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tcp-20200930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2020

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

For the transition period from to

Commission File Number: 001-35358

TC PipeLines, LP

(Exact name of registrant as specified in its charter)


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


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

877-290-2772

(Registrant’s telephone number, including area code)

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

Yes ý 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 every Interactive Data File required to be submitted 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 such files).

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

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 ☐ No ý

As of November 5, 2020, there were 71,306,396 of the registrant’s common units outstanding.

TC PIPELINES, LP

TABLE OF CONTENTS


		Page No.

PART I	FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (Unaudited)	7
	Condensed Notes to Consolidated Financial Statements	12
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	47

PART II	OTHER INFORMATION

Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	49
Item 6.	Exhibits	51
	Signatures	52

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

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
AFUDC			Allowance for funds used during construction
ANR			ANR Pipeline Company
ASC			Accounting Standards Codification
AOCI			Accumulated other comprehensive income
Bison			Bison Pipeline LLC
Class B Distribution			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 (ii) 25 percent of distributions above $20 million thereafter
Class B Reduction			Approximately 35 percent reduction applied to the estimated annual Class B Distribution beginning in 2018, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit
COVID-19			Coronavirus 2019
DOT			U.S. Department of Transportation
EBITDA			Earnings Before Interest, Tax, Depreciation and Amortization
EPA			U.S. Environmental Protection Agency
ExC Project			Iroquois Enhancement by Compression project that involves upgrading its compressor stations along the pipeline and provides approximately 125,000 Dth/day of additional firm transportation service to meet current and future gas supply needs of utility customers
FASB			Financial Accounting Standards Board
FERC			Federal Energy Regulatory Commission
GAAP			U.S. generally accepted accounting principles
General Partner			TC PipeLines GP, Inc.
Great Lakes			Great Lakes Gas Transmission Limited Partnership
GTN			Gas Transmission Northwest LLC
GTN XPress			GTN’s project to both increase the reliability of existing transportation service on GTN and to provide for 250,000 Dth/day of incremental transportation volumes, primarily through facility replacements and additions of existing brownfield compression sites.
IDRs			Incentive Distribution Rights
Iroquois			Iroquois Gas Transmission System, L.P.
LIBOR			London Interbank Offered Rate
LNG			Liquified natural gas
MLP			Master Limited Partnership
North Baja			North Baja Pipeline, LLC
Northern Border			Northern Border Pipeline Company
NYMEX			New York Mercantile Exchange
Our pipeline systems			Our ownership interests in GTN, Northern Border, Bison, Great Lakes, North Baja, Tuscarora, PNGTS and Iroquois
Partnership			TC PipeLines, LP including its subsidiaries, as applicable


Partnership Agreement			Fourth Amended and Restated Agreement of Limited Partnership of the Partnership
PHMSA			The Pipeline and Hazardous Materials Safety Administration
PNGTS			Portland Natural Gas Transmission System
PXP			Portland XPress Project
SEC			Securities and Exchange Commission
Senior Credit Facility			TC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated September 29, 2017
TC Energy			TC Energy Corporation
TC Energy Proposal			TC Energy's non-binding offer to the Partnership to acquire all outstanding common units of the Partnership not beneficially owned by TC Energy via stock exchange whereby the Partnership's common unitholders would receive 0.65 common shares of TC Energy for each issued and outstanding publicly-held Partnership common unit.
Tuscarora			Tuscarora Gas Transmission Company
Tuscarora XPress			Tuscarora's Expansion project to transport additional 15,000 Dth/Day of natural gas supplies through additional compression capability at Tuscarora's existing facility
U.S.			United States of America

WCSB			Western Canadian Sedimentary Basin
Westbrook XPress			Westbrook XPress Project of PNGTS that is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility
Wholly-owned subsidiaries			GTN, Bison, North Baja, and Tuscarora
WHO			World Health Organization

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

PART I

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

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

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

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

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

▪demand for natural gas;

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

▪natural gas prices and regional differences;

▪weather conditions;

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

▪competition from other pipeline systems;

▪natural gas storage levels;

▪rates and terms of service;

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

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

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

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

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

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

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

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

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

•the impact of any impairment charges;

•changes in political environment;

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

•the overall change 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;

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

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

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

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

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

•the impact of TC Energy's proposed acquisition of all the Partnership's outstanding common units not beneficially owned by TC Energy; and

•the negotiation and execution, and the terms and conditions, of a definitive agreement relating to TC Energy’s offer to acquire the Partnership’s outstanding common units and the timing and ability of TC Energy or the Partnership to enter into or consummate such agreement.

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

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF INCOME


	Three months ended		Nine months ended
(unaudited)	September 30,		September 30,
(millions of dollars, except per common unit amounts)	2020	2019	2020	2019
Transmission revenues	99	93	295	299
Equity earnings (Note 5)	39	31	123	115
Operation and maintenance expenses	(16)	(18)	(48)	(51)
Property taxes	(7)	(6)	(20)	(19)
General and administrative	(1)	(2)	(4)	(6)
Depreciation and amortization	(29)	(19)	(68)	(58)
Financial charges and other (Note 15)	(17)	(20)	(54)	(63)
Net income before taxes	68	59	224	217
Income taxes	—	—	(1)	(1)
Net income	68	59	223	216
Net income attributable to non-controlling interest	3	3	13	12
Net income attributable to controlling interests	65	56	210	204
Net income attributable to controlling interest allocation (Note 9)
Common units	64	54	206	199
General Partner	1	1	4	4
Class B units	—	1	—	1
	65	56	210	204

Net income per common unit (Note 9) — basic and diluted	$0.90	$0.76	$2.89	$2.79
Weighted average common units outstanding — basic and diluted (millions)	71.3	71.3	71.3	71.3
Common units outstanding, end of period (millions)	71.3	71.3	71.3	71.3

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

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three months ended		Nine months ended
(unaudited)	September 30,		September 30,
(millions of dollars)	2020	2019	2020	2019
Net income	68	59	223	216
Other comprehensive income
Change in fair value of cash flow hedges (Note 13)	—	(1)	(15)	(15)

Reclassification to net income of (gains) and losses on cash flow hedges (Note 13)	2	(2)	4	(1)
Comprehensive income	70	56	212	200
Comprehensive income attributable to non-controlling interests	3	3	13	12
Comprehensive income attributable to controlling interests	67	53	199	188

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

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS


(unaudited)
(millions of dollars)	September 30, 2020	December 31, 2019
ASSETS
Current Assets
Cash and cash equivalents	253	83
Accounts receivable and other (Note 14)	34	43
Distribution receivable from Iroquois	—	14
Inventories	10	10
Other	3	6
	300	156
Equity investments (Note 5)	1,051	1,098
Property, plant and equipment (Net of $1,233 accumulated depreciation; 2019 - $1,187)	1,702	1,528
Goodwill	71	71

TOTAL ASSETS	3,124	2,853

LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	75	28
Accounts payable to affiliates (Note 12)	32	8
Accrued interest	19	11
Current portion of long-term debt (Note 7)	373	123
	499	170
Long-term debt, net (Note 7)	1,767	1,880
Deferred state income taxes	6	7
Other liabilities	48	36
	2,320	2,093
Partners’ Equity
Common units	611	544
Class B units (Note 8)	95	103
General partner	15	14
Accumulated other comprehensive income (loss) (AOCI)	(16)	(5)
Controlling interests	705	656
Non-controlling interests	99	104
	804	760
TOTAL LIABILITIES AND PARTNERS’ EQUITY	3,124	2,853

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

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CASH FLOWS


	Nine months ended
(unaudited)	September 30,
(millions of dollars)	2020	2019
Cash Generated from Operations
Net income	223	216
Depreciation and amortization	68	58
Amortization of debt issue costs reported as interest expense	1	1

Equity earnings from equity investments (Note 5)	(123)	(115)
Distributions received from operating activities of equity investments (Note 5)	161	168
Equity allowance for funds used during construction (AFUDC Equity)	(6)	(1)
Change in operating working capital (Note 11)	17	16
Other	(2)	1
	339	344
Investing Activities
Investment in Great Lakes (Note 5)	(5)	(5)
Investment in Iroquois (Note 5)	—	(4)
Distribution received from Iroquois as return of investment (Note 5)	29	8
Distribution received from Northern Border as return of investment (Note 5)	—	50
Capital expenditures	(159)	(48)
Customer advances for construction	(1)	—
	(136)	1
Financing Activities
Distributions paid to common units, including the General Partner (Note 10)	(142)	(142)
Distributions paid to Class B units (Note 8)	(8)	(13)
Distributions paid to non-controlling interests	(18)	(18)

Long-term debt issued, net of discount (Note 7)	235	21
Long-term debt repaid (Note 7)	(100)	(136)

	(33)	(288)
Increase in cash and cash equivalents	170	57
Cash and cash equivalents, beginning of period	83	33
Cash and cash equivalents, end of period	253	90

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

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY


	Limited Partners
	Common Units		Class B Units		General Partner	Accumulated Other Comprehensive Income (Loss) (a)	Non- Controlling Interest	Total Equity
(unaudited)	millions of units	millions of dollars	millions of units	millions of dollars	millions of dollars	millions of dollars	millions of dollars	millions of dollars
Partners’ Equity at December 31, 2019	71.3	544	1.9	103	14	(5)	104	760
Net income	—	206	—	—	4	—	13	223
Other comprehensive income (loss)	—	—	—	—	—	(11)	—	(11)
Distributions	—	(139)	—	(8)	(3)	—	(18)	(168)
Partners’ Equity at September 30, 2020	71.3	611	1.9	95	15	(16)	99	804

(a)Gain (loss) related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months is estimated to be $(8) million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

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

TC PIPELINES, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 ORGANIZATION

TC PipeLines, LP and its subsidiaries are collectively referred to herein as the Partnership. The Partnership was formed by TransCanada PipeLines Limited, a wholly owned subsidiary of TC Energy Corporation (TC Energy Corporation together with its subsidiaries collectively referred to herein as TC Energy), to acquire, own and participate in the management of energy infrastructure assets in North America.

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements and related notes have been prepared in accordance with United States generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The results of operations for the three and nine months ended September 30, 2020 and 2019 are not necessarily indicative of the results that may be expected for the full fiscal year.

The accompanying consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2019 included in our 2019 Annual Report. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying consolidated financial statements contain all of the appropriate adjustments, which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our 2019 Annual Report, except those that became effective in 2020 as described in full under Note 3, "Accounting Pronouncements."

Basis of Presentation

The Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included as non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence.

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

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

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 3 ACCOUNTING PRONOUNCEMENTS

Changes in Accounting Policies effective January 1, 2020

Measurement of credit losses on financial instruments

In June 2016, the Financial Accounting Standards Board (FASB) issued new guidance that changes how entities measure credit losses for most financial assets and certain other financial instruments that are not measured at fair value through net income (loss). The new guidance amends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write down of the amortized cost basis. The new guidance became effective January 1, 2020 and was applied using a modified retrospective approach. The adoption of this new guidance did not have a material impact on the Partnership’s consolidated financial statements.

Consolidation

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

Reference rate reform

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

NOTE 4 GOODWILL

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

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

On March 11, 2020, the World Health Organization (WHO) declared COVID-19 a global pandemic. While there are continuing concerns around the decline in energy demand related to the pandemic, we believe the current state of the macroeconomic environment does not represent a permanent shift. However, it remains difficult to predict with any certainty the severity of the impact of these events or how long any disruptions are likely to continue.

The following additional factors were considered in our first quarter 2020 analysis specific to the Partnership's Tuscarora and North Baja reporting units:

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

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

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

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

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

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

As a result of these factors, we concluded during our first quarter 2020 analysis that there was a greater than 50 percent likelihood that both Tuscarora’s and North Baja’s estimated fair values would continue to exceed their carrying values. Therefore, no impairment exists on our goodwill. While the issues described above persist in the current quarter, we continue to believe these conditions remain temporary and are not aware of any other conditions or triggering events in the third quarter that would require us to change the conclusion reached during the first quarter. Adverse changes to our key considerations could, however, result in future impairments on our goodwill.

NOTE 5 EQUITY INVESTMENTS

The Partnership has equity interests in Northern Border, Great Lakes and Iroquois. The pipeline systems owned by these entities are regulated by the Federal Energy Regulatory Commission (FERC). The Northern Border and Great Lakes pipeline systems are operated by subsidiaries of TC Energy. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees.


	Ownership	Equity Earnings				Equity Investments
	Interest at	Three months ended		Nine months ended
(unaudited)	September 30,	September 30,		September 30,		September 30,	December 31,
(millions of dollars)	2020	2020	2019	2020	2019	2020	2019
Northern Border	50.00%	22	15	57	50	412	422
Great Lakes	46.45%	10	8	39	37	487	491
Iroquois	49.34%	7	8	27	28	152	185
		39	31	123	115	1,051	1,098

Distributions from Equity Investments

Distributions received from equity investments in the three and nine months ended September 30, 2020 totaled $70 million and $190 million, respectively (September 30, 2019 - $59 million and $226 million, respectively).

During the nine months ended September 30, 2020, $29 million of the total $190 million distributions received from equity investments (September 30, 2019 - $58 million) was considered return of capital and included in "Investing Activities" in the Partnership’s consolidated statement of cash flows. The return of capital was related to our investment in Iroquois (see further discussion below).

Northern Border

During the three and nine months ended September 30, 2020, the Partnership received distributions from Northern Border amounting to $22 million and $68 million, respectively (September 30, 2019 - $21 million and $121 million, respectively).

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

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


(unaudited)
(millions of dollars)	September 30, 2020	December 31, 2019
ASSETS
Cash and cash equivalents	40	21
Other current assets	39	37
Property, plant and equipment, net	979	989
Other assets	12	12
	1,070	1,059
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	58	42
Deferred credits and other	40	39
Long-term debt, net (a)	378	364
Partners’ equity
Partners’ capital	594	615
Accumulated other comprehensive loss	—	(1)
	1,070	1,059


	Three months ended		Nine months ended
(unaudited)	September 30,		September 30,
(millions of dollars)	2020	2019	2020	2019
Transmission revenues	83	73	232	221
Operating expenses	(19)	(21)	(58)	(61)
Depreciation	(16)	(15)	(47)	(46)
Financial charges and other	(4)	(5)	(13)	(13)
Net income	44	32	114	101

(a) Includes current maturities of $250 million as of September 30, 2020 for Northern Border's 7.50% Senior Notes (December 31, 2019 - nil), net of unamortized debt issuance costs and debt discounts. At September 30, 2020, Northern Border was in compliance with all of its financial covenants.

Great Lakes, a variable interest entity

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

The Partnership made an equity contribution to Great Lakes of $5 million during the nine months ended September 30, 2020 (September 30, 2019 - $5 million). This amount represents the Partnership’s 46.45 percent share of an $11 million cash call from Great Lakes to make a scheduled debt repayment.

During the three and nine months ended September 30, 2020, the Partnership received distributions from Great Lakes amounting to $11 million and $48 million, respectively (September 30, 2019 - $9 million and $48 million, respectively).

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

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


(unaudited)
(millions of dollars)	September 30, 2020	December 31, 2019
ASSETS
Current assets	27	72
Property, plant and equipment, net	710	685
	737	757
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	31	33
Net long-term debt, including current maturities (a)	208	219
Other long term liabilities	8	6
Partners’ equity	490	499
	737	757


	Three months ended		Nine months ended
(unaudited)	September 30,		September 30,
(millions of dollars)	2020	2019	2020	2019
Transmission revenues	50	51	172	174
Operating expenses	(18)	(23)	(53)	(58)
Depreciation	(8)	(8)	(24)	(24)
Financial charges and other	(4)	(3)	(11)	(12)
Net income	20	17	84	80

(a) Includes current maturities of $31 million as of September 30, 2020 (December 31, 2019 - $21 million). At September 30, 2020, Great Lakes was in compliance with all of its financial covenants.

Iroquois

During the three and nine months ended September 30, 2020, the Partnership received total distributions from Iroquois amounting to $37 million and $74 million, respectively (September 30, 2019 - $28 million and $56 million, respectively), which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately nil and $5.2 million, respectively (September 30, 2019 - $2.6 million and $7.8 million, respectively).

Also included in the $37 million and $74 million is the Partnership's receipt of (a) a $24 million one-time, non-recurring distribution from Iroquois, representing our 49.34 percent of the reimbursement proceeds received by Iroquois from a terminated project that was guaranteed by the customer and (b) an additional $2 million distribution representing our 49.34 percent of the excess cash generated by Iroquois' operating activities in 2020.

The 2020 unrestricted cash of $5.2 million (2019 - $7.8 million) and the $24 million non-recurring distributions do not represent a distribution of Iroquois’ cash from operations during the period and therefore were reported as a return of investment in the Partnership’s consolidated statement of cash flows.

The Partnership did not have undistributed earnings from Iroquois for the three and nine months ended September 30, 2020 and 2019.

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


(unaudited)
(millions of dollars)	September 30, 2020	December 31, 2019
ASSETS
Cash and cash equivalents	26	43
Other current assets	32	36
Property, plant and equipment, net	509	570
Other assets	19	16
	586	665
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	21	34
Long-term debt, net (a)	316	317
Other non-current liabilities	22	20
Partners’ equity	227	294
	586	665


	Three months ended		Nine months ended
(unaudited)	September 30,		September 30,
(millions of dollars)	2020	2019	2020	2019
Transmission revenues	40	39	133	131
Operating expenses	(15)	(15)	(44)	(43)
Depreciation	(7)	(7)	(22)	(22)
Financial charges and other	(3)	(2)	(12)	(9)
Net income	15	15	55	57

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

NOTE 6 REVENUES

Disaggregation of Revenues

For the three and nine months ended September 30, 2020 and 2019, effectively all of the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed in more detail below.

Capacity Arrangements and Transportation Contracts

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

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

The Partnership's pipeline systems are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. As of September 30, 2020, the Partnership does not have any outstanding refund obligations related to any rate proceedings. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.

Contract Balances

All of the Partnership’s contract balances pertain to receivables from contracts with customers amounting to $32 million at September 30, 2020 (December 31, 2019 - $37 million) and are recorded as trade accounts receivable and reported as "Accounts receivable and other" in the Partnership’s consolidated balance sheet (Refer to Note 14, "Accounts Receivable and Other").

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

Right to invoice practical expedient

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

NOTE 7 DEBT AND CREDIT FACILITIES


(unaudited) (millions of dollars)	September 30, 2020	Weighted Average Interest Rate for the Nine Months Ended September 30, 2020		December 31, 2019	Weighted Average Interest Rate for the Year Ended December 31, 2019
TC PipeLines, LP
Senior Credit Facility due 2021	—	—		—	—
2013 Term Loan Facility due 2022	450	2.03%		450	3.52%
4.65% Unsecured Senior Notes due 2021	350	4.65%	(a)	350	4.65%	(a)
4.375% Unsecured Senior Notes due 2025	350	4.375%	(a)	350	4.375%	(a)
3.90% Unsecured Senior Notes due 2027	500	3.90%	(a)	500	3.90%	(a)

GTN
3.12% Series A Senior Notes due 2030	175	3.12%	(a)	—	—
5.29% Unsecured Senior Notes due 2020	—	—	(a)	100	5.29%	(a)
5.69% Unsecured Senior Notes due 2035	150	5.69%	(a)	150	5.69%	(a)


PNGTS
Revolving Credit Facility due 2023	99	2.02%		39	3.47%

Tuscarora
Unsecured Term Loan due 2021	23	2.13%		23	3.39%

North Baja
Unsecured Term Loan due 2021	50	1.85%		50	3.34%
	2,147			2,012
Less: unamortized debt issuance costs and debt discount	7			9
Less: current portion (b)	373			123
	1,767			1,880

(a) Fixed interest rate

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

TC PipeLines, LP

The Partnership’s senior facility under a revolving credit agreement as amended and restated, dated September 29, 2017 (Senior Credit Facility) consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 10, 2021. In March 2019, the Partnership repaid all amounts outstanding under its Senior Credit Facility and there was no outstanding balance at either September 30, 2020 or December 31, 2019.

As of September 30, 2020, the variable interest rate exposure related to the Partnership's term loan facility under a term loan agreement, as amended, dated September 29, 2017 (2013 Term Loan Facility) was hedged using interest rate swaps at an average rate of 3.26 percent (December 31, 2019 - 3.26 percent). Prior to hedging activities, the London Interbank Offered Rate based (LIBOR) interest rate on the 2013 Term Loan Facility was 1.41 percent at September 30, 2020 (December 31, 2019 - 2.94 percent).

The Senior Credit Facility and the 2013 Term Loan Facility require the Partnership to maintain a debt to adjusted cash flow leverage ratio of no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions have been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 3.76 to 1.00 as of September 30, 2020.

GTN

On June 1, 2020, GTN’s $100 million 5.29% Unsecured Senior Notes became due and were refinanced through a Note Purchase and Private Shelf Agreement whereby GTN issued $175 million of 10-year Series A Senior Notes (GTN Series A Notes) with a coupon rate of 3.12% per annum and entered into a 3-year private shelf agreement for an additional $75 million of Senior Notes (GTN Private Shelf Facility). The GTN Series A Notes do not require any principal payments until maturity on June 1, 2030. Proceeds from GTN's Series A Note issuance were used to repay the outstanding balance of the 5.29% Unsecured Senior Notes and the remaining proceeds will be used to fund the GTN XPress capital expenditures for the balance of 2020. GTN expects to draw the remaining $75 million available under the GTN Private Shelf Facility by the end of 2023, the estimated completion date of GTN XPress. The GTN Private Shelf Facility and GTN Series A Notes contain a covenant that limits total debt to no greater than 65 percent and 70 percent of GTN’s total capitalization, respectively. GTN’s total debt to total capitalization ratio at September 30, 2020 was 38.2 percent.

PNGTS

PNGTS’ $125 million Revolving Credit Facility requires PNGTS to maintain a leverage ratio of no greater than 5.00 to 1.00. The leverage ratio was 1.42 to 1.00 as of September 30, 2020. During the nine months ended September 30, 2020, PNGTS borrowed an additional $60 million under its Revolving Credit Facility to fund its expansion projects.

The LIBOR-based interest rate applicable to PNGTS’s Revolving Credit Facility was 1.28 percent at September 30, 2020 (December 31, 2019 - 2.99 percent).

On October 8, 2020, PNGTS entered into a Note Purchase and Private Shelf Agreement whereby PNGTS issued $125 million 10-year Series A Senior Notes (PNGTS Series A Notes) with a coupon rate of 2.84% per annum and entered into a 3 year private shelf agreement for an additional $125 million of Senior Notes (PNGTS Private Shelf Facility). The PNGTS Series A Notes do not require any principal payments until maturity on October 8, 2030. Proceeds from PNGTS' Series A Note issuance were used to repay the outstanding balance of PNGTS' Revolving Credit Facility and for general partnership purposes including funding growth capital. PNGTS expects to draw the remaining $125 million available under the PNGTS Private Shelf Facility by the end of 2021, the estimated completion date of Westbrook XPress project. The PNGTS Private Shelf Facility and PNGTS Series A Notes contains a covenant that limits total debt to no greater than 65 percent of PNGTS’ total capitalization and requires PNGTS to maintain a leverage ratio of no greater than 5.00 to 1.00.

Tuscarora

On July 23, 2020, Tuscarora's $23 million variable rate Unsecured Term Loan (Unsecured Term Loan) was amended to extend the maturity date to August 20, 2021 under generally the same terms. The Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by the sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of September 30, 2020, the ratio was 28.18 to 1.00.

The LIBOR-based interest rate applicable to Tuscarora’s Unsecured Term Loan was 2.16 percent at September 30, 2020 (December 31, 2019 - 2.82 percent).

North Baja

North Baja’s $50 million Term Loan Facility contains a covenant that limits total debt to no greater than 70 percent of North Baja’s total capitalization. North Baja’s total debt to total capitalization ratio at September 30, 2020 was 40.82 percent.

The LIBOR-based interest rate applicable to North Baja’s Term Loan Facility was 1.23 percent at September 30, 2020 (December 31, 2019 - 2.77 percent).

Partnership

At September 30, 2020, the Partnership was in compliance with all debt and credit facility terms and conditions including its financial covenants and its other covenants including restrictions on entering into mergers, consolidations and sales of assets, granting of liens, material amendments to the Fourth Amended and Restated Agreement of Limited Partnership, as amended to date (Partnership Agreement), incurring additional debt and distributions to unitholders.

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


(unaudited)
(millions of dollars)			Principal Payments
2020			—
2021			423
2022			450
2023			99
2024			—
Thereafter			1,175
			2,147

NOTE 8 PARTNERS’ EQUITY

Class B units issued to TC Energy

The Class B units entitle TC Energy to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020 and (ii) 25 percent of distributions above $20 million thereafter, which equates to 43.75 percent of distributions above $20 million for the year ending December 31, 2020 (Class B Distribution). Additionally, the Class B Distribution will be further reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018 (Class B Reduction). The Class B Reduction was implemented during the first quarter of 2018 following the Partnership’s common unit distribution reduction of 35 percent. The Class B Reduction will continue to apply to any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit.

For the year ending December 31, 2020, the Class B units’ equity account will be increased by the Class B Distribution, less the Class B Reduction, until such amount is declared for distribution and paid in the first quarter of 2021. During the nine months ended September 30, 2020, the 2020 annual Class B Distribution threshold was not exceeded.

For the year ended December 31, 2019, the Class B Distribution was $8 million and was declared and paid in the first quarter of 2020.

NOTE 9 NET INCOME PER COMMON UNIT

Net income per common unit is computed by dividing net income attributable to controlling interests, after deduction of amounts attributable to TC PipeLines GP, Inc. (General Partner) and Class B units, by the weighted average number of common units outstanding.

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

The amount allocable to the Class B units in 2020 will equal 30 percent of GTN’s distributable cash flow during the year ending December 31, 2020 less $20 million, the residual of which is further multiplied by 43.75 percent. This amount is further reduced by the estimated Class B Reduction for 2020, an approximately 35 percent reduction applied to the estimated annual Class B Distribution (December 31, 2019 - $20 million less Class B Reduction). During the three and nine months ended September 30, 2020 and 2019, no amounts were allocated to the Class B units as the annual threshold was not exceeded.

Net income per common unit was determined as follows:


(unaudited)	Three months ended September 30,		Nine months ended September 30,
(millions of dollars, except per common unit amounts)	2020	2019	2020	2019
Net income attributable to controlling interests	65	56	210	204
Net income attributable to the Class B units	—	(1)	—	(1)
Net income attributable to the General Partner and common units	65	55	210	203
Net income attributable to the General Partner	(1)	(1)	(4)	(4)
Net income attributable to common units	64	54	206	199
Weighted average common units outstanding (millions) — basic and diluted	71.3	71.3	71.3	71.3
Net income per common unit — basic and diluted	$0.90	$0.76	$2.89	$2.79

NOTE 10 CASH DISTRIBUTIONS PAID TO COMMON UNITS

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

distribution paid includes our General Partner's share for its two percent general partner interest for both the three and nine months ended September 30, 2020 and 2019 totaling $1 million and $3 million, respectively. The General Partner did not receive any distributions in respect of its Incentive Distribution Rights (IDRs) in either of the three or nine months ended September 30, 2020 and 2019.

NOTE 11 CHANGE IN OPERATING WORKING CAPITAL


(unaudited)	Nine months ended September 30,
(millions of dollars)	2020	2019
Change in accounts receivable and other (a)	5	16
Change in inventories	—	(1)
Change in other current assets	3	4
Change in accounts payable and accrued liabilities (a)	3	(11)
Change in accounts payable to affiliates (a)	(2)	—
Change in accrued interest	8	8
Change in operating working capital	17	16

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

NOTE 12 RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to conduct the business of, and allocable to the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. For both the three and nine months ended September 30, 2020 and 2019, total costs charged to the Partnership by the General Partner were $1 million and $3 million, respectively.

As operator of our pipelines, except Iroquois and a certain portion of the PNGTS facilities, TC Energy’s subsidiaries provide capital and operating services to our pipeline systems. TC Energy’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. Iroquois does not receive any capital and operating services from TC Energy (Refer to Note 5, "Equity Investments").

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


	Three months ended		Nine months ended
(unaudited)	September 30,		September 30,
(millions of dollars)	2020	2019	2020	2019
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes (a)	35	12	57	35
Northern Border (a)	9	10	29	29
GTN	33	11	57	32
Bison	—	1	1	2
North Baja	4	1	6	4
Tuscarora	3	1	5	3
PNGTS (a)	1	2	4	5
Impact on the Partnership’s income (b):
Great Lakes	4	4	13	14
Northern Border	4	4	12	13
GTN	7	9	22	25
Bison	—	—	1	1
North Baja	1	1	3	3
Tuscarora	—	1	2	3
PNGTS	—	1	2	3


(unaudited)
(millions of dollars)	September 30, 2020	December 31, 2019
Net amounts payable to TC Energy’s subsidiaries are as follows:
Great Lakes (a)	4	5
Northern Border (a)	3	4
GTN (c)	30	5
Bison	—	—
North Baja	—	1
Tuscarora	—	—
PNGTS (a)	1	1

(a)Represents 100 percent of the costs.

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

(c)Includes obligations related to commercial system purchase described below. The purchase price was paid in October 2020.

Great Lakes

Great Lakes earns significant transportation revenues from TC Energy and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For both the three and nine months ended September 30, 2020, Great Lakes earned 74 percent of its transportation revenues from TC Energy and its affiliates (September 30, 2019 - 73 percent for both periods).

At September 30, 2020, $12 million was included in Great Lakes’ receivables with regard to the transportation contracts with TC Energy and its affiliates (December 31, 2019 - $19 million).

In 2018, Great Lakes executed long-term transportation capacity contracts with its affiliate, ANR Pipeline Company (ANR) in anticipation of specific possible future needs. The original total contract value of these contracts was approximately $1.3 billion over a 15-year period. These contracts were subject to certain conditions and provisions, including a reduction option up to the full contract quantity if exercised up to a certain date. During the first quarter of 2020, several amendments were made to these contracts and ANR exercised the right to terminate a significant portion of the contracts amounting to approximately $1.1 billion. The remaining maximum rate contract, which has a total capacity of approximately 168,000 Dth/Day and total contract value of $182 million over a term of 20 years, is expected to begin in late 2022. This contract, which has a full quantity reduction option at any time before October 1, 2022, is dependent on ANR being able to secure the required regulatory approvals and other requirements of the project associated with these volumes. Any remaining unsubscribed capacity on Great Lakes will be available for contracting in response to developing marketing conditions.

PNGTS

In connection with the Portland XPress expansion project (PXP), which was designed to be phased in over a three-year time period, PNGTS has entered into an arrangement with affiliates regarding the construction of certain facilities on their systems that are required to fulfill future contracts on the PNGTS system. In the event the expansions are terminated prior to their in-service dates, PNGTS would be required to reimburse its affiliates for any costs incurred related to the development of their facilities. On November 1, 2020, the last phase of PXP (Phase III) was commercially placed in service. As a result of placing the TC Energy facilities associated with the Phases I, II and III volumes in service, PNGTS' reimbursement obligation to TC Energy relating to this project has been extinguished.

Commercial System Purchase

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

NOTE 13 FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

Under Accounting Standards Codification (ASC) 820, Fair Value Measurements and Disclosures, 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.

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

(b) Fair Value of Financial Instruments

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

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

Long-term debt is recorded at amortized cost and classified as Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified as Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership’s debt as at September 30, 2020 and December 31, 2019 was $2,257 million and $2,111 million, respectively.

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

The Partnership’s interest rate swaps mature on October 2, 2022. The interest rate swaps were structured such that the cash flows of the derivative instruments match the variable rate of interest on the 2013 Term Loan Facility. The fixed weighted average interest rate on these instruments is 3.26 percent.

At September 30, 2020, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $17 million (both on a gross and net basis) (December 31, 2019 - liability of $6 million), the net change of which is recognized in other comprehensive income. For both the three and nine months ended September 30, 2020, the net realized loss related to the interest rate swaps was $2 million and $4 million and was included in "financial charges and other" (September 30, 2019 - gain of nil and gain of $1 million, respectively) (Refer to Note 15, "Financial Charges and Other').

The Partnership has no master netting agreements; however, it has derivative contracts containing provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the consolidated balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of September 30, 2020 and December 31, 2019.

NOTE 14 ACCOUNTS RECEIVABLE AND OTHER


(unaudited)
(millions of dollars)	September 30, 2020	December 31, 2019
Trade accounts receivable, net of allowance of nil	32	37
Imbalance receivable from affiliates	1	—
Other	1	6
	34	43

NOTE 15 FINANCIAL CHARGES AND OTHER


	Three months ended		Nine months ended
(unaudited)	September 30,		September 30,
(millions of dollars)	2020	2019	2020	2019
Interest expense (a)	19	22	59	67
Net realized loss (gain) related to the interest rate swaps	2	—	4	(1)
AFUDC - Equity	(3)	—	(6)	(1)
Other income	(1)	(2)	(3)	(2)
	17	20	54	63

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

NOTE 16 SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through November 9, 2020, the date the consolidated financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

Distributions

On October 21, 2020, the board of directors of the General Partner (TC PipeLines Board) declared the Partnership’s third quarter 2020 cash distribution in the amount of $0.65 per common unit payable on November 13, 2020 to unitholders of record as of November 2, 2020. The declared distribution totaled $47 million and is payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to the General Partner for its two percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the third quarter of 2020.

Northern Border declared its September 2020 distribution of $18 million on October 9 2020, of which the Partnership received its 50 percent share or $9 million on October 30, 2020.

Iroquois declared its third quarter 2020 distribution of $21 million on November 2, 2020, of which the Partnership will receive its 49.34 percent share or $10 million on December 23, 2020.

PNGTS declared its third quarter 2020 distribution of $14 million on October 26, 2020, of which $5 million was paid to its non-controlling interest owner on October 30, 2020.

Great Lakes' Contract with TC Energy's Canadian Mainline

As noted in our 2019 Annual Report, a significant portion of Great Lakes’ total contract portfolio is contracted by its affiliates including its long-term transportation agreement with TC Energy’s Canadian Mainline that commenced on November 1, 2017 for a ten-year period that allows TC Energy to transport up to 0.711 billion cubic feet (equivalent to about 722,000 Dth/day) of natural gas per day on the Great Lakes system. This contract contained a volume reduction option up to full contract quantity until November 1, 2020. During the quarter, the Canadian Mainline requested an extension on the volume reduction option deadline and Great Lakes extended the option expiry to November 16, 2020.

TC Energy's offer to acquire the Partnership's publicly-held outstanding common units:

On October 5, 2020, the Partnership announced receipt of a non-binding offer from TC Energy to acquire all of its outstanding common units not beneficially owned by TC Energy or its affiliates in exchange for common shares of TC Energy. Under the proposal, the Partnership's common unitholders would receive 0.65 common shares of TC Energy for each issued and outstanding publicly-held Partnership common unit (TCP common unit), representing an implied value of $27.31 per TCP common unit based on the closing price of TC Energy common shares on the New York Stock Exchange (NYSE) on October 2, 2020 (TC Energy Proposal). This reflects a 7.5 percent premium to the exchange ratio implied by the 20-day volume weighted average prices of the Partnership's common units and TC Energy’s common shares on the NYSE as of October 2, 2020.

The offer has been made to the TC PipeLines Board. As the general partner of the Partnership is an indirect wholly-owned subsidiary of TC Energy, a conflicts committee composed of independent directors of the TC PipeLines Board (the Conflicts Committee) was formed to consider the offer pursuant to the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership (Partnership Agreement).

The transaction is subject to the review and favorable recommendation by the Conflicts Committee of the TC PipeLines Board and approvals by the TC PipeLines Board, the Board of Directors of TC Energy, and the holders of a majority of the outstanding common units of the Partnership. It is also subject to the negotiation and execution of an agreement and plan of merger, which would provide the definitive terms of the transaction, including the exchange ratio, and customary regulatory approvals. Any definitive agreement is expected to contain customary closing conditions. There can be no assurance that any such approvals will be forthcoming, that a definitive agreement will be executed or that any transaction will be consummated.

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

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

RECENT BUSINESS DEVELOPMENTS

COVID-19

On March 11, 2020, the WHO declared COVID-19, a global pandemic. As primary operator of our pipelines, TC Energy’s business continuity plans remain in place across the organization and TC Energy continues to effectively operate our assets, conduct commercial activities and execute on projects with a focus on health, safety and reliability. Our business is broadly considered essential in the United States given the important role our infrastructure plays in providing energy to North American markets. We believe that TC Energy’s robust continuity and business resumption plans for critical teams including gas control and commercial and field operations, will continue to ensure the safe and reliable delivery of energy that our customers depend upon.

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

Capital market conditions in 2020 have been significantly impacted by COVID-19 resulting in periods of extreme volatility and reduced liquidity. Despite these challenges, our liquidity remains strong, underpinned by stable cashflow from operations, cash on hand and full access to our $500 million Senior Credit Facility. During the second quarter of 2020, GTN's $100 million Senior Notes due in June 2020 were refinanced through a Note Purchase Agreement whereby GTN issued $175 million of 10-year Series A Senior Notes with a coupon rate of 3.12% with the incremental $75 million of proceeds to be used to fund the GTN XPress project through the balance of 2020. Additionally, GTN entered into a 3-year private shelf agreement for an additional $75 million which will be used to finance a portion of the GTN XPress project into 2023. During the fourth quarter of 2020, PNGTS entered into a Note Purchase Agreement whereby PNGTS issued $125 million 10-year Series A Senior Notes with a coupon rate of 2.84%, the proceeds of which were primarily used to repay the outstanding balance of PNGTS' Revolving Credit Facility. The remaining proceeds were used for general partnership purposes, including the funding of PXP and Westbrook XPress. PNGTS also entered into a 3-year private shelf agreement for an additional $125 million which will be used to finance the remaining capital spending required for Westbrook XPress into 2021. Additionally, on July 23, 2020, Tuscarora's $23 million Unsecured Term Loan due in August 2020 was extended for one year to August 2021 under generally the same terms. These recently concluded transactions demonstrate our continued access to the debt capital markets at attractive levels. We continue to conservatively manage our financial position, self-fund our ongoing capital expenditures and maintain our debt at prudent levels and we believe we are well positioned to fund our obligations through a prolonged period of disruption, should it occur. Based on current expectations, we believe our business will continue to deliver consistent financial performance going forward and support our current quarterly distribution level of $0.65 per common unit.

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

Impairment considerations:

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

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

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

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

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

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

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

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

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

TC Energy's offer to acquire the Partnership's outstanding publicly-held common units:

On October 5, 2020, the Partnership announced a non-binding offer from TC Energy to acquire all of its outstanding common units not beneficially owned by TC Energy or its affiliates in exchange for common shares of TC Energy. Under the proposal, the Partnership's common unitholders would receive 0.65 common shares of TC Energy for each issued and outstanding publicly-held Partnership common unit, representing an implied value of $27.31 per TCP common unit based on the closing price of TC Energy common shares on the NYSE on October 2, 2020. This reflects a 7.5 percent premium to the exchange ratio implied by the 20-day volume weighted average prices of the Partnership's common units and TC Energy’s common shares on the NYSE as of October 2, 2020.

The offer has been made to the TC PipeLines Board. As the general partner of the Partnership is an indirect wholly-owned subsidiary of TC Energy, a conflicts committee composed of independent directors of the TC PipeLines Board was formed to consider the offer pursuant to the Partnership Agreement.

The transaction is subject to the review and favorable recommendation by the Conflicts Committee of the TC PipeLines Board and approvals by the TC PipeLines Board, the board of directors of TC Energy, and the holders of a majority of the outstanding common units of the Partnership. It is also subject to the negotiation and execution of an agreement and plan of merger, which would provide the definitive terms of the transaction, including the exchange ratio, and customary regulatory approvals. Any definitive agreement is expected to contain customary closing conditions. There can be no assurance that any such approvals will be forthcoming, that a definitive agreement will be executed or that any transaction will be consummated.

Other notable business developments:

PNGTS’ Portland XPress Project - Our Portland XPress Project or “PXP” was initiated in 2017 in order to expand deliverability on the PNGTS system to Dracut, Massachusetts through re-contracting and construction of incremental compression within PNGTS’ existing footprint in Maine. PXP was designed to be phased in over a three-year time period. Phases I and II were placed into service on November 1, 2018 and 2019 respectively. On November 1, 2020, the last phase of PXP (Phase III) was commercially placed in service. All phases of the project are now fully in-service.

Beginning in 2021, PXP is expected to generate approximately $50 million in annual revenue for PNGTS. PXP is secured by long-term transportation agreements and PNGTS is now effectively fully contracted until 2032.

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

ANR's Alberta XPress project - On February 12, 2020, TC Energy approved the Alberta XPress project, an expansion project on its ANR Pipeline system with an estimated in-service date of 2022. This project utilizes existing capacity on the Great Lakes system (of which we own 46.45 percent) and TC Energy’s Canadian Mainline systems to connect growing natural gas supply from the Western Canadian Sedimentary Basin (WCSB) to U.S. Gulf Coast Liquified Natural Gas (LNG) export markets. In 2018, Great Lakes entered into long-term transportation capacity contracts with ANR for approximately 900,000 Dth/day of aggregate capacity for a term of 15 years. In connection with the approval of the Alberta XPress project, such contracts have been reduced to provide for approximately 168,000 Dth/day of aggregate capacity for a term of 20 years at maximum rates for a total contract value of $182 million starting in 2022. The contract contains reduction options (i) at any time on or before October 1, 2022 for any reason and (ii) at any time, if ANR is not able to secure the required regulatory approval related to its anticipated expansion projects. Please read Note 12 within Item 1. “Financial Statements” for information regarding Great Lakes and ANR.

Iroquois Gas Transmission ExC Project (Iroquois ExC Project) - In 2019, Iroquois initiated the “Enhancement by Compression” project (ExC Project) which will optimize the Iroquois system to meet current and future gas supply needs of utility customers while minimizing the environmental impact through enhancements at existing compressor stations along the pipeline. In February 2020, Iroquois filed an application with FERC to authorize the construction of the project. On September 30, 2020, FERC issued its Environmental Assessment (EA) for the Iroquois ExC Project. The EA concluded that approval of the project, with appropriate mitigating measures, would not constitute a major federal action significantly affecting the quality of the human environment. The project’s total design capacity is approximately 125,000 Dth/day with an estimated cost of $250 million and in-service date of November 2023. This project will be 100 percent underpinned with 20-year contracts.

Northern Border complaint - On March 31, 2020, BP Canada Energy Marketing Corp., Oasis Petroleum Marketing LLC and Tenaska Marketing Ventures (the “Alliance for Open Markets”) filed a complaint with FERC (Docket No. RP20-745-000) against Northern Border Pipeline Company alleging that Northern Border violated Sections 4 and 5 of the Natural Gas Act, FERC policy and other regulations by (i) failing to post capacity as available on a long-term basis before entering into a prearranged transaction for six agreements with ONEOK Rockies Midstream, L.L.C.; (ONEOK Midstream) and (ii) structuring the prearranged transaction open season in a manner that denied other shippers a meaningful opportunity to bid on the capacity. On April 2, 2020, ConocoPhillips Company, Shell Energy North America (US), L.P. and XTO Energy Inc. (the “Indicated Shippers”, together with the Alliance for Open Markets, the “Complainants”) filed a second complaint with FERC (Docket No. RP20-767-000) against Northern Border containing similar allegations regarding the prearranged transaction open season. The Complainants have requested that FERC (a) unwind the six prearranged contracts; (b) require Northern Border to hold an open season for the capacity such that all interested parties are on equal footing; and (c) direct Northern Border to cease from engaging in prearranged transactions where the unsubscribed capacity has not been publicly posted as generally available.

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

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

On October 15, 2020, FERC issued an order on the complaints and directed Northern Border to (1) refrain from making similar, discriminatory awards of capacity in the future, (2) rescind the pre-arranged deals with ONEOK Midstream, effective October 15, 2020, and (3) hold a new open season without a pre-arranged shipper. In addition, FERC directed Northern Border to file revisions to its tariff requiring it to post capacity on its website before entering a pre-arranged deal.

FERC did not order Northern Border to refund any of the revenue earned from the pre-arranged transactions with ONEOK Midstream.

Northern Border held an open season from October 21 to 28, 2020 to remarket the capacity. Final bids were evaluated and the successful bids will reflect a revenue that approximates Northern Border’s maximum recourse rates, which reflects a reduction from the pre-arranged contract rate.

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

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

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

Northern Border credit rating upgrade – On September 3, 2020, S&P affirmed Northern Border’s credit rating at BBB+ and upgraded the outlook from Stable to Positive based on strong recontracting, continued stable cashflows, conservative leverage, solid shipper base and strong sponsors.

Credit rating affirmation - On September 30, 2020, S&P affirmed the Partnership's BBB/Stable credit rating. S&P continues to consider the Partnership's business risk profile to be a key strength underpinned by its highly contracted, long-term, take-or-pay contracts with creditworthy counterparties. S&P further recognizes the Partnership's strong basin diversification and benefits associated with its strategic relationship with TC Energy despite the expected higher leverage due to the funding of its growth projects. On October 30, 2020 Moody's also affirmed the Partnership's credit rating at Baa2/Stable.

On October 6, 2020 S&P revised the Partnership's outlook from Stable to Creditwatch Positive in connection with TC Energy's offer to acquire the Partnership's outstanding common units. The Creditwatch reflects S&P's opinion that TC Energy's offer to acquire all of the outstanding units will increase the level of parental support from TC Energy. Tuscarora was also placed on Creditwatch Positive.

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

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

PNGTS financing - On October 8, 2020, PNGTS entered into a Note Purchase and Private Shelf Agreement whereby PNGTS issued $125 million of 10-year Series A Senior Notes with a coupon of 2.84% per annum and entered into a three-year private shelf agreement for an additional $125 million Senior Notes. The PNGTS Series A Notes do not require any principal payments until maturity on October 8, 2030. Proceeds from the Series A Senior Note issuance were used to repay the outstanding balance of PNGTS' Revolving Credit Facility and for general partnership purposes including funding of growth capital. PNGTS expects to draw the remaining $125 million available under the Private Shelf Facility by the end of 2021, the estimated completion date of its Westbrook XPress project. The PNGTS Private

Shelf Agreement contains a covenant that limits total debt to no greater than 65 percent of PNGTS’ total capitalization and requires PNGTS to maintain a leverage ratio of no greater than 5.00 to 1.00.

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

Pacific Gas and Electric Company - In early 2019, GTN’s largest customer, Pacific Gas and Electric Company (Pacific Gas), filed for Chapter 11 bankruptcy protection. Pacific Gas accounted for less than 10 percent Partnership’s consolidated revenues in 2019. On July 1, 2020, Pacific Gas emerged from its bankruptcy proceedings. To date, GTN has not experienced any collection issues on its receivable from Pacific Gas and we expect this to continue going forward.

Iroquois' Wright Interconnect Project - During the first quarter of 2020, Iroquois received a notice of termination of its precedent agreement with Constitution pipeline related to its Wright Interconnect Project. In April 2020, Iroquois exercised its contractual right for reimbursement through a guarantee from Williams Partners, L.P., a 41 percent owner of the Constitution pipeline project. During the third quarter of 2020, the parties reached an agreement for a $48.5 million reimbursement of project costs, recovering all but $3 million of capital expenditures spent by Iroquois on the project. The proceeds received by Iroquois were distributed to its partners, of which the Partnership's proportionate share was approximately $24 million. The proceeds received by the Partnership were treated as a return of capital and used for general partnership purposes.

Great Lakes' Contract with TC Energy's Canadian Mainline - As noted in our 2019 Annual Report, a significant portion of Great Lakes’ total contract portfolio is contracted by its affiliates including its long-term transportation agreement with TC Energy’s Canadian Mainline that commenced on November 1, 2017 for a ten-year period that allows TC Energy to transport up to 0.711 billion cubic feet (equivalent to about 722,000 Dth/day) of natural gas per day on the Great Lakes system. This contract contained a volume reduction option up to full contract quantity until November 1, 2020. During the quarter, the Canadian Mainline requested an extension on the volume reduction option deadline and Great Lakes extended the option expiry to November 16, 2020.

Cash Distributions to Common Units and our General Partner

On April 21, 2020, the TC Pipelines Board declared the Partnership’s first quarter 2020 cash distribution in the amount of $0.65 per common unit, payable on May 12, 2020 to unitholders of record as of May 1, 2020. The declared distribution totaled $47 million and was payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as a holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest.

On July 23, 2020, the TC Pipelines Board declared the Partnership’s second quarter 2020 cash distribution in the amount of $0.65 per common unit, payable on August 14, 2020 to unitholders of record as of August 3, 2020. The declared distribution totaled $47 million and was payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as a holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest.

On October 21, 2020, the TC Pipelines Board declared the Partnership’s third quarter 2020 cash distribution in the amount of $0.65 per common unit, payable on November 13, 2020 to unitholders of record as of November 2, 2020. The declared distribution totaled $47 million and was payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as a holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest.

HOW WE EVALUATE OUR OPERATIONS

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

EBITDA

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

Adjusted EBITDA

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

Distributable Cash Flows

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

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

RESULTS OF OPERATIONS

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


	Three months ended
(unaudited)	September 30,		$	%
(millions of dollars)	2020	2019	Change	Change (a)
Transmission revenues	99	93	6	6
Equity earnings	39	31	8	26
Operating, maintenance and administrative costs	(24)	(26)	2	8
Depreciation and amortization	(29)	(19)	(10)	(53)
Financial charges and other	(17)	(20)	3	15
Net income before taxes	68	59	9	15

Income taxes	—	—	—	—
Net income	68	59	9	15

Net income attributable to non-controlling interests	3	3	—	—
Net income attributable to controlling interests	65	56	9	16

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

Three Months Ended September 30, 2020 Compared to the Same Period in 2019

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

Transmission revenues - The $6 million increase was largely the result of higher revenue from PNGTS as a result of new revenues from PXP Phase II and Westbrook XPress Phase I both of which entered service on November 1, 2019.

Equity Earnings - The $8 million increase was largely a one time result of higher earnings from our equity investment in Northern Border primarily related to certain pre-arranged contracts with ONEOK Midstream entered into by Northern Border that resulted in incremental revenue on the pipeline during the quarter. As noted under "Recent Business Developments" within Item 2, the pre-arranged contracts were cancelled by FERC effective October 15, 2020. The capacity was remarketed, and awarded under terms that approximate Northern Border’s maximum recourse rates, which are lower than the pre-arranged contract rates and is more consistent with historical results.

Operating, maintenance and administrative costs - The $2 million decrease was primarily due to:

•lower operating costs related to our pipeline systems' compliance programs; and

•decrease in TC Energy's allocated costs related to personnel.

Depreciation and amortization - The $10 million increase is related to increased maintenance capital expenditures at GTN and negative salvage allowance recorded for PNGTS during the period.

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


	Nine months ended
(unaudited)	September 30,		$	%
(millions of dollars)	2020	2019	Change	Change (a)
Transmission revenues	295	299	(4)	(1)
Equity earnings	123	115	8	7
Operating, maintenance and administrative costs	(72)	(76)	4	5
Depreciation and amortization	(68)	(58)	(10)	(17)
Financial charges and other	(54)	(63)	9	14
Net income before taxes	224	217	7	3

Income taxes	(1)	(1)	—	—
Net income	223	216	7	3

Net income attributable to non-controlling interests	13	12	1	(8)
Net income attributable to controlling interests	210	204	6	3

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

Nine Months Ended September 30, 2020 Compared to the Same Period in 2019

The Partnership’s net income attributable to controlling interests increased by $6 million in the nine months ended September 30, 2020 compared to the same period in 2019, mainly due to the following:

Transmission revenues - The $4 million decrease was largely the net result of the following:

•lower revenue on GTN due to (i) its scheduled 6.6 percent rate decrease effective January 1, 2020, (ii) lower discretionary services sold primarily due to moderate weather conditions in early 2020 compared to colder weather experienced in early 2019, (iii) additional sales in 2019 related to regional supply constraints from a force majeure event experienced by a neighboring pipeline that were not repeated in 2020; and (iv) lower opportunity for the sale of discretionary services during the second quarter given the increased natural gas storage injection rates upstream of GTN;

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

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

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

•lower revenue on Bison as a result of the expiration of one of its legacy contracts at the end of January 2019.

Operating, maintenance and administrative costs - The $4 million decrease was primarily due to:

•lower operating costs related to our pipeline systems' compliance programs; and

•a decrease in TC Energy's allocated costs related to personnel.

Depreciation and amortization - The $10 million increase is related to increased maintenance capital expenditures at GTN and negative salvage allowance recorded for PNGTS during the period.

Financial charges and other - The $9 million decrease was primarily attributable to the following:

•generally lower weighted average interest costs despite an increase in our overall debt balance; and

•higher AFUDC primarily due to continued spending on our expansion projects and higher maintenance capital spending.

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

As discussed in Note 9 within Item 1. “Financial Statements,” we will allocate a portion of the Partnership’s income to the Class B units after the annual threshold is exceeded which will effectively reduce the income allocable to the common units and net income per common unit. Beginning in 2020 and beyond, we expect the impact of the Class B distribution on our cashflows to be significantly lower compared to previous periods due to TC Energy's reduced share of GTN's distributable cashflows beginning at the end of March 2020 as part of the Class B agreement. Please also read Note 8 within Item 1. “Financial Statements,” for additional disclosures on the Class B units.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Overall Current Financial Condition

Cash and Debt position - Our overall long-term debt balance increased by approximately $135 million primarily as result of the financing put in place during the period for our expansion projects. The increase included an incremental $75 million of liquidity from GTN's issuance of Series A Senior Notes at a fixed rate of 3.12 percent which effectively secured the funding required for GTN XPress for the balance of 2020.

The $75 million liquidity position related to GTN, together with the $24 million return of capital special distribution we received during the third quarter from Iroquois representing our 49.34% share of the reimbursement proceeds received by Iroquois from its terminated Wright Interconnect Project, and net excess cash generated by our solid operating cashflows, resulted in an increase in the balance of our cash and cash equivalents to $253 million at September 30, 2020 compared to our position at December 31, 2019 of approximately $83 million.

Working capital position - At September 30, 2020, our current assets totaled $300 million and current liabilities amounted to $499 million, leaving us with a working capital deficit of $199 million compared to a deficit of $14 million at December 31, 2019. Our working capital deficiency is considered normal course for our business and is managed through:

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

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

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

We continue to be financially disciplined by using our available cash to fund ongoing capital expenditures and maintaining debt at prudent levels and we believe we are well positioned to fund our obligations as required.

We believe our (1) cash on hand, (2) operating cash-flows, (3) $500 million available borrowing capacity under our Senior Credit Facility at November 9, 2020 and (4) if needed, and subject to customary lender approval upon request, an additional $500 million capacity that is available under the Senior Credit Facility's accordion feature, are sufficient to fund our short-term liquidity requirements, including distributions to our unitholders, ongoing capital expenditures, required debt repayments and other financing needs such as capital contribution requests from our equity investments without the need for additional common equity.

Our Pipeline Systems' Current Financial Condition

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

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

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

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

•Bison’s remaining contracts will continue to be in effect until January of 2021. In 2019, Bison generated revenues of $32 million and is expected to produce comparable results in 2020. We continue to explore alternative transportation-related options for Bison and we believe commercial potential exists to allow for the flow of natural gas on Bison in both directions, with the southwest direction involving deliveries onto third party pipelines and ultimately connecting into the Cheyenne hub. In any event, Bison will continue to incur costs related to property tax and operating and maintenance costs of approximately $6 million per year.

Maintenance and expansion capital expenditures are funded by a variety of sources, as noted above. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends upon their financial condition and prevailing market conditions.

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

Cash Flow Analysis for the Nine Months Ended September 30, 2020 Compared to the Same Period in 2019


	Nine months ended
(unaudited)	September 30,
(millions of dollars)	2020	2019
Net cash provided by (used in):
Operating activities	339	344
Investing activities	(136)	1
Financing activities	(33)	(288)
Net increase in cash and cash equivalents	170	57
Cash and cash equivalents at beginning of the period	83	33
Cash and cash equivalents at end of the period	253	90

Operating Cash Flows

The Partnership's operating cashflows for the nine months ended September 30, 2020 compared to the same period in 2019 were lower primarily due to the decrease in distributions received from operating activities of equity investments, as a result of the following:

• the timing of receipt of Iroquois' third quarter 2019 distributions from its operating activities, which we would ordinarily have received during the fourth quarter of 2019 but were instead received early in the first quarter of 2020 offset by additional surplus cash distribution received from Iroquois in the third quarter of 2019 as a result of the cash it accumulated during the previous years' earnings; and

• lower distributions from our equity investment in Northern Border largely due to its higher maintenance capital spending.

Investing Cash Flows

During the nine months ended September 30, 2020, the cash used in our investing activities was a net cash outflow of $136 million compared to a net inflow of $1 million in the nine months ended September 30, 2019 due to the net effect of:

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

•$24 million return of capital distribution received from Iroquois, representing our 49.34% share of the reimbursement proceeds received by Iroquois from the termination of its Wright Interconnect Project; and

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

Financing Cash Flows

The change in cash used for financing activities was primarily due to the net debt issuance of $135 million in the nine months ended September 30, 2020 compared to a net debt repayment of $115 million for the same period in the prior year, primarily due to financing executed for the capital expenditures on our GTN XPress, PXP and Westbrook XPress expansion projects.

Short-Term Cash Flow Outlook

Operating Cash Flow Outlook

Northern Border declared its September 2020 distribution of $18 million on October 9, 2020, of which the Partnership received its 50 percent share or $9 million on October 30, 2020.

Iroquois declared its third quarter 2020 distribution of $21 million on November 2, 2020, of which the Partnership will receive its 49.34 percent share or $10 million on December 23, 2020.

Investing Cash Flow Outlook

The Partnership made an equity contribution to Great Lakes of $5 million in the first quarter of 2020. This amount represents the Partnership’s 46.45 percent share of an $11 million cash call from Great Lakes to make a scheduled debt repayment. The Partnership expects to make an additional $5 million equity contribution to Great Lakes in the fourth quarter of 2020 to further fund debt repayments. This is consistent with prior years.

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

Our consolidated entities have commitments of $92 million as of September 30, 2020 in connection with various maintenance and general plant projects.

Commercial system purchase effective August 1, 2020

On August 1, 2020, four of our pipelines jointly purchased an internally developed customer-facing commercial natural gas IT application system from a TC Energy affiliate. The total price of the transaction was $51 million and the Partnership's proportionate share was $38 million. The purchase, which is considered a maintenance capital cost, was funded primarily from cash generated from each pipeline's cash from operations. See Note 12 of the “Financial Statements” within Item 1.

Except for the commercial system purchase described above, which is considered maintenance capital, we do not anticipate any other material changes to our expected 2020 growth and maintenance capital expenditures from what was disclosed in our 2019 Annual Report. However, those estimates are subject to cost and timing adjustments due to weather, market conditions, permitting conditions and timing of regulatory permits, among other factors, as well as additional uncertainty presented by the COVID-19 pandemic. We expect to continue funding these expenditures from a combination of (1) cash from operations and (2) debt at both the asset and Partnership levels.

Financing Cash Flow Outlook

Distributions to unitholders

On October 21, 2020, the TC PipeLines Board declared the Partnership’s third quarter 2020 cash distribution in the amount of $0.65 per common unit payable on November 13, 2020 to unitholders of record as of November 2, 2020. Please see Note 16 of the "Financial Statements" within Item 1 and “Recent Business Developments” within Item 2 for additional disclosures.

Debt refinancing:

•The Partnership's $350 million aggregate principal amount 4.65 percent Unsecured Senior Notes and $500 million Senior Credit Facility are both due in 2021 and we expect that both will be refinanced or extended prior to maturity.

•It is expected that Tuscarora will refinance its maturing Unsecured Term loan through an extension of the existing facility including the potential to increase the size of the facility to include the financing required for Tuscarora XPress.

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

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

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

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

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

Total distributable cash flow includes Adjusted EBITDA:

less:

•AFUDC;

•Interest expense;

•Current income taxes;

•Distributions to non-controlling interests; and

•Maintenance capital expenditures from consolidated subsidiaries.

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

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

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

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

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


	Three months ended		Nine months ended
(unaudited)	September 30,		September 30,
(millions of dollars)	2020	2019	2020	2019
Net income	68	59	223	216
Add:
Interest expense (a)	21	22	63	66
Depreciation and amortization	29	19	68	58
Income taxes	—	—	1	1
EBITDA	118	100	355	341

Less:
Equity earnings:
Northern Border	(22)	(15)	(57)	(50)
Great Lakes	(10)	(8)	(39)	(37)
Iroquois	(7)	(8)	(27)	(28)
	(39)	(31)	(123)	(115)
Add:
Distributions from equity investments (b)
Northern Border	25	21	67	69
Great Lakes	—	7	32	39
Iroquois (c)	13	28	34	56
	38	56	133	164

Adjusted EBITDA	117	125	365	390

Less:
AFUDC	(4)	—	(7)	(1)
Interest expense (a)	(21)	(22)	(63)	(66)
Current income taxes	—	—	(1)	(1)
Distributions to non-controlling interest (d)	(6)	(4)	(17)	(14)
Maintenance capital expenditures (e)	(49)	(19)	(95)	(40)
	(80)	(45)	(183)	(122)

Total Distributable Cash Flow	37	80	182	268
General Partner distributions declared (f)	(1)	(1)	(3)	(3)
Distributions allocable to Class B units (g)	—	(1)	—	(1)
Distributable Cash Flow	36	78	179	264

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

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

(c)This amount represents our proportional 49.34 percent share of the distribution declared by our equity investee, Iroquois, for the current reporting period and excludes any distributions received that are considered return of investment. For the three and nine months ended September 30, 2019, the amount includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million and $7.8 million, respectively (three and nine months ended September 30, 2020 -none). In the three and nine months ended September 30, 2019 we also received an additional distribution amounting to approximately $15 million for both the three and nine months ended September 30, 2019 (three and nine months ended September 30, 2020- $2 million) related to the increase in the cash Iroquois generated from its higher net income post acquisition.

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

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

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

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

Three Months Ended September 30, 2020 Compared to the Same Period in 2019

Our EBITDA was higher for the three months ended September 30, 2020 compared to the same period in 2019. The $18 million increase was primarily due to higher revenue from PNGTS and equity earnings as discussed in more detail under the “Results of Operations” section within Item 2.

Our Adjusted EBITDA was lower for the three months ended September 30, 2020 compared to the same period in 2019. The $8 million decrease was primarily due to the net effect of the following:

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

•no distribution from Great Lakes during the quarter as it used the cash generated during the period to fund a one-time commercial IT system purchase from a TC Energy affiliate on August 1, 2020. This will reduce future operating costs and will increase Great Lakes’ rate base and we anticipate will generate a return on and of capital in future rates; and

•lower distributions from Iroquois as Iroquois satisfied its final surplus cash distribution obligation of $2.6 million per quarter in the fourth quarter of 2019 to us and in the third quarter of 2019, we received an additional one-time $15 million distribution representing our proportionate share of the excess cash accumulated by Iroquois between 2018 and 2019 from its earnings.

Our distributable cash flow decreased by $42 million in the three months ended September 30, 2020 compared to the same period in 2019 due to the net effect of:

•lower Adjusted EBITDA;

•one-time cash impact related to the funding of a commercial IT system purchase by GTN, Tuscarora and North Baja from a TC Energy affiliate on August 1, 2020. These expenditures will reduce future operating costs and increase our pipelines’ respective rate bases and we anticipate will generate a return on and of capital in future rates; and

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

Nine Months Ended September 30, 2020 Compared to the Same Period in 2019

Our EBITDA was higher for the nine months ended September 30, 2020 compared to the same period in 2019. The $14 million increase was primarily due to lower operating costs and higher equity earnings, partially offset by lower revenue from consolidated subsidiaries as discussed in more detail under the “Results of Operations” section within Item 2.

Our Adjusted EBITDA was lower for the nine months ended September 30, 2020 compared to the same period in 2019. The $25 million decrease was primarily due to:

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

•no distributions from Great Lakes during the quarter as it used the cash generated during the period to fund a one-time commercial IT system purchase from a TC Energy affiliate on August 1, 2020. This will reduce future operating costs and will increase Great Lakes’ rate base and we anticipate will generate a return on and of capital in future rates; and

•lower distributions from Iroquois as Iroquois satisfied its final surplus cash distribution obligation of $2.6 million per quarter in the fourth quarter of 2019; and in the third quarter of 2019, we received an additional one-time $15 million distribution representing our proportionate share of the excess cash accumulated by Iroquois between 2018 and 2019 from its earnings.

Our distributable cash flow decreased by $85 million in the nine months ended September 30, 2020 compared to the same period in 2019 due to the net effect of:

•lower Adjusted EBITDA;

increase our pipelines’ respective rate bases and we anticipate will generate a return on and of capital in future rates; and

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

Contractual Obligations

The Partnership’s Contractual Obligations

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


	Payments Due by Period
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Nine Months Ended September 30, 2020
TC PipeLines, LP
Senior Credit Facility due 2021	—	—	—	—	—	—
2013 Term Loan Facility due 2022	450	—	450	—	—	2.03%
4.65% Senior Notes due 2021	350	350	—	—	—	4.65%	(a)
4.375% Senior Notes due 2025	350	—	—	350	—	4.375%	(a)
3.90% Senior Notes due 2027	500	—	—	—	500	3.90%	(a)
GTN
3.12% Series A Senior Notes due 2030	175	—	—	—	175	3.12%	(a)
5.69% Unsecured Senior Notes due 2035	150	—	—	—	150	5.69%	(a)
PNGTS
Revolving Credit Facility due 2023	99	—	99	—	—	2.02%

North Baja
Unsecured Term Loan due 2021	50	—	50	—	—	1.85%
Tuscarora
Unsecured Term Loan due 2021	23	23	—	—	—	2.13%
Partnership (TC PipeLines, LP and its subsidiaries)
Interest on Debt Obligations(b)	417	73	109	90	145
Operating Leases	1	1	—	—	—
Right of Way commitments	4	1	1	—	2
	2,569	448	709	440	972

(a)Fixed interest rate.

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

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

The fair value of the Partnership’s 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 debt at September 30, 2020 was $2,257 million.

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

Summary of Northern Border’s Contractual Obligations

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


	Payments Due by Period (a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Nine Months Ended September 30, 2020
$200 million Credit Agreement due 2024	129	—	—	129	—	1.88%
7.50% Senior Notes due 2021 (b)	250	250	—	—	—	7.50%	(c)
Interest payments on debt (d)	25	20	3	2	—
Other commitments (e)	47	3	6	6	32
	451	273	9	137	32

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

(b) Expected to be refinanced prior to maturity.

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

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

As of September 30, 2020, $129 million was outstanding under Northern Border’s $200 million revolving credit agreement, leaving $71 million available for future borrowings. At September 30, 2020, Northern Border was in compliance with all of its financial covenants. If needed, and subject to customary lender approval upon request, an additional $200 million of capacity is available under Northern Border's revolving credit agreement accordion feature.

Northern Border has commitments of $21 million as of September 30, 2020 in connection with compressor station overhauls and other capital projects.

Summary of Great Lakes’ Contractual Obligations

Great Lakes’ contractual obligations as of September 30, 2020 included the following:


	Payments Due by Period (a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Nine Months Ended September 30, 2020
9.09% series Senior Notes due 2020 to 2021	20	10	10	—	—	9.09%	(b)
6.95% series Senior Notes due 2020 to 2028	88	11	22	22	33	6.95%	(b)
8.08% series Senior Notes due 2021 to 2030	100	10	20	20	50	8.08%	(b)
Interest payments on debt (c)	67	15	23	16	13
Right of Way commitments	1	—	—	—	1
	276	46	75	58	97

(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 $112 million of Great Lakes’ partners’ capital was restricted as to distributions as of September 30, 2020 (December 31, 2019 - $118 million). Great Lakes was in compliance with all of its financial covenants at September 30, 2020.

Great Lakes has commitments of $14 million as of September 30, 2020 in connection with pipeline integrity program spending, major overhaul projects, and right of way renewals.

Summary of Iroquois’ Contractual Obligations

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


	Payments Due by Period (a)
(unaudited) (millions of dollars)	Total	Less than 1 Year	1-3 Years	4-5 Years	More than 5 Years	Weighted Average Interest Rate for the Nine Months Ended September 30, 2020
4.12% series Senior Notes due 2034	140	—	—	—	140	4.12%	(b)
4.07% series Senior Notes due 2030	150	—	—	—	150	4.07%
6.10% series Senior Notes due 2027	28	4	8	8	8	6.10%	(b)
Interest payments on debt (c)	148	14	26	25	83
Transportation by others (d)	7	3	4	—	—
Operating leases	15	2	3	6	4

	488	23	41	39	385

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

(b) Fixed interest rate.

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

Iroquois has no capital commitments as of September 30, 2020.

Iroquois is restricted under the terms of its note purchase agreement from making cash distributions to its partners unless certain conditions are met. Before a distribution can be made, the debt to capitalization ratio must be below 75 percent and the debt service coverage ratio must be at least 1.25 times for the four preceding quarters. At September 30, 2020, the debt to capitalization ratio was 58.3 percent and the debt service coverage ratio was 6.30 times; therefore, Iroquois was not restricted from making any cash distributions.

RELATED PARTY TRANSACTIONS

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

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

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

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’ gains and losses may offset the hedged 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 expected LIBOR phase-out will affect the Partnership, including the possibility of a delay in adopting a new benchmark due to the uncertainty surrounding the COVID-19 pandemic. We currently do not expect the impact to be material.

As of September 30, 2020, the Partnership’s interest rate exposure resulted from our floating rate on North Baja’s Unsecured Term Loan Facility, PNGTS’ Revolving Credit Facility and Tuscarora’s Unsecured Term Loan Facility, under which $172 million, or 8 percent, of our outstanding debt was subject to variability in LIBOR interest rates (December 31, 2019 - $112 million or 6 percent).

As of September 30, 2020, the variable interest rate exposure related to our 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 3.26 percent. If interest rates hypothetically increased (decreased) on these facilities by one percent (100 basis points), compared with rates in effect at September 30, 2020, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $2 million.

As of September 30, 2020, $129 million, or 34 percent, of Northern Border’s outstanding debt was at floating rates. If interest rates hypothetically increased (decreased) by one percent (100 basis points), compared with rates in effect at September 30, 2020, Northern Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately $1 million.

Northern Border’s and Iroquois’ Senior Notes, all of Great Lakes’ and GTN' s Notes, and the PNGTS Series A Notes issued in October 2020, represent fixed-rate debt, and are therefore not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison, as Bison does not have any debt.

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

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

•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 and our pipeline systems enter into interest rate swaps and option agreements to mitigate the impact of changes in interest rates. For details regarding our current interest swaps and other agreements related to mitigation of impact on changes in interest rates, see Note 13 within Part I, Item 1. “Financial Statements,” which information is incorporated herein by reference.

COMMODITY PRICE RISK

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

COUNTERPARTY CREDIT RISK

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

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

•cash and cash equivalents;

•accounts receivable and other receivables; and

•the fair value of derivative assets

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

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

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

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

LIQUIDITY RISK

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

Item 4. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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

management of our General Partner, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 2020, there was no change in the Partnership’s internal control over financial reporting that 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 our 2019 Annual Report and Part I-Other Recent Business Developments-Northern Border within Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Item 1A. Risk Factors

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

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

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

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

While we have not seen any material impact of the COVID-19 pandemic on our business to date, it is difficult to predict how significant the impact of the COVID-19 virus, including any responses to it, will be on the global economy and our business or for how long any disruptions are likely to continue. The extent of such impact will depend on future developments, which are highly uncertain, including new information which may emerge concerning the severity of the COVID-19 pandemic and additional actions which may be taken to contain the further spread of the COVID-19 virus. Even after the COVID-19 pandemic has subsided, our business may be adversely impacted by the economic downturn or a recession that has occurred or may occur in the future. The COVID-19 pandemic could also increase or trigger other risks discussed in our Annual Report on Form 10-K for the year-ended December 31, 2019, any of which could have a materially adverse impact on our business, financial condition and results of operation.

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

In early March 2020, the market experienced a precipitous decline in crude oil prices in response to oil oversupply and demand concerns due to the economic impacts of the COVID-19 pandemic. Additionally, in April 2020, extreme shortages of transportation and storage capacity caused the New York Mercantile Exchange (NYMEX) West Texas Intermediate oil futures price to go as low as approximately negative $37. This negative pricing resulted from the holders of expiring front month oil purchase contracts being unable or unwilling to take physical delivery of crude oil and accordingly forced to make payments to purchasers of such contracts in order to transfer the corresponding purchase obligations.

Although oil prices have partially recovered from what was experienced in April, the COVID-19 pandemic and economic downturn could further negatively impact domestic and international demand for crude oil and natural gas and a prolonged period of low crude oil and natural gas prices would negatively impact exploration and development of new crude oil and natural gas supplies. In response to the sharp decline in oil and natural gas prices, many producers have announced cuts or suspension of exploration and production activities and some state regulators are considering mandating the proration of production of hydrocarbons. A drilling reduction could impact the availability of natural gas to be transported by our pipelines. Sustained low oil and natural gas prices could also impact counterparties’ creditworthiness and their ability to meet their transportation service cost obligations. Such developments could have an adverse effect on our assets, liabilities, business, financial condition, results of operations and cash flow.

The Conflicts Committee, the TC PipeLines Board and/or our unitholders may not recommend or approve TC Energy’s proposal, and even if accepted, the transactions contemplated by TC Energy’s proposal may be

delayed or may not be consummated, or the terms may be materially altered, which may cause significant volatility in the trading price of our common units.

The Conflicts Committee, the TC PipeLines Board and/or our unitholders may not recommend or approve TC Energy’s proposal. The Conflicts Committee is currently evaluating the terms of the TC Energy Proposal, but significant uncertainty remains as to whether the proposal will be consummated on the terms set forth in the offer letter or at all. Evaluation of TC Energy’s proposal may divert the attention of our management to the proposal rather than our own operations and pursuit of other opportunities that could have been beneficial to us. If we ultimately enter into an agreement relating to TC Energy Proposal, the terms may be materially different than in the non-binding offer letter. Any of these events or other actions or uncertainties associated with TC Energy Proposal may cause significant volatility in the trading price of our common units.

Item 6. Exhibits

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


3.1						Certificate of Limited Partnership of TC PipeLines, LP (Incorporated by reference to Exhibit 3.2 to TC PipeLines, LP's Form S-1 Registration Statement, filed on December 30, 1998).
3.2						Conformed Copy of Fourth Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP (incorporating Amendment No. 1, thereto, entered into on February 4, 2020 and effective as of December 31, 2018) (Incorporated by reference to Exhibit 3.2 to TC PipeLines, LP's Annual Report on Form 10-K for the year ended December 31, 2019).
31.1*						Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*						Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**						Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**						Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101						The following materials from TC Pipelines, LP's Quarterly Report on Form 10-Q for the period ended September 30, 2020 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements Comprehensive Income, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statement of Cash Flows, (v) the Consolidated Statement of Changes in Partners' Equity, and (vi) the Condensed Notes to Consolidated Financial Statements (Unaudited).
104						Cover Page Interactive Data File (embedded within the Inline XBRL document)

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 9th day of November 2020.


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

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

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

Document

Exhibit 31.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

I, Nathaniel A. Brown, certify that:

1.I have reviewed this quarterly report on Form 10-Q of TC PipeLines, LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: November 9, 2020

/s/ Nathaniel A. Brown

Nathaniel A. Brown

Principal Executive Officer and President

TC PipeLines GP, Inc., as General Partner of

TC PipeLines, LP

Document

Exhibit 31.2

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

I, William C. Morris, certify that:

1.I have reviewed this quarterly report on Form 10-Q of TC PipeLines, LP;

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: November 9, 2020

/s/ William C. Morris

William C. Morris

Principal Financial Officer, Vice President and Treasurer

TC PipeLines GP, Inc., as General Partner of

TC PipeLines, LP

Document

Exhibit 32.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

I, Nathaniel A. Brown , Principal Executive Officer and President of TC PipeLines GP, Inc., the General Partner of TC PipeLines, LP (the Partnership), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 hereby certify, to the best of my knowledge, in connection with the Partnership’s Quarterly Report on Form 10-Q for the period ended September 30, 2020 as filed with the Securities and Exchange Commission (the Report) on the date hereof, that:

•the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

•the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Dated: November 9, 2020

/s/ Nathaniel A. Brown

Nathaniel A. Brown

Principal Executive Officer and President

TC PipeLines GP, Inc., as General Partner of

TC PipeLines, LP

Document

Exhibit 32.2

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

I, William C. Morris, Principal Financial Officer, Vice-President and Treasurer of TC PipeLines GP, Inc., the General Partner of TC PipeLines, LP (the Partnership), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 hereby certify, to the best of my knowledge, in connection with the Partnership’s Quarterly Report on Form 10-Q for the period ended September 30, 2020 as filed with the Securities and Exchange Commission (the Report) on the date hereof, that:

•the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

•the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Dated: November 9, 2020

/s/ William C. Morris

William C Morris

Principal Financial Officer, Vice President and Treasurer

TC PipeLines GP, Inc., as General Partner of

TC PipeLines, LP