
Other	9	7
	108	90

Equity investments (Note 5)	1,211	1,213
Plant, property and equipment (Net of $1,229 accumulated depreciation; 2017 - $1,181)	2,086	2,123
Goodwill	130	130
Other assets	11	3
	3,546	3,559

LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	27	31
Accounts payable to affiliates (Note 12)	6	5
Distribution payable	—	1
Accrued interest	12	12
Current portion of long-term debt (Note 7)	36	51
	81	100

Long-term debt, net (Note 7)	2,272	2,352
Deferred state income taxes (Note 18)	10	10
Other liabilities	28	29
	2,391	2,491
Partners’ Equity
Common units	912	824
Class B units (Note 8)	95	110
General partner	22	24
Accumulated other comprehensive income (AOCI)	15	5
Controlling interests	1,044	963

Non-controlling interests	111	105
	1,155	1,068
	3,546	3,559

	Limited Partners						General		Accumulated Other Comprehensive	Non- Controlling
(unaudited)	Common Units			Class B Units			Partner		Income (a)	Interest		Total Equity
	millions of units	millions of dollars		millions of units	millions of dollars		millions of dollars		millions of dollars	millions of dollars		millions of dollars

Partners’ Equity at December 31, 2017	70.6	824		1.9	110		24		5	105		1,068
Net income	—	166		—	—		3		—	8		177
Other comprehensive income	—	—		—	—		—		10	1		11
ATM equity issuances, net (Note 8)	0.7	39		—	—		1		—	—		40
Distributions	—	(117	)	—	(15	)	(6	)	—	(3	)	(141	)

Partners’ Equity at June 30, 2018	71.3	912		1.9	95		22		15	111		1,155


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

ASSETS
Current Assets
Cash and cash equivalents	45	33
Accounts receivable and other (Note 14)	33	48
Inventories	9	8
Other	3	8
	90	97

Equity investments (Note 5)	1,118	1,196
Property, plant and equipment
(Net of $1,145 accumulated depreciation; 2018 - $1,110)	1,520	1,529
Goodwill	71	71
Other assets	—	6
TOTAL ASSETS	2,799	2,899

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities	26	36
Accounts payable to affiliates (Note 12)	6	6
Accrued interest	11	12
Current portion of long-term debt (Note 7)	101	36
	144	90
Long-term debt, net (Note 7)	1,892	2,072
Deferred state income taxes	9	9
Other liabilities	34	29
	2,079	2,200
Partners’ Equity
Common units	514	462
Class B units (Note 8)	95	108
General partner	14	13
Accumulated other comprehensive income (loss) (AOCI)	(5)	8
Controlling interests	618	591
Non-controlling interests	102	108
	720	699
TOTAL LIABILITIES AND PARTNERS' EQUITY	2,799	2,899


						Accumulated
						Other	Non-
	Limited Partners				General	Comprehensive	Controlling	Total
	Common Units		Class B Units		Partner	Income (Loss) ^(a)	Interest	Equity
	millions	millions	millions	millions	millions	millions	millions	millions
(unaudited)	of units	of dollars	of units	of dollars	of dollars	of dollars	of dollars	of dollars

Partners' Equity at December 31, 2018	71.3	462	1.9	108	13	8	108	699
Net income		145		—	3	—	9	157
Other comprehensive income (loss)		—		—	—	(13)	—	(13)
Distributions (Note 10)		(93)		(13)	(2)	—	(15)	(123)
Partners' Equity at June 30, 2019	71.3	514	1.9	95	14	(5)	102	720

	Ownership		Equity Earnings				Equity Investments
	Interest at		Three months		Six Months

									Ownership		Equity Earnings				Equity Investments
									Interest at		Three months ended		Six months ended
(unaudited)	June 30,		ended June 30,		ended June 30,		June 30,	December 31,	June 30,		June 30,		June 30,		June 30,	December 31,
(millions of dollars)	2018		2018	2017	2018	2017	2018	2017	2019		2019	2018	2019	2018	2019	2018

Northern Border (a)	50	%	15	15	32	34	505	512

Northern Border									50	%	14	15	35	32	431	497
Great Lakes	46.45	%	12	6	36	23	485	479	46.45	%	9	12	29	36	484	489
Iroquois(b)	49.34	%	9	3	27	3	221	222
			36	24	95	60	1,211	1,213
Iroquois									49.34	%	7	9	20	27	203	210
											30	36	84	95	1,118	1,196

(unaudited) (millions of dollars)	Three months ended June 30, 2018		One month ended June 30, 2017		Six months ended June 30, 2018		One month ended June 30, 2017

Transmission revenues	44		14		105		14
Operating expenses	(14	)	(5	)	(28	)	(5	)
Depreciation	(7	)	(2	)	(15	)	(2	)
Financial charges and other	(4	)	(1	)	(7	)	(1	)
Net income	19		6		55		6

(unaudited-millions of dollars)	June 30, 2018	January 1, 2018

Receivables from contracts with customers(a)	37	40
Contract assets(b)	—	—

(unaudited) (millions of dollars)	June 30, 2018	Weighted Average Interest Rate for the Six Months Ended June 30, 2018		December 31, 2017		Weighted Average Interest Rate for the Year Ended December 31, 2017

TC PipeLines, LP
Senior Credit Facility due 2021	140	2.99	%	185		2.41	%
2013 Term Loan Facility due 2022	500	3.02	%	500		2.33	%
2015 Term Loan Facility due 2020	170	2.91	%	170		2.22	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%(a)	350		4.65	%(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%(a)	350		4.375	%(a)
3.90% Unsecured Senior Notes due 2027	500	3.90	%(a)	500		3.90	%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%(a)	100		5.29	%(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%(a)	150		5.69	%(a)
Unsecured Term Loan Facility due 2019	35	2.71	%	55		2.02	%
PNGTS
Revolving Credit Facility due 2023	—	—		—		—
5.90% Senior Secured Notes due 2018	—	—		30	(b)	5.90	%(a)
Tuscarora
Unsecured Term Loan due 2020	25	2.87	%	25		2.27	%
	2,320			2,415
Less: unamortized debt issuance costs and debt discount	12			12
Less: current portion	36			51	(b)
	2,272			2,352


		Weighted Average				Weighted Average
		Interest Rate for the				Interest Rate for the
(unaudited)		Six Months Ended			December 31,	Year Ended
(millions of dollars)	June 30, 2019	June 30, 2019			2018	December 31, 2018
TC PipeLines, LP
Senior Credit Facility due 2021	—	3.61	%		40	3.14	%
2013 Term Loan Facility due 2022	450	3.73	%		500	3.23	%
4.65% Unsecured Senior Notes due 2021	350	4.65	%	^(a)	350	4.65	%	^(a)
4.375% Unsecured Senior Notes due 2025	350	4.375	%	^(a)	350	4.375	%	^(a)
3.90 % Unsecured Senior Notes due 2027	500	3.90	%	^(a)	500	3.90	%	^(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	5.29	%	^(a)	100	5.29	%	^(a)
5.69% Unsecured Senior Notes due 2035	150	5.69	%	^(a)	150	5.69	%	^(a)
Unsecured Term Loan Facility due 2019	—	—			35	2.93	%
PNGTS
Revolving Credit Facility due 2023	29	3.74	%		19	3.55	%
Tuscarora
Unsecured Term Loan due 2020	24	3.62	%		24	3.10	%
North Baja
Unsecured Term Loan due 2021	50	3.56	%		50	3.54	%
	2,003				2,118
Less: unamortized debt issuance costs and debt discount	10				10
Less: current portion	101				36
	1,892				2,072

(unaudited)
(millions of dollars)

2018		1
2019		36
2020		293
2021		490
2022		500
Thereafter		1,000
		2,320


(unaudited)
(millions of dollars)		Principal Payments
2019		1
2020		123
2021		400
2022		450
2023		29
Thereafter		1,000
		2,003


(unaudited)	Three months ended June 30,				Six months ended June 30,
(millions of dollars, except per common unit amounts)	2019		2018		2019		2018

Net income attributable to controlling interests		55		73		148		169
Net income attributable to the General Partner		(1)		(1)		(3)		(3)
Net income attributable to common units		54		72		145		166
Weighted average common units outstanding (millions) – basic and diluted		71.3		71.3		71.3		71.2
Net income per common unit – basic and diluted	$	0.75	$	1.00	$	2.03	$	2.33

	Three months ended								Six months ended
(unaudited)	June 30,				$		%		June 30,				$		%
(millions of dollars)	2018		2017		Change (a)		Change(a)		2018		2017		Change(a)		Change(a)

Transmission revenues	111		101		10		10		226		213		13		6
Equity earnings	36		24		12		50		95		60		35		58
Operating, maintenance and administrative	(25	)	(26	)	1		4		(49	)	(49	)	—		—
Depreciation	(24	)	(25	)	1		4		(48	)	(49	)	1		2
Financial charges and other	(23	)	(19	)	(4	)	(21	)	(46	)	(36	)	(10	)	(28	)
Net income before taxes	75		55		20		36		178		139		39		28
State income taxes	—		—		—		—		(1	)	(1	)	—		—
Net income	75		55		20				177		138		39
Net income attributable to non-controlling interests	2		—		2		—		8		6		2		(33	)
Net income attributable to controlling interests	73		55		18		33		169		132		37		28

	Payments Due by Period
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Six Months Ended June 30, 2018

								Payments Due by Period
													Weighted Average
													Interest Rate for
													the Six Months
(unaudited)									Less than	1‑3	4‑5	More than 5	Ended June 30,
(millions of dollars)								Total	1 Year	Years	Years	Years	2019
TC PipeLines, LP
Senior Credit Facility due 2021	140	—	—	140	—	2.99	%	—	—	—	—	—	3.61 %
2013 Term Loan Facility due 2022	500	—	—	500	—	3.02	%	450	—	—	450	—	3.73 %
2015 Term Loan Facility due 2020	170	—	170	—	—	2.91	%
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	3.9%^(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	35	35	—	—	—	2.71	%
PNGTS
Revolving Credit Facility due 2023		—	—	—		—		29	—	—	29	—	3.74%
North Baja
Unsecured Term Loan due 2021								50	—	50	—	—	3.56%
Tuscarora
Unsecured Term Loan due 2020	25	1	24	—	—	2.87	%	24	1	23	—	—	3.62%
	2,320	36	644	640	1,000
Partnership (TC PipeLines, LP and its subsidiaries)
Interest on Debt Obligations^(b)								488	89	145	93	161
Operating Leases								1	—	1	—	—
Right of Way commitments								4	1	—	1	2
								2,496	191	569	573	1,163

	Payments Due by Period (a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Six Months Ended June 30, 2018

								Payments Due by Period ^(a)
													Weighted Average
													Interest Rate for the
(unaudited)									Less than	1‑3	4‑5	More than 5	Six Months Ended
(millions of dollars)								Total	1 Year	Years	Years	Years	June 30, 2019
$200 million Credit Agreement due 2020	15	—	15	—	—	2.94	%	115	—	115	—	—	3.70%
7.50% Senior Notes due 2021	250	—	—	250	—	7.50	%(b)	250	—	250	—	—	7.50%^(b)
	265	—	15	250	—
Interest payments on debt ^(c)								44	11	33	—	—
Right of way commitments								47	2	5	5	35
								456	13	403	5	35

~~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).
~~3.1.1~~		Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated December 13, 2017 (incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed December 15, 2017).
~~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~~S1 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 8K filed January 2, 2019).
4.1		Indenture, dated as of June 17, 2011, between the Partnership and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to TC PipeLines, ~~LP’s~~LP's Form ~~8-K~~8K 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~~LP's Form ~~8-K~~8K 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~~LP's Form ~~8-K~~8K 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~~LP's Form ~~8-K~~8K 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 ~~8-K~~8K filed March 13, 2015).
4.6		Third Supplemental Indenture, dated as of May 25, 2017, relating to the issuance of $500,000,000 aggregate principal amount of 3.900% Senior Notes due 2027 (Incorporated by reference from Exhibit 4.2 to TC PipeLines, ~~LP’s~~LP's Form ~~8-K~~8K filed May 25, 2017).
~~4.7~~		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).
~~4.8~~		~~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).~~
~~4.9~~		~~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).~~

~~4.10~~		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).
~~4.10.1~~		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).
~~4.11~~		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).
~~4.11.1~~		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 4.5.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
10.1*		~~Transportation Service Agreement FT19214 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 16, 2018.~~
10.2*		~~Transportation Service Agreement FT19215 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date April 16, 2018.~~
10.3*		~~Amended Precedent Agreement by and between Portland Natural Gas Transmission System and TransCanada PipeLines Limited~~
10.4*		~~Amended Financial Assurances Agreement by and between Portland Natural Gas Transmission System and TransCanada PipeLines Limited~~
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.

~~101.INS~~101		~~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.~~The following materials from TC Pipelines, LP's Quarterly Report on Form 10-Q for the period ended June 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).


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

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

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