UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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


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

For the fiscal year ended December 31, 2020

For the fiscal year ended December 31, 2019

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

~~ ☐ 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 No.)

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


DelawareState or other jurisdictionof incorporation or organization	52-2135448(I.R.S. EmployerIdentification No.)

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

877-290-2772

(Registrant’s telephone number, including area code)

877-290-2772(Registrant’s telephone number, including area code)

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

Title of each Class Trading Symbol Name of each exchange on which registered Common units representing limited partner interests TCP NYSE

Securities registered pursuant ~~Title~~to ofSection 12(g) ~~each ClassCommon units representing limited partner interests Trading SymbolTCP Name~~ of ~~each~~the ~~exchange on which registeredNew York Stock Exchange~~Act:

None

~~Securities~~Indicate ~~registered~~by ~~pursuant~~check tomark ~~Section~~if the registrant is a well-known seasoned issuer, as defined in Rule ~~12(g)~~405 of the Securities Act~~:None~~. Yes x No ¨

Indicate by check mark if the registrant is anot ~~well-known~~required ~~seasoned~~to ~~issuer,~~file asreports ~~defined~~pursuant into ~~Rule~~Section ~~405~~13 or Section 15(d) of the ~~Securities~~ Act. Yes ⌧ ¨ No ◻x

Indicate by check mark ifwhether the registrant is(1) has ~~not~~filed all reports required to ~~file~~be ~~reports~~filed ~~pursuant~~by to Section 13 or ~~Section~~ 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ◻ x No ⌧¨

Indicate by check mark whether the registrant ~~(1)~~ has ~~filed~~submitted ~~all~~electronically ~~reports~~every Interactive Data File required to be ~~filed~~submitted bypursuant ~~Section 13~~to orRule ~~15(d)~~405 of ~~the~~Regulation S-T ~~Securities~~(§232.405 ~~Exchange Act~~ of ~~1934~~this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to ~~file~~submit such ~~reports), and (2)~~ ~~has been subject to such filing requirements for the past 90 days~~files). Yes ⌧ x No ◻¨

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 ⌧ No ◻

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting 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~~Accelerated ~~filer~~Filer ⌧x Accelerated filer ◻¨ Non-accelerated filer ◻¨ 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. ¨

IfIndicate ~~an emerging growth company, indicate~~ by check mark ifwhether the registrant has ~~elected~~filed ~~not~~a toreport ~~use~~on ~~the~~and ~~extended~~attestation ~~transition~~to ~~period~~its ~~for~~management’s ~~complying~~assessment ~~with~~of ~~any~~the ~~new~~effectiveness orof ~~revised~~its ~~financial~~internal ~~accounting~~control ~~standards~~over ~~provided~~financial ~~pursuant~~reporting tounder Section 13404(ab) of the ~~Exchange~~Sarbanes-Oxley Act (15 U.S.C. ◻7262(b)) by the registered public accounting firm that prepared or issued its audit report. x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒x

The aggregate market value of the common units of the registrant held by non-affiliates as of June 30, ~~2019~~2020 was approximately $ 2.72 billion.

As of February 19, ~~2020~~2021, there were 71,306,396 common units of the registrant outstanding.

Table of Contents

DOCUMENTS INCORPORATED BY REFERENCE

None

Table of Contents

TC PIPELINES, LP

TABLE OF CONTENTS


				Page No.
		Page No.
PART I

Item 1.			Business	8
PART I
Item 1A.			Risk Factors	32
Item 1.	Business	9
Item 1B.			Unresolved Staff Comments	46
Item 1A.	Risk Factors	26
Item 2.			Properties	46
Item 1B.	Unresolved Staff Comments	40
Item 3.			Legal Proceedings	46
Item 2.	Properties	40
Item 4.			Mine Safety Disclosures	46
Item 3.	Legal Proceedings	41
PART II
Item 4.	Mine Safety Disclosures	41
Item 5.			Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46

Item 6.			Selected Financial Data	47
PART II
Item 7.			Management’s Discussion and Analysis of Financial Condition and Results of Operations	66
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41
Item 7A.			Quantitative and Qualitative Disclosures About Market Risk	66
Item 6.	Selected Financial Data	42
Item 8.			Financial Statements and Supplementary Data	68
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
Item 9.			Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	68
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 9A.			Controls and Procedures	68
Item 8.	Financial Statements and Supplementary Data	64
Item 9B.			Other Information	69
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	64
PART III
Item 9A.	Controls and Procedures	64
Item 10.			Directors, Executive Officers and Corporate Governance	69
Item 9B.	Other Information	65
Item 11.			Executive Compensation	72

Item 12.			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	74
PART III
Item 13.			Certain Relationships and Related Transactions, and Director Independence	76
Item 10.	Directors, Executive Officers and Corporate Governance	65
Item 14.			Principal Accountant Fees and Services	78
Item 11.	Executive Compensation	68
PART IV
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	70
Item 15.			Exhibits and Financial Statement Schedules	80
Item 13.	Certain Relationships and Related Transactions, and Director Independence	72
Signatures				84
Item 14.	Principal Accountant Fees and Services	75

PART IV
Item 15.	Exhibits and Financial Statement Schedules	75

Signatures		79

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

TC PipeLines, LP Annual Report 2020 3

TC PipeLines, LP Annual Report 2019 3

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DEFINITIONS

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

2013 Term Loan Facility	~~TC PipeLines, LP’s $500 million term loan credit facility under a term loan agreement as amended on September 29, 2017~~	TC PipeLines, LP’s $500 million term loan credit facility under a term loan agreement as amended on September 29, 2017

2015 Term Loan Facility		TC PipeLines, LP’s $170 million term loan credit facility under a term loan agreement as amended on September 29, 2017
2015 Term Loan Facility	TC PipeLines, LP’s $170 million term loan credit facility under a term loan agreement as amended on September 29, 2017
2017 Acquisition		Partnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017

2017 Great Lakes Settlement		Stipulation and Agreement of Settlement for Great Lakes regarding its rates and terms and conditions of service approved by FERC on February 22, 2018
2017 Acquisition	Partnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017
2017 Northern Border Settlement		Stipulation and Agreement of Settlement for Northern Border regarding its rates and terms and conditions of service approved by FERC on February 23, 2018

2017 Tax Act		Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act, enacted on December 22, 2017
2017 Great Lakes Settlement	Stipulation and Agreement of Settlement for Great Lakes regarding its rates and terms and conditions of service approved by FERC on February 22, 2018
2018 FERC Actions		FERC’s 2018 issuance of Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC regulated pipelines and the impact of the Revised Policy Statement on pipelines held by an MLP

2018 GTN Settlement		Stipulation and Agreement of Settlement for GTN regarding its rates and terms and conditions of service approved by FERC on November 30, 2018
2017 Northern Border Settlement	Stipulation and Agreement of Settlement for Northern Border regarding its rates and terms and conditions of service approved by FERC on February 23, 2018
2019 Iroquois Settlement		An uncontested settlement filed by Iroquois with FERC to address the issues contemplated by the 2017 Tax Act and the 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019

2019 Tuscarora Settlement		An uncontested settlement filed by Tuscarora with FERC to address the issues contemplated by the 2017 Tax Act and the 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
2017 Tax Act	Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act, enacted on December 22, 2017
ADIT		Accumulated Deferred Income Tax

Adjusted EBITDA		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
2018 FERC Actions	FERC’s 2018 issuance of Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC regulated pipelines and the impact of the Revised Policy Statement on pipelines held by an MLP
AFUDC		Allowance for funds used during construction

ANR		ANR Pipeline Company
2018 GTN Settlement	Stipulation and Agreement of Settlement for GTN regarding its rates and terms and conditions of service approved by FERC on November 30, 2018
ASC		Accounting Standards Codification

ATM program		At-the-market Equity Issuance Program
2019 Iroquois Settlement	An uncontested settlement filed by Iroquois with FERC to address the issues contemplated by the 2017 Tax Act and the 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
BIA		Bureau of Indian Affairs

Bison		Bison Pipeline LLC
2019 Tuscarora Settlement	An uncontested settlement filed by Tuscarora with FERC to address the issues contemplated by the 2017 Tax Act and the 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
C2C Contracts		PNGTS’ Continent-to-Coast Contracts with several shippers for a term of 15 years for approximately 82,000 Dth/day

Canadian Mainline		TC Energy’s Mainline, a natural gas transmission system extending from the Alberta/Saskatchewan border east to Quebec
ADIT	Accumulated Deferred Income Tax
Certificate Policy Statement NOI		FERC Notice of Inquiry issued on April 19, 2018

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
AFUDC	Allowance for funds used during construction
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

Consolidated Subsidiaries		GTN, Bison, North Baja, Tuscarora and PNGTS
ASC	Accounting Standards Codification

ASU	Accounting Standards Update

ATM program	At-the-market Equity Issuance Program

BIA	Bureau of Indian Affairs

Bison	Bison Pipeline LLC

4 TC PipeLines, LP Annual Report 2020

C2C Contracts	PNGTS’ Continent-to-Coast Contracts with several shippers for a term of 15 years for approximately 82,000 Dth/day

Canadian Mainline	TC Energy’s Mainline, a natural gas transmission system extending from the Alberta/Saskatchewan border east to Quebec

Certificate Policy Statement NOI	FERC Notice of Inquiry issued on April 19, 2018

4 TC PipeLines, LP Annual Report 2019

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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
COVID-19		Coronavirus 2019

Delaware Act		Delaware Revised Uniform Limited Partnership Act
Class B Reduction	Approximately 35 percent reduction applied to the estimated annual Class B Distribution beginning in 2018, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit
DOT		U.S. Department of Transportation

DSUs		Deferred Share Units
Consolidated Subsidiaries	GTN, Bison, North Baja, Tuscarora and PNGTS
Dth/day		Dekatherms per day

EBITDA		Earnings Before Interest, Tax, Depreciation and Amortization
Delaware Act	Delaware Revised Uniform Limited Partnership Act
EPA		U.S. Environmental Protection Agency

ExC Project		Iroquois Enhancement by Compression project that involves upgrading its compressor stations along the pipeline and provide approximately 125,000 Dth/day of additional firm transportation service to meet current and future gas supply needs of utility customers
DOT	U.S. Department of Transportation
FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission
Dth/day	Dekatherms per day
GAAP		U.S. generally accepted accounting principles

General Partner		TC PipeLines GP, Inc.
DSUs	Deferred Share Units
GHG		Greenhouse Gas

Great Lakes		Great Lakes Gas Transmission Limited Partnership
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
GTN		Gas Transmission Northwest LLC

GTN XPress		GTN's projects designed to both increase the reliability of existing transportation service including 100,000 Dth/day of existing transportation service on GTN and provide for a total of 150,000 Dth/day of incremental transportation capacity, primarily through facility replacements and additions of existing brownfield compression sites.
EPA	U.S. Environmental Protection Agency
HCAs		High consequence areas

IDRs		Incentive Distribution Rights
ExC Project	Iroquois Enhancement by Compression project that involves upgrading its compressor stations along the pipeline and provide approximately 125,000 Dth/day of additional firm transportation service to meet current and future gas supply needs of utility customers
Iroquois		Iroquois Gas Transmission System, L.P.

IRS		Internal Revenue Service
FASB	Financial Accounting Standards Board
Joint Facilities		Pipeline facilities jointly owned with MNE on PNGTS

KPMG		KPMG LLP
FERC	Federal Energy Regulatory Commission
LDCs		Local Distribution Companies

LIBOR		London Interbank Offered Rate
GAAP	U.S. generally accepted accounting principles
LNG		Liquefied Natural Gas

MLPs		Master limited partnerships
General Partner	TC PipeLines GP, Inc.
MNE		Maritimes and Northeast Pipeline LLC, a subsidiary of Enbridge Inc.

MNOC		M&N Operating Company, LLC, a wholly owned subsidiary of MNE
GHG	Greenhouse Gas
Moody's		Moody's Investors Service

NGA		Natural Gas Act of 1938
Great Lakes	Great Lakes Gas Transmission Limited Partnership
North Baja		North Baja Pipeline, LLC

North Baja XPress		North Baja project to transport additional volumes of natural gas of approximately 495,000 Dth/day between Ehrenberg, Arizona and Ogilby, California
GTN	Gas Transmission Northwest LLC
Northern Border		Northern Border Pipeline Company

NYSE		New York Stock Exchange
GTN XPress	GTN project that will both increase the reliability of GTN's existing transportation service and provide up to 250,000 Dth/day of additional firm transportation service on the full path of the GTN system from Kingsgate, British Columbia, Canada to Malin, Oregon
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
HCAs	High consequence areas

IDRs	Incentive Distribution Rights

ILP Contribution	On December 31, 2018, General Partner contributed its 1.0101 percent general partner interest in each of the Partnership ILPs to the Intermediate GP and received a 1 percent general partner interest in the Partnership in return

ILPs	Intermediate Limited Partnerships

Intermediate GP	TC PipeLines Intermediate GP, LLC

IRS	Internal Revenue Service

TC PipeLines, LP Annual Report 2020 5

Iroquois Iroquois Gas Transmission System, L.P. Joint Facilities Pipeline facilities jointly owned with MNE on PNGTS

TC PipeLines, LP Annual Report 2019 5

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

PHMSA		U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration
LDCs	Local Distribution Companies
PNGTS		Portland Natural Gas Transmission System

PXP		Portland XPress Project of PNGTS to re-contract certain system capacity set to expire in 2019 as well as construct incremental compression facilities within PNGTS’ existing footprint in Maine
LIBOR	London Interbank Offered Rate
Revised Policy Statement		FERC's Revised Policy Statement on Treatment of Income Taxes

ROE		Return on equity
LNG	Liquefied Natural Gas
SEC		Securities and Exchange Commission

Securities Act		Securities Act of 1933, as amended
MLPs	Master limited partnerships
Senior Credit Facility		TC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated September 29, 2017

S&P		Standard & Poor's
MNE	Maritimes and Northeast Pipeline LLC, a subsidiary of Enbridge Inc.
TC Energy		TC Energy Corporation, formerly known as TransCanada Corporation

TC Energy Merger Agreement		TC Energy's definitive agreement with 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 0.70 common shares of TC Energy for each issued and outstanding publicly-held Partnership common unit.
MNOC	M&N Operating Company, LLC, a wholly owned subsidiary of MNE
TC Energy Merger		The merger of TCP Merger Sub, LLC with and into the Partnership, with the Partnership continuing as the sole surviving entity and an indirect, wholly owned subsidiary of TC Energy.

TQM		TransQuebec and Maritimes Pipeline
NGA	Natural Gas Act of 1938
Tuscarora		Tuscarora Gas Transmission Company

Tuscarora XPress		Tuscarora's expansion project through additional compression capability at an existing Tuscarora facility and provide up to 15,000 Dth/day of additional firm transportation service
North Baja	North Baja Pipeline, LLC
Unaffiliated TCP Unitholders		Holders of the outstanding Partnership common units, other than TC Energy and its affiliates

U.S.		United States of America
North Baja XPress	North Baja potential project to transport additional volumes of natural gas of approximately 495,000 Dth/day between Ehrenberg, Arizona and Ogilby, California
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
Northern Border	Northern Border Pipeline Company
Wholly owned subsidiaries		GTN, Bison, North Baja, and Tuscarora

WHO		World Health Organization
NYSE	New York Stock 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

Partnership ILPs	TC PipeLines Intermediate Limited Partnership, TC Tuscarora Intermediate Limited Partnership and TC GL Intermediate Limited Partnership

PHMSA	U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration

PNGTS	Portland Natural Gas Transmission System

PXP	Portland XPress Project of PNGTS to re-contract certain system capacity set to expire in 2019 as well as construct incremental compression facilities within PNGTS’ existing footprint in Maine

Revised Policy Statement	FERC's Revised Policy Statement on Treatment of Income Taxes

ROE	Return on equity

SEC	Securities and Exchange Commission

Securities Act	Securities Act of 1933, as amended

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, formerly known as TransCanada Corporation

TQM	TransQuebec and Maritimes Pipeline

Unless the context clearly indicates otherwise, TC PipeLines, LP and its subsidiaries are collectively referred to in this annual report as “we,” “us,” “our”, TC PipeLines 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).

Tuscarora	Tuscarora Gas Transmission Company

Tuscarora XPress	Tuscarora's expansion project through additional compression capability at an existing Tuscarora facility and provide up to 15,000 Dth/day of additional firm transportation service

6 TC PipeLines, LP Annual Report 2020

6 TC PipeLines, LP Annual Report 2019

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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 VIEs Variable Interest Entities Wholly-owned subsidiaries GTN, Bison, North Baja, and Tuscarora

Unless the context clearly indicates otherwise, TC PipeLines, LP and its subsidiaries are collectively referred to in this annual 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).

TC PipeLines, LP Annual Report 2019 7

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PART I

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

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

Forward-looking statements involve risks and uncertainties that may cause actual results to differ materially from the results predicted. Factors that could cause actual results and our financial condition to differ materially from those contemplated in forward-looking statements include, but are not limited to:

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

● •demand for natural gas;

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

● •natural gas prices and regional differences;

● •weather conditions;

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

● •competition from other pipeline systems;

● •natural gas storage levels; and

● •rates and terms of service;

● •the ~~performance~~refusal byor ~~the~~inability of our customers, shippers ofor counterparties to perform their contractual obligations onwith ~~our~~us, ~~pipeline~~whether ~~systems~~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 elimination of pass-through taxation or tax deferred distributions;

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

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

●•potential ~~our~~conflicts ~~ongoing~~of ~~ability~~interest tobetween ~~grow distributions through acquisitions~~TC PipeLines GP, Inc., ~~accretive~~our ~~expansions~~general orpartner ~~other~~(General ~~growth opportunities~~Partner), ~~including~~TC ~~the~~Energy ~~timing,~~Corporation ~~structure~~(TC ~~and~~Energy) ~~closure of further potential acquisitions~~and us;

●•failure ~~potential conflicts~~ of ~~interest~~the ~~between~~Partnership TCor ~~PipeLines~~our ~~GP,~~pipeline ~~Inc.,~~systems ~~our~~to ~~general~~comply ~~partner~~with ~~(General~~debt ~~Partner)~~covenants, TCsome ~~Energy~~of ~~Corporation~~which ~~(TC~~are ~~Energy)~~beyond ~~and~~our uscontrol;

●•the ~~failure~~ability to ~~comply~~maintain ~~with~~secure ~~debt~~operation ~~covenants,~~of ~~some~~our information technology including management of ~~which~~cybersecurity ~~are~~threats, ~~beyond~~acts ~~our~~of ~~control~~terrorism and related distractions;

● •the ~~ability~~implementation ~~to maintain secure operation~~ of ~~our~~future ~~information~~accounting ~~technology~~changes ~~including~~and ~~management~~ultimate ofoutcome ~~cybersecurity threats, acts~~ of ~~terrorism~~commitments and ~~related~~contingent ~~distractions~~liabilities (if any);

● •the ~~implementation~~impact of ~~future~~any ~~accounting~~impairment ~~changes and ultimate outcome of commitments and contingent liabilities (if any)~~charges;

●•changes in the ~~impact~~political ~~of any impairment charges~~environment;

●•operating ~~changes~~hazards, incasualty ~~the~~losses ~~political~~and ~~environment~~other matters beyond our control;

8 •the overall increase in the allocated management and operational expenses to our pipeline systems for services performed by TC Energy; ~~PipeLines, LP Annual Report 2019~~

TC PipeLines, LP Annual Report 2020 7

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●•ability ~~operating~~of ~~hazards,~~our ~~casualty~~pipeline ~~losses~~systems ~~and~~to ~~other~~renew ~~matters~~rights-of-way ~~beyond~~at ~~our~~a ~~control~~reasonable cost;

● •the ~~overall~~level ~~increase~~of inour ~~the~~indebtedness ~~allocated~~(including ~~management~~the ~~and~~indebtedness ~~operational~~of ~~expenses to~~ our pipeline systems), ~~for~~increases ~~services~~in ~~performed~~interest byrates, TCour ~~Energy;~~level of operating cash flows and the availability of capital;

● •the ~~level~~impact of ~~our~~a ~~indebtedness,~~potential ~~including~~slowdown in construction activities or a delay in the ~~indebtedness~~completion of our ~~pipeline~~capital ~~systems,~~projects ~~changes~~including increases in ~~interest~~costs ~~rates,~~ and ~~the~~ availability of ~~capital.~~labor, equipment and materials;

•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 market disruptions relating to global supply and demand for oil and natural gas;

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

•the timing and ability of TC Energy or the Partnership to consummate the TC Energy Merger.

These and other risks are described in greater detail in Part I, Item 1A. “Risk Factors.” Given these uncertainties, you should not place undue reliance on these forward-looking statements. 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.

Item 1. Business

NARRATIVE DESCRIPTION OF BUSINESS

GENERAL

We are a publicly traded Delaware master limited partnership. Our common units trade on the New York Stock Exchange (NYSE) under the symbol "TCP". We were formed by TC Energy and its subsidiaries in 1998 to acquire, own and participate in the management of energy infrastructure businesses in North America. Our pipeline systems transport natural gas in the U.S.

We are managed by our General Partner, which is an indirect, wholly- owned subsidiary of TC Energy. At December 31, ~~2019~~2020, subsidiaries of TC Energy ~~own~~owned approximately 24 percent of our common units, 100 percent of our Class B units, 100 percent of our incentive distribution rights (IDRs) and hold a two percent general partner interest in us. See Part II, Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for more information regarding TC Energy's ownership in us.

RECENT BUSINESS DEVELOPMENTS

Planned merger with TC Energy:

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 initial proposal, holders of the outstanding TC PipeLines common units, other than TC Energy and its affiliates, (the Unaffiliated TCP Unitholders) would receive 0.65 common shares of TC Energy for each issued and outstanding publicly-held Partnership common unit.

The offer was made to the board of directors of the General Partner (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).

On December 14, 2020, the Partnership, the General Partner, TC Energy, TransCan Northern Ltd., a Delaware corporation (TC Northern), TransCanada PipeLine USA Ltd., a Nevada corporation (TC PipeLine USA), and TCP Merger Sub, LLC, a Delaware limited liability company and an indirect wholly owned subsidiary of TC Energy (Merger Sub), entered into an Agreement and Plan of Merger (the TC Energy Merger Agreement). Pursuant to the TC Energy Merger Agreement, Merger Sub will be merged with and into the Partnership (TC Energy Merger), with the Partnership continuing as the sole surviving entity and an indirect wholly owned subsidiary of TC Energy.

Subject to the terms and conditions set forth in the TC Energy Merger Agreement, at the effective time of the TC Energy Merger, each common unit representing a fractional part of the limited partner interests in the Partnership issued and outstanding immediately prior to the effective time of the TC Energy Merger held by an Unaffiliated TCP Unitholder, will be cancelled in exchange for 0.70 shares of TC Energy’s common shares.

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The Conflicts Committee has approved the TC Energy Merger Agreement and the transactions contemplated thereby and recommended that the Board direct that the TC Energy Merger Agreement be submitted to a vote of the limited partners for their approval at a special meeting and recommended that the Board recommend to the limited partners of the Partnership that the limited partners approve the TC Energy Merger Agreement and the TC Energy Merger.

Based upon such recommendation, the Board has directed that the TC Energy Merger Agreement and the transactions contemplated thereby, including the TC Energy Merger, be submitted to the limited partners for their approval at a special meeting, to be held at 10:00 a.m. Central Time, on February 26, 2021. See Part I, Item 1A. “Risk Factors” for a discussion of the risks related to the TC Energy Merger. For additional information regarding the TC Energy Merger Agreement and the TC PipeLines Board’s process and rationale for the TC Energy Merger, please see the definitive proxy statement filed with the Securities Exchange Commission on January 26, 2021 and other documents filed with the Securities and Exchange Commission when they become available.

COVID-19

On March 11, 2020, the WHO declared COVID-19, a global pandemic. As the 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 were 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. The recently concluded transactions described below demonstrate our continued access to the debt capital markets at attractive levels:

•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 a further $75 million which will be used to finance a portion of the GTN XPress Project into 2023;

•During the third quarter of 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; and

•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 the Portland XPress project (PXP) and the Westbrook XPress project. 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 the Westbrook XPress project into 2021.

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 the COVID-19 pandemic has a more significant longer-term 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 Part I, Item 1A - "Risk Factors" and Part II, Item 7A - "Quantitative and Qualitative Disclosures About Market Risk."

Impairment considerations:

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Under U.S. GAAP, we evaluate our goodwill related to Tuscarora and North Baja for impairment at least annually or more frequently if any indicators of impairment are evident. Our long-lived assets and equity investments are evaluated whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

On a quarterly basis during 2020, we evaluated changes within our business and the external environment including considerations regarding whether such changes are permanent, to determine whether a triggering event had occurred. This analysis included the quarterly assessment of the impact of COVID-19 to our reporting units and equity investments. Through our quarterly analyses, no triggering events were identified.

The following factors were considered in our analysis specific to the Partnership:

•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 hold collateral, as appropriate, to support our contracts;

•we evaluated the multiples and discount rate assumptions within the current economic environment and compared to the previous quantitative model used for our North Baja and Tuscarora reporting units. The multiples and discount rates identified for the current year used in our qualitative model are reflective of the long-term outlook for Tuscarora and North Baja, in line with their underlying asset lives;

•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 continue to persist, 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.

Growth Projects Update:

~~Below~~PNGTS’ isPortland aXPress ~~summary~~Project (PXP) - PXP was initiated in 2017 in order to expand deliverability on the PNGTS system to Dracut, Massachusetts through re-contracting and construction of ~~our~~incremental ~~growth~~compression ~~projects~~within ~~announced~~PNGTS’ existing footprint in ~~2019~~Maine. PXP was designed to be phased in over a three-year time period. Phases I and ~~updates~~II were placed into service in 2018 and 2019, respectively, with the final Phase III placed into service during the fourth quarter of 2020. Beginning in 2021, PXP is expected to ~~previously~~generate ~~announced~~approximately ~~projects:~~$50 million in annual revenue for PNGTS. The total final volume of the project is approximately 183,000 Dth/day; 40,000 Dth/day from Phase I, 118,400 Dth/day from Phase II, which includes re-contracting and renewal of expiring contracts, and 24,600 Dth/day from Phase III. PXP is secured by long-term agreements and now that all phases of the project are in service, PNGTS is effectively fully contracted until 2032.

~~PNGTS’~~Additionally, ~~Portland~~in ~~XPress~~connection ~~Project~~with -PXP, ~~Our~~PNGTS ~~estimated~~entered ~~$85~~into ~~million~~an ~~Portland~~arrangement ~~XPress~~with ~~Project~~TC orEnergy ~~“PXP”~~regarding ~~was~~the ~~initiated~~construction inof ~~2017~~certain infacilities ~~order to expand deliverability~~ on the ~~PNGTS~~TC Energy system to(TransQuebec ~~Dracut,~~and ~~Massachusetts~~Maritimes ~~through~~Pipeline ~~re-contracting~~(TQM) and ~~construction~~TC ofEnergy’s ~~incremental~~Canadian ~~compression~~Mainline ~~within~~natural ~~PNGTS’~~gas ~~existing~~transmission ~~footprint~~system in(Canadian ~~Maine.~~Mainline)) ~~PXP~~that ~~was~~were ~~designed~~required to befulfill ~~phased~~PXP incontracts ~~over~~on athe ~~three-year~~PNGTS ~~time period~~system. ~~Phases~~In Ithe ~~and~~event IIthe ~~were~~Canadian ~~placed~~system ~~into~~expansions ~~service~~had onterminated ~~November~~prior ~~1, 2018 and November 1, 2019, respectively. Phase III of the project is expected~~ to betheir in -service ~~on November 1~~dates, ~~2020.~~PNGTS ~~Beginning~~could inhave ~~2021,~~been ~~PXP~~required ~~is expected~~ to ~~generate~~reimburse ~~approximately~~TC ~~$50~~Energy ~~million in annual revenue~~ for ~~PNGTS.~~an ~~PNGTS~~amount ~~filed~~up ~~the~~to ~~required applications with FERC for all three phases of~~ the ~~project~~total inoutstanding ~~2018,~~costs ~~which~~incurred ~~included an amendment~~ to ~~its Presidential Permit and an increase in its certificated capacity through~~ the ~~addition~~date of athe ~~compressor unit at its jointly owned facility with Maritimes and Northeast Pipeline LLC to bring additional natural gas supply to New England~~termination. ~~The~~As ~~total~~a ~~final~~result ~~volume~~ of placing the ~~project~~TC isEnergy ~~approximately~~facilities ~~183,000~~associated ~~Dth/~~with ~~day;~~the ~~40,000~~Phases ~~Dth/day from Phase~~ I, ~~118,400 Dth/day from Phase~~ II, ~~which includes re-contracting~~ and ~~renewal~~III ofvolumes ~~expiring~~in ~~contracts~~service, ~~and~~PNGTS' ~~24,600~~reimbursement ~~Dth/day~~obligation ~~from~~to ~~Phase~~TC ~~III.~~Energy Werelating ~~continue~~ to ~~advance~~ this project ~~and~~has ~~have~~been ~~received all approvals on filings to date~~extinguished. We expect to file with FERC for approval to proceed with construction of Phase III of the project in early 2020. PXP is secured by long-term agreements and when all phases of the project are in service, PNGTS will be effectively fully contracted until 2032.

~~Additionally,~~PNGTS' inWestbrook ~~connection~~XPress ~~with~~Project ~~PXP,~~(Westbrook ~~PNGTS~~XPress) ~~entered~~- ~~into~~Westbrook anXPress ~~arrangement~~is ~~with~~an TCestimated ~~Energy~~$125 ~~regarding~~million ~~the~~multi-phase ~~construction~~expansion ofproject ~~certain~~that ~~facilities~~is onexpected ~~the~~to TCgenerate ~~Energy~~approximately ~~system~~$35 ~~(TransQuebec~~million ~~and~~in ~~Maritimes~~revenue ~~Pipeline~~for ~~(TQM)~~PNGTS ~~and~~on TCan ~~Energy’s~~annualized ~~Canadian~~basis ~~Mainline~~when ~~natural~~fully ~~gas~~in ~~transmission~~service. ~~system~~It ~~(Canadian~~is ~~Mainline))~~part ~~that~~of ~~will~~a becoordinated ~~required~~offering to ~~fulfill~~transport ~~future~~incremental ~~PXP~~Western ~~contracts~~Canadian onSedimentary ~~the~~Basin ~~PNGTS~~(WCSB) ~~system.~~natural Ingas ~~the~~supplies ~~event~~to the ~~Canadian~~Northeast ~~system~~U.S. ~~expansions~~and ~~terminate~~Atlantic ~~prior~~Canada tomarkets ~~their~~through ~~in-service~~additional ~~dates,~~compression ~~PNGTS~~capability ~~could~~at bean ~~required~~existing toPNGTS ~~reimburse~~facility. TCWestbrook ~~Energy~~XPress ~~for~~is andesigned ~~amount up~~ to ~~the~~be ~~total~~phased ~~outstanding~~in ~~costs~~over ~~incurred~~a tofour-year ~~the~~period ~~date~~which ofbegan ~~the~~on ~~termination.~~November As1, a2019 ~~result~~with ofPhase TCI. ~~Energy’s~~On ~~system~~June ~~expansions~~18, ~~being~~2020, ~~commercially~~FERC inissued ~~service~~a oncertificate ~~November~~of 1,public ~~2019,~~convenience and ~~PNGTS’~~necessity ~~commitments~~for onPhases TCII ~~Energy’s~~and ~~upstream~~III ~~pipelines~~for ~~being~~this ~~assigned~~project. toOn ~~the~~January ~~PXP~~9, ~~Phase II shippers~~2021, ~~PNGTS’~~construction ~~obligation~~crews toand ~~reimburse~~equipment ~~the~~were ~~costs~~mobilized ~~for~~to ~~Phase~~the Iexisting ~~and~~Westbrook IICompressor ~~terminated,~~Station ~~which~~following ~~was~~the ~~approximately~~authorization ~~$143~~received ~~million~~from atFERC ~~the~~by ~~time~~PNGTS ofon ~~termination.~~January ~~Going forward~~6, in2021. ~~the~~Phases ~~event~~II ~~the~~and ~~Phase~~ III ~~expansion~~have ~~terminates~~estimated ~~prior to its~~ in-service ~~date,~~dates ~~PNGTS~~of ~~will~~November ~~only~~2021 beand ~~obligated~~2022, torespectively. ~~reimburse~~These ~~costs~~three ~~incurred~~Phases bywill TCadd ~~Energy~~incremental incapacity ~~relation~~of toapproximately ~~Phase~~43,000 ~~III~~Dth/day, ~~which~~69,000 ~~was~~Dth/day, ~~$0.6~~and ~~million~~18,000 atDth/day, ~~December~~respectively. 31Westbrook XPress, ~~2019~~together ~~and~~with isPXP, ~~estimated~~will toincrease bePNGTS’ ~~approximately~~capacity ~~$8.0~~by ~~million~~90 bypercent ~~November~~from 1210,000 ~~2020,~~Dth/day ~~when~~to TCapproximately ~~Energy’s~~400,000 ~~facilities~~Dth/day. ~~associated~~The ~~with~~Westbrook ~~the~~XPress ~~Phase~~contracts ~~III~~expire ~~volumes~~between go2036 ~~into~~and ~~service~~2042.

~~TC PipeLines, LP Annual Report~~ Iroquois Gas Transmission ExC Project - In 2019 9, Iroquois initiated the “Enhancement by Compression” project (Iroquois 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

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~~PNGTS'~~project’s ~~Westbrook~~total ~~XPress~~design ~~Project~~capacity ~~(Westbrook~~is ~~XPress)~~approximately -125,000 ~~Westbrook~~Dth/day ~~XPress~~with is an estimated ~~$125~~cost ~~million~~of ~~multi-phase expansion project that is expected to generate approximately~~ $35250 million in revenue for PNGTS on an annualized basis when fully in service. It is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin (WCSB) natural gas supplies to the Northeast U.S. and ~~Atlantic Canada markets through additional compression capability at an existing PNGTS facility. Westbrook XPress is designed to be phased~~ in ~~over a four~~-~~year period which began on November 1, 2019 with Phase I. Phases II and III have estimated in-~~service ~~dates~~date of November ~~2021 and 2022, respectively~~2023. ~~These~~This ~~three~~project ~~Phases~~ will ~~add~~be ~~incremental~~100 ~~capacity~~percent ofunderpinned ~~approximately 43,000 Dth/day, 69,000 Dth/day, and 18,000 Dth/day, respectively. Westbrook XPress, together~~ with ~~PXP,~~20-year ~~will increase PNGTS’ capacity by 90 percent from 210,000 Dth/day to approximately 400,000 Dth/day. The Westbrook XPress~~ contracts ~~expire between 2036 and 2042~~.

~~GTN~~North Baja XPress Project (~~GTN~~North Baja XPress) - OnNorth ~~November~~Baja 1,XPress ~~2019,~~is wean ~~announced~~estimated ~~that~~$90 ~~GTN~~million ~~will~~project ~~move~~to ~~forward~~transport ~~with~~additional ~~the~~volumes ~~GTN~~of ~~XPress~~natural gas along North Baja’s mainline system. The project ~~which~~was ~~will~~initiated ~~transport~~in response to market demand to provide firm transportation service of approximately ~~250~~495,000 Dth/day ofbetween ~~additional~~Ehrenberg, ~~volumes~~Arizona ofand ~~natural~~Ogilby, ~~gas~~California. ~~enabled~~The bybinding TCopen ~~Energy’s~~season ~~system~~for ~~expansion~~the ~~upstream~~project was concluded in April of 2019. ~~The~~In ~~estimated~~December ~~total~~2019, ~~project~~North ~~cost~~Baja filed an application with FERC to authorize the construction of this ~~integrated~~project. ~~reliability~~On ~~and~~September ~~expansion~~8, ~~project~~2020, isFERC ~~$335~~issued ~~million~~its Environmental Assessment (EA) for the North Baja XPress Project. The ~~project’s~~EA ~~reliability~~concluded ~~work~~that isapproval ~~anticipated~~of tothe beproject, inwith ~~service~~appropriate bymitigating ~~the~~measures, ~~end~~would ofnot ~~2021~~constitute ~~and~~a ~~will~~major ~~account~~federal ~~for~~action ~~more~~significantly ~~than~~affecting ~~three~~the ~~quarters~~quality of the ~~total~~human ~~project cost~~environment. North ~~These~~Baja ~~costs~~XPress ~~are~~was ~~expected~~subject to bea ~~recovered~~Final inInvestment ~~recourse~~Decision ~~rates.~~(FID) ~~The~~by ~~project’s~~Sempra ~~expansion~~LNG ~~work~~International, isLLC, ~~anticipated~~(Sempra toLNG) beregarding ~~commercially~~the ~~phased~~development, ~~into~~construction ~~service~~and ~~through~~operation ~~November~~of ~~2023.~~a ~~GTN~~Liquified ~~XPress’~~Natural ~~expansion~~Gas ~~work~~(LNG) isterminal ~~100~~in ~~percent~~Baja ~~underpinned~~California, byMexico ~~fixed~~and ~~rate~~on ~~negotiated~~November ~~contracts~~17, ~~with~~2020, anSempra ~~average~~LNG ~~term~~reached ina ~~excess~~positive ofFID 30on ~~years~~the project. ~~The~~North ~~incremental~~Baja ~~capacity~~XPress ishas ~~expected~~an toestimated ~~generate~~in-service ~~approximately~~date ~~$25~~of ~~million~~February in2023 ~~revenue~~and ~~annually~~is ~~when~~still ~~fully~~subject into ~~service~~regulatory approvals and other requirements of the project.

~~Tuscarora~~Great ~~XPress~~Lakes ~~Project~~Long-term ~~(Tuscarora~~Contracts Related to ANR's Alberta XPress) Project - ~~Tuscarora~~On ~~XPress~~February is12, an2020, ~~estimated~~TC ~~$13~~Energy ~~million~~approved the Alberta XPress Project, an expansion project ~~through~~on ~~additional~~its ~~compression~~ANR ~~capability~~Pipeline atsystem with an ~~existing~~estimated ~~Tuscarora~~in-service ~~facility~~date of 2022. ~~Tuscarora~~This ~~XPress~~project isutilizes ~~100~~existing capacity on the Great Lakes system (of which we own 46.45 percent) ~~underpinned~~and byTC aEnergy’s 20Canadian Mainline systems to connect growing natural gas supply from the WCSB to U.S. Gulf Coast LNG export markets. In 2018, Great Lakes entered into long-~~year~~term ~~contract~~transportation ~~and~~capacity ~~will~~contracts ~~transport~~with ANR for approximately 15900,000 Dth/day of ~~additional~~aggregate ~~volumes~~capacity ~~when~~for ~~completed~~a interm ~~November~~of ~~2021~~15 years. ~~Tuscarora~~In connection with the approval of the Alberta XPress isProject, ~~expected~~such contracts have been reduced to ~~generate~~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 $2182 million starting in ~~revenue~~2022. The contract contains reduction options (i) at any time on anor ~~annualized~~before ~~basis~~October ~~when~~1, ~~fully~~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. Any remaining unsubscribed capacity on Great Lakes will be available for contracting in ~~service~~response to developing marketing conditions. In June 2020, ANR filed an application with FERC to authorize construction of the project. On December 4, 2020, FERC issued its Environmental Assessment (EA) for the Alberta XPress 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. In the first quarter of 2021, Alberta XPress has been modified to reflect revised shipper commitments. ANR has not exercised its contract reduction rights as a result of the revised shipper commitments on Alberta XPress. In the event of a contract reduction, the remaining unsubscribed capacity on Great Lakes will be available for contracting.

~~Iroquois~~GTN ~~Gas~~XPress ~~Transmission~~Project ~~ExC~~– ~~Project~~In ~~(Iroquois~~March ~~ExC~~2020, ~~Project)~~GTN -filed ~~During~~applications ~~the~~with ~~second~~FERC ~~quarter~~to authorize the replacement of ~~2019,~~certain ~~Iroquois~~facilities ~~initiated~~on the ~~“Enhancement~~GTN bysystem. ~~Compression”~~Once ~~project~~in ~~(ExC~~service, ~~Project)~~the ~~which~~replacements will ~~optimize~~increase the ~~Iroquois~~reliability ~~system~~of toexisting ~~meet~~transportation ~~current~~service ~~and~~including ~~future~~100,000 ~~gas~~Dth/day ~~supply~~of ~~needs~~existing, oflong-term, ~~utility~~full-haul ~~customers~~system ~~while~~capacity. ~~minimizing~~In 2021, GTN will file an application with FERC for the ~~environmental~~installation ~~impact~~of ~~through~~an ~~enhancements~~additional compressor at ~~existing~~a brownfield compressor ~~stations~~site ~~along~~and ~~the~~other ~~pipeline~~related work. InOnce ~~February~~in ~~2020~~service, ~~Iroquois~~this ~~filed~~work will increase GTN's long-term system capacity by an ~~application~~incremental ~~with~~150,000 ~~FERC~~Dth/day. toThe ~~authorize~~estimated ~~the~~total ~~construction~~project cost of ~~the~~this integrated reliability and expansion project is $335 million. The project’s ~~total~~reliability ~~design~~work ~~capacity~~ is ~~approximately~~anticipated ~~125,000~~to ~~Dth/day~~be ~~with~~in anservice ~~estimated~~by ~~cost~~the end of ~~$250~~2021 ~~million~~ and ~~in-service~~will ~~date~~account for more than three quarters of ~~November~~the ~~2023~~total project cost. ~~This~~These costs are expected to be recovered in recourse rates. The project’s ~~will~~expansion work is anticipated to be commercially phased into service through November 2023. GTN XPress’ expansion work is 100 percent underpinned ~~with~~by ~~20-year~~fixed rate negotiated contracts with an average term in excess of 30 years. The incremental capacity is expected to generate approximately $25 million in revenue annually when fully in service.

~~North~~Laws Baja XPress Project (North Baja XPress) - North Baja XPress is an estimated $90 million potential project to transport additional volumes of natural gas along North Baja’s mainline system. The project was initiated in response to market demand to provide firm transportation service of up to approximately 495,000 Dth/day between Ehrenberg, Arizona and Ogilby, California. The binding open season for the project was concluded in April of 2019. In December 2019, North Baja filed an application with FERC to authorize the construction of this project. The estimated in-service date is November 1, 2022, subject to the satisfaction or waiver of certain conditions precedent, including a positive Final Investment Decision (FID) from Sempra LNG International, LLC.Regulation

2020 PIPES Act – On December 27, 2020, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (2020 PIPES Act) was signed into law as part of a broader federal spending and COVID-19 relief package. In addition to authorizing funding for PHMSA’s ~~Compliance~~pipeline safety programs through fiscal year 2023, the 2020 PIPES Act provides several substantive amendments to the federal pipeline safety statutes, including requiring PHMSA to provide public notice of enforcement hearings and ensuring that formal hearings are open to the public, issue new rules implementing a leak detection and repair program, and determine whether to proceed with rulemaking to update class location requirements. President Biden's administration will have responsibility for implementing the 2020 PIPES Act and we are in the process of assessing impacts associated with this new legislation. See also Part I, Item 1. “Business- Government Regulation-Pipeline Safety Matters” for more information relating to PHSMA regulation of gas pipelines.

NEPA Final Rule – On ~~October~~July 116, ~~2019~~2020, the ~~federal~~Council ~~Pipeline~~on ~~and~~Environmental ~~Hazardous~~Quality ~~Materials Safety Administration~~ (~~PHMSA~~CEQ), ~~released~~under ~~the~~former ~~first~~President ofTrump's ~~three~~administration, ~~anticipated~~published a final ~~rulemakings following its issuances in 2016 of an expansive proposed rulemaking (known as the "gas mega~~ rule") ~~revising~~modifying the ~~regulation~~National ofEnvironmental ~~gas~~Policy ~~transmission~~Act ~~and gathering lines~~(NEPA). The ~~October~~modified ~~1, 2019~~ final rule ~~relates~~establishes ~~specifically~~a totime ~~gas~~limit ~~transmission~~of ~~pipelines~~two ~~and,~~years ~~among~~for ~~other~~preparation ~~things,~~of ~~updates~~environmental ~~reporting~~impact statements and ~~records~~one ~~retention~~year ~~standards~~ for ~~covered pipelines and expands~~ the ~~level~~preparation of ~~required~~environmental ~~integrity~~ assessments. ~~that~~The ~~must~~modified berule ~~completed~~also oneliminates ~~certain~~the ~~pipeline~~responsibility ~~segments~~to ~~outside~~consider ofcumulative ~~high~~effects ~~consequence~~of ~~areas~~a ~~(HCAs)~~project. The ~~October 1, 2019~~ final rule ~~also~~is ~~requires~~being ~~operators~~widely tocriticized ~~review~~by ~~maximum~~environmental ~~allowable~~and ~~operating~~conservation ~~pressure~~groups ~~records~~ and ~~perform~~is ~~specific~~facing ~~remediation~~court ~~activities~~challenges. ~~where~~The ~~records~~Partnership ~~are~~sees ~~not~~these ~~available.~~updates Weas ~~are~~positive ~~currently~~for ~~assessing~~ the ~~operational and financial impact related to this ruling which will become effective on July 1~~industry, ~~2020~~as ~~with~~CEQ astreamlines ~~15-year~~the ~~implementation~~review ~~deadline~~process. ~~The~~However, ~~remaining rulemakings comprising~~ the ~~gas~~updated ~~mega~~rules ~~rule~~may ~~are expected to~~ be ~~issued~~delayed indue ~~2020.~~to ~~See~~congressional ~~also~~review ~~Part~~or I,litigation ~~Item~~or 1.President ~~“Business-~~Biden's ~~Government~~Administration ~~Regulation-Pipeline~~may ~~Safety~~direct ~~Matters”~~CEQ ~~for more information relating~~ to ~~PHSMA~~reconsider ~~regulation~~or ofwithdraw ~~gas~~the ~~pipelines~~rule.

~~Cash~~FERC's ~~Distributions~~Instant Final Rule – The Natural Gas Act (NGA) allows intervening parties to ~~Common~~file ~~Units~~requests for rehearing with FERC within thirty days after FERC issues an order granting a certificate of public convenience and ~~our~~necessity ~~General~~and ~~Partner~~prohibits any party from appealing such a certificate order to the courts without having received a final ruling from FERC. In lieu of following the statutory requirement of thirty days to respond to a rehearing request, FERC used “tolling orders” effectively granting itself more

~~Our quarterly declared cash distributions in 2019 remained the same as in 2018~~TC PipeLines, ~~which was $0.65 per common unit or $2.60 per common unit in total for the year. Please read Notes 15 within Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more information.~~ LP Annual Report 2020 11

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

10 TC PipeLines, LP Annual Report 2019

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Ontime. ~~July~~This ~~23,~~prevented ~~2019,~~ the ~~board~~requester offrom ~~directors~~being ofable ~~our General Partner declared the Partnership’s second quarter 2019 cash distribution in the amount of $0.65 per common unit, which was paid on August 14, 2019~~ to ~~unitholders~~appeal ~~of record as of August 2, 2019. The declared distribution totaled $47 million and was paid in~~ the ~~following~~certificate ~~manner: $46 million~~ to ~~common unitholders (including $4 million to~~ the ~~General Partner as a holder of 5~~courts,~~797,106~~ ~~common~~while ~~units~~FERC ~~and~~continued ~~$7 million~~ to ~~another~~grant ~~subsidiary~~notices ofto TCproceed ~~Energy~~with asconstruction ~~holder of 11,287,725 common units~~(NTPs) ~~and~~with $1the ~~million~~requests ~~to our General Partner~~ for ~~its~~rehearing ~~two~~still ~~percent general partner interest~~pending.

OnIntervening ~~October~~parties ~~22,~~recently ~~2019,~~challenged the ~~board~~tolling oforder ~~directors~~practice ofin ~~our~~court. ~~General~~Prior ~~Partner~~to ~~declared~~ the ~~Partnership~~court’s ~~third quarter 2019 cash distribution in the amount of $0.65 per common unit~~decision, ~~which was paid~~ on ~~November~~June 149, ~~2019 to unitholders of record as of November 1~~2020, ~~2019.~~FERC ~~The~~issued ~~declared~~an ~~distribution~~Instant ~~totaled~~Final ~~$47~~Rule ~~million~~(IFR) ~~and~~prohibiting ~~was~~it ~~paid~~from inissuing ~~the~~NTPs ~~following~~while ~~manner:~~rehearing ~~$46~~requests ~~million~~are topending. ~~common~~On ~~unitholders~~June ~~(including~~30, $42020, ~~million to~~ the ~~General~~D.C. ~~Partner~~Circuit asCourt ~~a holder~~ of ~~5,797,106~~Appeals ~~common~~issued ~~units~~an ~~and~~opinion $7prohibiting ~~million~~FERC tofrom ~~another~~utilizing ~~subsidiary~~tolling oforders TCwithout ~~Energy~~any assubstantive ~~holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest~~ruling.

OnThe ~~January~~IFR ~~21,~~and ~~2020,~~ the ~~board~~D.C. ofCircuit ~~directors~~Opinion oftogether ~~the~~cause ~~General~~concern ~~Partner~~that ~~declared~~potential ~~the~~delays ~~Partnership’s~~may ~~fourth~~occur ~~quarter 2019 cash distribution~~ in the ~~amount~~certification ofprocess ~~$0.65~~given ~~per~~that ~~common~~FERC ~~unit,~~will ~~which~~need ~~was paid on February 14, 2020~~ to ~~unitholders~~issue ofdecisions ~~record~~on asrehearing ofrequests ~~January 31, 2020. The declared distribution totaled $47 million and was paid~~ in ~~the following manner: $46 million to common unitholders (including $4 million to the General Partner as~~ a ~~holder~~much ofshorter ~~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 the General Partner for its two percent general partner interest~~timeframe.

~~Incentive~~The ~~distributions~~Partnership ~~are~~believes ~~paid~~that tounder ~~our~~the ~~General~~current ~~Partner~~framework, ifthese ~~quarterly~~issuances ~~cash~~will ~~distributions~~likely onhave ~~the~~a ~~common~~small ~~units~~impact ~~exceed~~on ~~levels~~our ~~specified~~pending inand ~~the~~future ~~Fourth~~projects, ~~Amended~~if ~~and~~any ~~Restated~~at ~~Agreement~~all. Many of ~~Limited~~our ~~Partnership~~projects ofin ~~the~~execution ~~Partnership~~are ~~(as~~largely ~~amended,~~compression-based ~~the~~and ~~Partnership~~involve ~~Agreement).~~little-to-no ~~The~~greenfield ~~distributions~~construction, ~~declared~~which ~~during~~have ~~2019~~tended ~~did~~to ~~not~~be ~~reach~~less ~~the~~likely ~~specified~~to ~~levels~~draw ~~for~~a ~~any~~rehearing ~~period~~request. ~~and~~However, ~~therefore,~~certain ~~the~~avenues ~~General~~still ~~Partner~~exist ~~did~~for ~~not~~FERC ~~receive~~to ~~any~~extend ~~distributions~~the intime ~~respect~~period oflonger, ~~its~~FERC ~~IDRs~~continues into ~~2019.~~retain ~~See~~discretion ~~Part~~over ~~II,~~when ~~Item~~to 7issue ~~“Management’s~~a ~~Discussion~~notice to proceed, and ~~Analysis~~the ofcurrent ~~Financial~~framework ~~Condition~~may ~~and~~be ~~Results~~modified by legislation (some of ~~Operations~~which –has ~~Cash~~already ~~Distribution~~been ~~Policy~~proposed) ofor a potential further appeal to the ~~Partnership”~~United ~~for~~States ~~further~~Supreme ~~information~~Court, ~~regarding~~therefore we cannot know the ~~Partnership’~~impact of FERC's ~~distributions~~IFR with certainty at this time.

~~Class~~Environmental B(Water) ~~Distributions~~– U.S. Army Corps of Engineers (USACE) and EPA Rulemaking: In 2020, considerable steps were taken by the USACE and EPA, under former President Trump's administration, to define the scope of waters federally regulated under the Clean Water Act (CWA), known as Waters of the United States (WOTUS), as well as the framework and implementation of CWA permitting and certification programs that Partnership projects are regulated under. For example, while constructing, maintaining, repairing, and/or replacing our pipelines and related facilities, our activities may discharge dredged or fill material into WOTUS and, in effect, may require a CWA Section 401 water quality certification and CWA Section 404 general permit, such as Nationwide Permit (NWP) 12. On June 22, 2020 a revised, narrower, definition of WOTUS, as proposed by the EPA and USACE, became effective. On September 11, 2020, EPA’s rule clarifying various aspects of the CWA Section 401 water quality certification process, became effective. The final WOTUS and Section 401 certification rules, which are both very favorable to our permitted activities and business, were subsequently challenged in federal courts, with litigation still pending.

OnAdditionally, ~~January~~the 21CWA Section 404 NWP Program has been under increased national scrutiny since April 15, 2020, ~~the~~when ~~board~~a Montana federal District Court ruled against TC Energy’s use of ~~directors~~an allegedly invalid NWP 12 for the performance of ~~our~~construction ~~General~~activities ~~Partner~~affecting ~~declared~~WOTUS in Montana for its ~~annual~~Keystone ~~Class~~XL Boil ~~distribution~~pipeline inproject (the ~~amount~~Presidential Permit for which was revoked on January 20, 2021 by executive order of $8President ~~million~~Biden) and enjoined the USACE from issuing NWP 12s to authorize any and all utility projects nationwide (later narrowed to only oil and gas pipeline construction projects) until the USACE resolved the Court’s identified compliance issue. The scope of the District Court ruling, ~~which~~the ~~was~~ensuing ~~paid~~appeal of the ruling to higher courts, and subsequent lawsuits against other pipeline projects’ use of NWP 12 on ~~February~~similar 14grounds, ~~2020~~have created a great deal of uncertainty around the continued use of NWP 12 for projects. InAdditionally, ~~2019~~rulemaking undertaken by the USACE in 2020 to reissue or renew the 2017 NWPs, which are set to expire in 2022, may have increased the ~~Class~~uncertainty Bsurrounding ~~distribution~~the ~~paid~~use ~~was~~of ~~$13~~NWP ~~million~~12. ~~Please~~The ~~read~~final ~~Notes~~rule, 11which reissued 12 existing NWPs, 14included ~~and~~a 15restructured ~~within~~NWP ~~Part~~12 IVthat separated utilities covered under the permit into three NWPs, ~~Item~~with 15the more contentious oil and gas pipelines isolated from the rest. ~~“Exhibits~~The reissuance also did not rectify the ESA non-compliance at the center of the legal dispute in the Keystone XL NWP litigation. The USACE’s final rule will become effective in March 2021. The uncertainty surrounding NWP 12 as a result of the pending litigation and ~~Financial~~USACE ~~Statement~~may ~~Schedules”~~materially ~~for~~affect ~~more~~the ~~detailed~~Partnership’s ~~disclosures~~business, onparticularly with the ~~Class~~arrival Bof ~~units~~President Biden's administration. For further discussion on environmental matters, see Part I, Item 1 “Government Regulation” – “Environmental Matters”.

Environmental (Species) –The U.S. Fish and Wildlife Service (USFWS), under former President Trump, spent 2020 developing a rule which notably clarifies that criminal liability under the Migratory Bird Treaty Act (MBTA) will apply only to actions “directed at” migratory birds, its nests, or its eggs and not those lawful activities, such as pipeline facility construction, maintenance, repair, and related activities, which inadvertently result in the “incidental take” of migratory birds. This controversial rulemaking is beneficial to the Partnership, but if reversed by President Biden’s administration, the Partnership may continue being subject to the criminal liability associated with the "incidental take" of migratory birds, their nests, and their eggs under the MBTA, which may have a material effect on the Partnership. Additionally, former President Trump's administration also finalized two notable Endangered Species Act (ESA) rules in December 2020. One rule established a definition for “habitat” for the limited purpose of designating critical habitat and another rule which established the process and factors to be considered when determining whether to exclude certain lands from critical habitat designations, controversially including economic impacts. For further discussion on environmental matters, see Part I, Item 1 “Government Regulation” – “Environmental Matters”.

Environmental (Air) – Federal and State Climate Change Regulations –The trend towards increased regulation of GHG emissions in the oil and natural gas sector to combat climate change was evident in federal and state agency rulemaking in 2020, predominantly at the state level. On August 13, 2020, the EPA issued policy and technical amendments to lessen the administrative and compliance cost burden on the oil and gas industry related to the New Source Performance Standards (NSPS). One of the rules, imposing policy amendments and dated to be effective on September 14, 2020, notably removed the transmission and storage sector from the source category and rescinded methane and Volatile Organic Compound (VOC) requirements for remaining sources. The amendments are currently being challenged in federal court. Notwithstanding these legal challenges, President Biden issued an executive order on January 20, 2021 that specifically directed the EPA to review the technical amendments and to propose revisions to existing source standards. The more controversial policy amendment is expected to be addressed soon. Additionally, on December 27, 2020, former President Trump signed into law the 2020 PIPES Act, which includes a requirement for PHMSA to regulate methane emissions from pipelines, joining EPA as one of two federal

12 TC PipeLines, LP Annual Report 2020

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regulators of GHG emissions. State and local governments are also increasingly regulating GHGs, potentially leading to additional compliance costs and operating restrictions. For example, Oregon is undertaking rulemaking to develop a carbon cap and reduce program at the direction of its Governor. Local governments in those states are also moving towards building electrification, cutting demand for hydrocarbon energy sources. For further discussion on environmental matters, see Part I, Item 1 “Government Regulation” – “Environmental Matters”.

Cash Distributions to Common Units and our General Partner

Our quarterly declared cash distributions in 2020 remained the same as in 2019, which was $0.65 per common unit or $2.60 per common unit in total for the year. Please read Note 14 within Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more information.

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, which was paid on May 12, 2020 to unitholders of record as of May 1, 2020. The declared distribution totaled $47 million and was paid in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest.

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, which was paid on August 14, 2020 to unitholders of record as of August 3, 2020. The declared distribution totaled $47 million and was paid in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest.

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, which was paid on November 13, 2020 to unitholders of record as of November 2, 2020. The declared distribution totaled $47 million and was paid in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to our General Partner for its two percent general partner interest.

On January 19, 2021, the TC PipeLines Board declared the Partnership’s fourth quarter 2020 cash distribution in the amount of $0.65 per common unit, which was paid on February 12, 2020 to unitholders of record as of January 29, 2020. The declared distribution totaled $47 million and was paid 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 the General Partner for its two percent general partner interest.

Incentive distributions are paid to our General Partner if quarterly cash distributions on the common units exceed levels specified in the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership (as amended, the Partnership Agreement). The distributions declared during 2020 did not reach the specified levels for any period and, therefore, the General Partner did not receive any distributions in respect of its IDRs in 2020. See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Cash Distribution Policy of the Partnership” for further information regarding the Partnership’s distributions.

To date, there has been no annual Class B distribution for 2021. In 2020, the Class B distribution paid was $8 million. Please read Note 11 within Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more detailed disclosure on the Class B units.

Other Business Developments

~~Partnership~~Northern ~~structure~~Border complaint - On ~~December~~March 31, ~~2018~~2020, BP Canada Energy Marketing Corp., Oasis Petroleum Marketing LLC and Tenaska Marketing Ventures (the ~~General~~Alliance ~~Partner~~for ~~contributed~~Open ~~its~~Markets) ~~1.0101~~filed ~~percent~~a ~~general~~complaint ~~partner~~with ~~interest~~FERC in(Docket ~~each~~No. ofRP20-745-000) TCagainst ~~PipeLines~~Northern ~~Intermediate~~Border ~~Limited~~alleging ~~Partnership,~~that TCNorthern ~~Tuscarora~~Border ~~Intermediate~~violated ~~Limited~~Sections ~~Partnership~~4 and TC5 GLof ~~Intermediate~~the ~~Limited~~NGA ~~Partnership~~FERC ~~(together~~policy, ~~the~~and ~~Partnership~~other ~~ILPs)~~regulations toby TC(i) ~~PipeLines~~failing ~~Intermediate~~to ~~GP,~~post ~~LLC~~capacity ~~(the~~as ~~Intermediate~~available ~~GP),~~on a ~~wholly~~long-~~owned~~term ~~subsidiary~~basis ofbefore ~~the~~entering ~~Partnership,~~into ~~and~~a ~~received~~prearranged atransaction ~~one~~for ~~percent~~six ~~general~~agreements ~~partner~~with ~~interest~~ONEOK inRockies ~~the~~Midstream, ~~Partnership~~L.L.C.; in(ONEOK ~~return~~Midstream) and (ii) structuring the ~~ILP~~prearranged ~~Contribution).~~transaction ~~This~~open ~~resulted~~season in a ~~simplification~~manner ofthat ~~the~~denied ~~General~~other ~~Partner’s~~shippers ~~effective~~a ~~two~~meaningful ~~percent~~opportunity ~~general~~to ~~interest~~bid inon the ~~Partnership~~capacity. ~~previously~~On ~~held~~April ~~through~~2, ~~its~~2020, ~~directly-held~~ConocoPhillips ~~one~~Company, ~~percent~~Shell Energy North America (US), L.P. and ~~indirectly-held~~XTO 1Energy Inc.~~0101~~ ~~percent~~(the ~~general~~Indicated ~~partner~~Shippers, ~~interests~~together inwith the ~~Partnership~~Alliance ~~and~~for ~~Partnership~~Open ~~ILPs~~Markets, ~~respectively,~~the toComplainants) filed a ~~directly~~second complaint with FERC (Docket No. RP20-~~held~~767-000) ~~two~~against ~~percent~~Northern ~~general~~Border ~~partner~~containing ~~interest~~similar inallegations regarding the ~~Partnership~~prearranged transaction open season. The ~~Partnership~~Complainants ~~subsequently~~have ~~held~~requested ~~100~~that ~~percent~~FERC of(a) unwind the ~~Partnership~~six ~~ILPs’~~prearranged ~~limited~~contracts; ~~and~~(b) ~~general~~require ~~partner~~Northern ~~interests,~~Border ~~with~~to hold an open season for the ~~general~~capacity ~~partner~~such ~~interest~~that ~~being~~all ~~held~~interested ~~through~~parties are on equal footing; and (c) direct Northern Border to cease from engaging in prearranged transactions where the ~~Intermediate~~unsubscribed GPcapacity has not been publicly posted as generally available.

~~During~~The ~~the~~prearranged ~~fourth~~contracts ~~quarter~~range ofin ~~2019,~~volume ~~the~~from ~~Partnership~~40,000 ~~initiated~~to ~~the~~269,732 ~~dissolution~~Dth/day offor ~~the~~terms ~~Partnership~~ranging ~~ILPs~~from ~~and~~10 ~~Intermediate~~months ~~GP.~~to ~~Effective~~10 ~~October 31~~years, ~~2019,~~two ~~the~~of ~~Intermediate~~which GPbegan ~~and~~on ~~Partnership~~June ~~ILPs~~1, ~~transferred~~2020. ~~100~~Northern ~~percent~~Border offiled ~~the~~a ~~ownership~~motion ofto ~~their~~consolidate ~~pipeline~~the ~~assets~~two tocomplaint ~~the~~dockets ~~Partnership,~~ and ~~the~~filed ~~process~~its ofresponse ~~dissolving~~to ~~and unwinding~~ the ~~entities~~complaints ~~was~~on ~~completed~~May in1, ~~January~~ 2020. ~~Accordingly~~On June 1,2020, ~~the~~updated ~~Partnership~~tariff ~~now~~sheets ~~owns~~reflecting ~~its~~the ~~pipeline~~contract ~~assets~~price ~~directly,~~were ~~which~~filed ~~creates~~by aNorthern ~~more~~Border ~~efficient~~with ~~partnership~~FERC ~~structure~~for ~~and~~the ~~aligns~~two ~~more~~contracts ~~closely~~set ~~with~~to ~~other~~begin ~~MLP~~June ~~structures~~1, ~~existing~~2020. ~~today~~On July 1, ~~with~~2020, noFERC ~~economic~~issued ~~impact~~an toorder and accepted the ~~general~~tariff ~~and~~sheets, ~~limited~~subject ~~partners~~to the outcome of ~~the~~complaint ~~Partnership~~proceedings.

~~Financing~~TC PipeLines, LP Annual Report 2020 13

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

Partnership’s Senior Credit Facility and Overall Debt Level - We continue to deleverage our balance sheet. At December 31, 2019, there was no outstanding balance under the Partnership's Senior Credit Facility. Additionally, the Partnership's overall consolidated debt was reduced by $106 million from $2,118 million at December 31, 2018 to $2,012 million at December 31, 2019 as a result of the (a) $40 million net repayment from cash flow of the outstanding balance under the Partnership's Senior Credit facility; (b) $50 million partial repayment of the Partnership's 2013 $500 Million Term Loan

TC PipeLines, LP Annual Report 2019 11

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~~Facility;~~On October 15, 2020, FERC issued an order on the complaints and directed Northern Border to (c1) ~~the~~refrain ~~repayment~~from making similar, discriminatory awards of ~~$35~~capacity ~~million~~in ~~due~~the ~~upon~~future, (2) rescind the ~~maturity~~pre-arranged ofdeals ~~GTN's~~with ~~$75~~ONEOK ~~million~~Midstream, ~~Unsecured~~effective ~~Term~~October ~~Loan~~15, ~~Facility;~~2020, and (d3) $1hold ~~million~~a ~~scheduled~~new ~~payment~~open onseason ~~Tuscarora's~~without ~~Unsecured~~a ~~Term~~pre-arranged ~~Loan~~shipper. ~~offset~~In byaddition, ~~$20~~FERC ~~million~~directed ofNorthern ~~additional~~Border ~~borrowings~~to onfile ~~PNGTS'~~revisions ~~revolving~~to ~~credit~~its ~~facility.~~tariff ~~See~~requiring ~~Part~~it ~~II,~~to ~~Item~~post 7capacity on its website before entering a pre-arranged deal. ~~"Management’s~~FERC ~~Discussion~~did ~~and~~not ~~Analysis~~order ofNorthern ~~Financial~~Border ~~Condition~~to ~~and~~refund ~~Result~~any of ~~Operations-Liquidity~~the ~~and~~revenue ~~Capital~~earned ~~Resources"~~from ~~for~~the ~~more~~pre-arranged ~~information~~transactions with ONEOK Midstream.

~~Credit~~Northern ~~Rating~~Border ~~Upgrade~~held -an Onopen ~~July~~season ~~23,~~from ~~2019,~~October ~~Standard~~21 &to ~~Poor's~~28, ~~(S&P)~~2020 ~~upgraded~~to remarket the ~~Partnership’s~~capacity. ~~credit~~Final ~~rating~~bids towere ~~BBB/Stable~~evaluated ~~from~~and ~~BBB-/Stable~~the ~~primarily~~successful ~~due~~bids toreflect ~~the~~a ~~improvement~~revenue inthat ~~our~~approximates ~~financial~~Northern ~~risk~~Border’s ~~profile~~maximum ~~resulting~~recourse rates, a reduction from ~~our~~the ~~ongoing~~pre-arranged ~~deleveraging~~contract ~~efforts~~rate.

~~Financing~~Great –Lakes ~~Unconsolidated~~501-G ~~Subsidiaries~~Proceeding - On May 11, 2020, FERC terminated Great Lakes’ 501-G proceeding and ruled that Great Lakes had complied with the one-time reporting requirement, designated as FERC Form No. 501-G related to the rate effect of the Tax Cuts and Jobs Act (2017 Tax Act). Additionally, FERC also stated that rate reductions provided for in Great Lakes' 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, FERC will not exercise its right to institute a NGA Section 5 investigation to determine if Great Lakes is over-recovering on its current tariff rates.

~~Northern~~Commercial ~~Border~~system purchase - InOn ~~June~~August ~~2019~~1, ~~Northern~~2020, ~~Border~~GTN, ~~borrowed~~Great anLakes, ~~additional~~Tuscarora ~~$100~~and ~~million~~North ~~under~~Baja ~~its~~entered ~~$200~~into ~~million~~a ~~revolving~~purchase ~~credit~~agreement ~~facility~~with a TC Energy affiliate to ~~finance~~purchase aan ~~$100~~internally ~~million~~developed ~~cash~~customer-facing ~~distribution~~commercial natural gas transmission information technology (IT) application that maintains and manages customer contracts, natural gas capacity release, customer nominations, metering and billings. The total value of ~~which~~the transaction was $5051 million ~~was~~and ~~received~~the byPartnership's proportionate share of the ~~Partnership~~cost was $38 million. ~~Northern~~Prior ~~Border's~~to ~~outstanding~~the ~~balance~~transaction ~~under~~close, GTN, Great Lakes, Tuscarora and North Baja each paid the affiliate for the use of this ~~facility~~system ~~amounted~~as topart ~~$115~~of ~~million~~their atongoing ~~December~~operating 31expenses. As a result of the capital purchase, ~~2019~~the amount paid by each pipeline will be added to its respective rate base and utilized in the calculation of maximum allowable rates.

Iroquois' ~~Financing~~Wright Interconnect Project - OnDuring ~~May~~the 9,first ~~2019~~quarter of 2020, Iroquois ~~refinanced~~received ~~$140~~a ~~million~~notice of 6termination of its precedent agreement with Constitution pipeline related to its Wright Interconnect Project.~~63%~~ ~~Senior~~In ~~Notes~~April ~~due~~2020, ~~2019~~Iroquois ~~and~~exercised ~~$150~~its ~~million~~contractual right for reimbursement through a guarantee from Williams Partners, L.P., a 41 percent owner of 4the Constitution pipeline project.~~84%~~ ~~Senior~~During ~~Notes~~the ~~due~~third inquarter of 2020, bythe ~~issuing~~parties reached an agreement for a $~~140~~48.5 million reimbursement of ~~new~~project ~~15-year~~costs, ~~4.12%~~recovering ~~Senior~~all ~~Notes~~but ~~and~~ $~~150~~3 million of ~~new~~capital ~~10-year~~expenditures ~~4.07%~~spent ~~Senior~~by ~~Notes~~Iroquois on the project. The ~~debt~~proceeds ~~covenants~~received ~~require~~by Iroquois towere ~~maintain~~distributed ~~a debt~~ to ~~capitalization~~its ~~ratio~~partners, ~~below~~of 75which ~~percent~~the ~~and~~Partnership's aproportionate ~~debt~~share ~~service~~was ~~coverage~~approximately ~~ratio~~$24 ofmillion. atThe ~~least~~proceeds ~~1.25~~received ~~times~~by ~~for~~ the ~~four~~Partnership ~~preceding~~were ~~quarters~~treated ~~and~~as ~~are~~a ~~unchanged~~return ~~from~~of ~~those~~capital ~~governing~~and ~~the~~used ~~refinanced~~for ~~Senior~~general ~~Notes~~partnership purposes.

Great Lakes' Contract with TC Energy's Canadian Mainline - As noted in our 2019 Annual Report on Form 10-K for the year 2019 (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 (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 fourth quarter, the Canadian Mainline requested an extension on the volume reduction option deadline and Great Lakes extended the option expiry to November 16, 2020 and then again until November 20, 2020.

On November 20, 2020, both parties came to an agreement. Effective November 1, 2021 the original contract rate will be reduced with no changes in the contracted volume. Additionally, after November 20, 2020, the Canadian Mainline shall have the right to reduce the contracted volume or terminate the full contract, effective November 1st of the applicable year, provided that 349 days’ prior written notice has been given to Great Lakes. As of February 24, 2021, no further changes to this contract have been made. The future revenue reduction on Great Lakes from the revised contract is not expected to have a material impact on the Partnership's expected distributions from Great Lakes.

Financing and Credit Ratings

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 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 3-year private shelf agreement for an additional $75 million of Senior Notes (GTN Private Shelf Facility) by the end of 2023, the estimated completion date of the GTN XPress Project. 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

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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 3-year private shelf agreement for an additional $125 million of Senior Notes (PNGTS Private Shelf Facility) by the end of third quarter of 2021 to refinance amounts funded on its revolving credit facility for costs associated with the Westbrook XPress Project. The PNGTS Private Shelf Facility 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.

GTN credit rating affirmation -On January 21, 2021, Moody's Investors Service (Moody's) affirmed GTN's A3 credit rating and revised GTN's outlook to stable from negative primarily in connection with the revision of TC Energy's outlook to stable from negative.

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 cash flows, 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.

$350 million Senior Notes redemption - The Partnership's $350 million aggregate principal amount of 4.65 percent Unsecured Senior Notes mature on June 15, 2021. On February 12, 2021, the Partnership exercised its option to redeem the Unsecured Senior Notes on March 15, 2021 at a redemption price equal to 100% of the principal amount of the notes then outstanding, plus unpaid interest accrued to March 15, 2021. Partial funding for the redemption is expected to be provided using cash on hand, and borrowings under the Partnership’s $500 million Senior Credit Facility.

Business Strategies

● •Our strategy is focused on generating long-term, steady and predictable distributions to our unitholders by investing in long-life critical energy infrastructure that provides reliable delivery of energy to customers.

● •Our investment approach is to develop or acquire assets that provide stable cash distributions and opportunities for new capital additions, while maintaining a low-risk profile. We are opportunistic and disciplined in our approach when identifying new investments.

● •Our goal is to maximize distributable cash flows over the long -term through efficient utilization of our pipeline systems and appropriate business strategies, while maintaining a commitment to safe and reliable operations.

Understanding the Natural Gas Infrastructure Business

Natural gas infrastructure moves natural gas from major sources of supply or upstream gathering facilities to downstream locations or markets that use natural gas to meet their energy needs. Infrastructure systems include meter stations that record how much natural gas comes on to the pipeline and how much exits at the delivery locations; compressor stations that act like pumps to move the large volumes of natural gas along the pipeline; and the pipelines themselves that transport natural gas under high pressure.

Regulation, rates and cost recovery

Interstate natural gas pipelines are regulated by FERC. FERC approves the construction of new facilities and regulates aspects of our business including the maximum rates that are allowed to be charged. Maximum rates are based on operating costs, which include allowances for operating and maintenance costs, income and property taxes, interest on debt, depreciation expense to recover invested capital and a return on the capital invested. During 2018, FERC issued a revised policy statement that changed its long-standing policy on the treatment of income taxes for rate-making purposes for MLP-owned pipelines. The revised policy statement had a significant impact on MLPs in general and on their respective natural gas pipeline assets. (See also Part I, Item 1. “Business- Government Regulation- 2018 FERC Actions for” more information).

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Although FERC regulates maximum rates for services, interstate natural gas pipelines frequently face competition and therefore may choose to discount their services in order to compete.

Because FERC rate reviews are periodic and not annual, actual revenues and costs typically vary from those projected during a rate case. If revenues no longer provide a reasonable opportunity to recover costs, a pipeline can file with FERC for a determination of new rates, subject to any moratoriums in effect. FERC also has the authority to initiate a review to determine whether a pipeline’s rates of return are just and reasonable. In some cases, a settlement or agreement with the pipeline’s shippers is achieved, precluding the need for FERC to conduct a rate case, which may include mutually beneficial performance incentives. A settlement is ultimately subject to FERC approval.

Contracting

New infrastructure projects are typically supported by long-term contracts. The term of the contracts is dependent on the individual developer’s appetite for risk and is a function of expected rates of return, stability and certainty of returns. Transportation contracts expire at varying times and underpin varying amounts of capacity. As existing contracts approach their expiration dates, efforts are made to extend and/or renew the contracts. If market conditions are not favorable at the time of renewal, transportation capacity may remain uncontracted, be contracted at lower rates or be contracted on a shorter-term basis. Unsold capacity may be recontracted if and when market conditions become more favorable. The ability to extend and/or renew expiring contracts and the terms of such subsequent contracts will depend upon the overall commercial environment for natural gas transportation and consumption in the region in which the pipeline is situated.

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approach their expiration dates, efforts are made to extend and/or renew the contracts. If market conditions are not favorable at the time of renewal, transportation capacity may remain uncontracted, be contracted at lower rates or be contracted on a shorter-term basis. Unsold capacity may be recontracted if and when market conditions become more favorable. The ability to extend and/or renew expiring contracts and the terms of such subsequent contracts will depend upon the overall commercial environment for natural gas transportation and consumption in the region in which the pipeline is situated.

Business environment

The North American natural gas infrastructure network has been developed to connect supply basins to market. Use and growth of the systems are affected by changes in the location, relative cost of natural gas supply and changing market demand.

The map below shows the location of certain North American basins in relation to our systems together with those of our General Partner and TC Energy.

Supply

Natural gas is primarily transported from producing regions and, in limited circumstances, from liquefied natural gas (LNG) import facilities to market hubs or interconnects for distribution to natural gas consumers. The ongoing development of shale and other unconventional gas reserves has resulted in increases in overall North American natural gas production and economically recoverable reserves.

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There has been an increase in production from the development of shale gas reserves that are located close to traditional markets, particularly in the Northeastern U.S. This has increased the number of supply choices for natural gas consumers and has contributed to the decline of higher-cost sources of supply (such as certain offshore gas production from Atlantic Canada) resulting in changes to historical natural gas pipeline flow patterns.

The supply of natural gas in North America is expected to continue increasing over the next decade and over the long-term for a number of reasons, including the following:

● •use of technology, including horizontal drilling in combination with multi-stage hydraulic fracturing, is allowing companies to access unconventional resources economically. This is increasing the technically accessible resource base of existing and emerging gas basins; and

● •application of these technologies to existing oil fields where further recovery of the existing resource is now possible. There is often associated natural gas discovered in the exploration and production of liquids-rich hydrocarbons (for example the Bakken oil fields), which also contributes to an increase in the overall natural gas supply for North America.

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hydrocarbons (for example the Bakken oil fields), which also contributes to an increase in the overall natural gas supply for North America.

Other factors that can influence the overall level of natural gas supply in North America include:

● •the price of natural gas – low prices in North America may increase demand but reduce drilling activities that in turn diminish production levels, particularly in dry natural gas fields where the extra revenue generated from the associated liquids is not available. High natural gas prices may encourage higher drilling activities but may decrease the level of demand;

● •producer portfolio diversification – large producers often diversify their portfolios by developing several basins, but this is influenced by actual costs to develop the resource as well as economic access to markets and cost of pipeline transportation services. Basin-on-basin competition impacts the extent and timing of a resource development that, in turn, drives changing dynamics for pipeline capacity demand; and

● •regulatory and public scrutiny – changes in regulations that apply to natural gas production and consumption could impact the cost and pace of development of natural gas in North America.

Demand

The natural gas pipeline business ultimately depends on a shipper’s demand for pipeline capacity and the price paid for that capacity. Demand for pipeline capacity is influenced by, among other things, supply and market competition, economic activity, weather conditions, natural gas pipeline and storage competition and the price of alternative fuels.

The growing supply of natural gas has resulted in relatively low natural gas prices in North America which has supported increased demand for natural gas particularly in the following areas:

● •natural gas-fired power generation;

● •petrochemical and industrial facilities;

● •the production of the Marcellus, Alberta’s oil sands, and the Bakken and shale deposits, although new greenfield projects that have not begun construction may be delayed in the current oil price environment;

● •exports to Mexico to fuel electric power generation facilities; and

● •exports from North America to global markets through a number of proposed LNG export facilities.

Commodity Prices

In general, the profitability of the natural gas pipelines business is not directly tied to commodity prices given we are a transporter of the commodity and the transportation costs are not tied to the price of natural gas. However, the cyclical supply and demand nature of commodities and its price impact can have a secondary impact on our business where our shippers may choose to accelerate or delay certain projects. This can impact the timing for the demand of transportation services and/or new gas pipeline infrastructure.

Competition

Competition among natural gas pipelines is based primarily on transportation rates and proximity to natural gas supply areas and consuming markets. Changes in supply locations and regional demand have resulted in changes to pipeline flow dynamics. Where pipelines historically transported natural gas from one or two supply sources to their markets under long-term contracts, today many pipelines transport gas in multiple directions and under shorter contract terms. Some pipelines have even reversed their flows in order to adapt to changing sources of supply. Competition among pipelines to attract supply and new or existing markets to their systems has also increased across North America.

Our Natural Gas Infrastructure

We have ownership interests in eight natural gas interstate pipeline systems that are collectively designed to transport approximately 1011.93 billion cubic feet per day of natural gas from producing regions and import facilities to market hubs and consuming markets primarily in the Western, Midwestern and Eastern U.S. All our pipeline systems, except Iroquois and the pipeline facilities jointly owned with MNE on PNGTS (Joint Facilities), 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 Joint Facilities are operated by M&N Operating Company, LLC (MNOC), a subsidiary of Maritimes and Northeast Pipeline LLC (MNE). ~~MNE~~on isPNGTS a(Joint ~~subsidiary~~Facilities), ofare ~~Enbridge~~operated ~~Inc.~~by

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subsidiaries of TC Energy. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Joint Facilities are operated by M&N Operating Company, LLC (MNOC),a subsidiary of MNE. MNE is a subsidiary of Enbridge Inc. Our pipeline systems include:


Pipeline		Length		Description	Ownership
Pipeline	Length		Description	Ownership
GTN		1,377 miles		Extends from an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
GTN	1,377 miles		Extends from an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison		303 miles		Extends from a location near Gillette, Wyoming to Northern Border’s pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
Bison	303 miles		Extends from a location near Gillette, Wyoming to Northern Border’s pipeline system in North Dakota. Bison can, but does not currently, transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja		86 miles		Extends from an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona to an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
North Baja	86 miles		Extends from an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona to an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora		305 miles		Extends from the terminus of the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Tuscarora	305 miles		Extends from the terminus of the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border		1,412 miles		Extends from the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Bakken, the Williston Basin and the Rocky Mountain area for deliveries to the Midwest. ONEOK Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border.	50 percent
Northern Border	1,412 miles		Extends from the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Bakken, the Williston Basin and the Rocky Mountain area for deliveries to the Midwest. ONEOK Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border.	50 percent
PNGTS		295 miles		Connects with the TQM pipeline at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS. The 295-mile pipeline includes 107 miles of jointly owned pipeline facilities (the Joint Facilities) with MNE. The Joint Facilities extend from Westbrook, Maine to Dracut, Massachusetts and PNGTS owns approximately 32 percent of the Joint Facilities.	61.71 percent
PNGTS	295 miles		Connects with the TQM pipeline at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS. The 295-mile pipeline includes 107 miles of jointly owned pipeline facilities (the Joint Facilities) with MNE. The Joint Facilities extend from Westbrook, Maine to Dracut, Massachusetts and PNGTS owns approximately 32 percent of the Joint Facilities.	61.71 percent
Great Lakes		2,115 miles		Connects with the TC Energy Mainline at the Canadian border points near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TC Energy owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Great Lakes	2,115 miles		Connects with the TC Energy Mainline at the Canadian border points near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TC Energy owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois		416 miles		Extends from the TC Energy Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by: TC Energy (0.66 percent), Berkshire Hathaway Energy (Berkshire Hathaway) (50 percent)	49.34 percent
Iroquois	416 miles		Extends from the TC Energy Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by: TC Energy (0.66 percent), Dominion Energy, Inc. (Dominion Energy) (50 percent)	49.34 percent

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The map below shows the location of our pipeline systems.

Customers, Contracting and Demand

Our customers are generally large utilities, Local Distribution Companies (LDCs), major natural gas marketers, producing companies and other interstate pipelines, including affiliates. Our systems generate revenue by charging rates for transporting natural gas. Natural gas transportation service is provided pursuant to long-term and short-term contracts on a firm or interruptible basis. The majority of our pipeline systems' natural gas transportation services are provided through firm service transportation contracts with a reservation or demand charge that reserves pipeline capacity, regardless of use, for the term of the contract. The revenues associated with capacity reserved under firm service transportation contracts are not subject to fluctuations caused by changing supply and demand conditions, competition or customers. Customers with interruptible service transportation agreements may utilize available capacity after firm service transportation requests are satisfied.

~~Our pipeline systems actively market their available capacity and work closely with customers~~18 TC PipeLines, ~~including natural gas producers, LDCs, marketers and end users, to ensure our pipelines are offering attractive services and competitive rates. Approximately 70~~ percent of our long-term contract revenues are with customers who have an investment grade rating or who have provided guarantees from investment grade parties. We have obtained financial assurances as permitted by FERC and our tariffs for the remaining long-term contracts. See PartLP ~~I, Item~~Annual ~~1A. “Risk~~Report ~~Factors.”~~2020

Transactions with our major customers that are at least 10 percent of our consolidated revenues can be found under Note 17-Transactions with major customers within Part IV, Item 15. “Exhibits and Financial Statement Schedules," which information is incorporated herein by reference. Additionally, our equity investee Great Lakes earns a significant portion of its revenue from TC Energy and its affiliates as disclosed under Note 18-Related party transactions within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

GTN – GTN’s revenues are substantially supported by long-term contracts through the end of 2023 with its remaining contracts extending between 2024 and 2045. These contracts, which have historically been renewed on a long-term basis upon expiration, are primarily held by residential and commercial LDCs and power generators that use a diversified portfolio of transportation options to serve their long-term markets and marketers under a variety of contract terms. A small portion of our contract portfolio is contracted by industrial shippers and producers. We expect GTN to continue to be an important transportation component of these diversified portfolios. Incremental transportation opportunities are based on the difference in value between Western Canadian natural gas supplies and deliveries to Northern California.

In 2018, GTN benefitted from an increase in the quantity of natural gas it transports as debottlenecking activities occurred on upstream pipeline systems which deliver natural gas to GTN. These upstream activities are continuing and, as a result, we have signed over 700,000 Dth/day in long-term contracts starting between 2018 and 2020, of which 348,000 Dth/day resulted in additional quantity flowing onto GTN mid-2018, and 114,000 Dth/day in the fourth quarter of 2019. The

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~~remaining~~fluctuations ~~quantity~~caused isby ~~expected~~changing tosupply ~~begin~~and todemand ~~flow~~conditions, incompetition ~~mid-2020~~or customers. ~~The~~Customers ~~majority~~with ofinterruptible ~~these~~service ~~contracts~~transportation ~~have~~agreements ~~terms~~may ofutilize atavailable ~~least~~capacity 15after ~~years~~firm service transportation requests are satisfied.

OnOur ~~January~~pipeline ~~29,~~systems ~~2019,~~actively ~~GTN’s~~market ~~largest~~their ~~customer,~~available ~~Pacific~~capacity ~~Gas~~ and ~~Electric~~work ~~Company~~closely ~~(Pacific~~with ~~Gas)~~customers, ~~filed~~including ~~for~~natural ~~Chapter~~gas 11producers, ~~bankruptcy~~LDCs, ~~protection.~~marketers ~~Pacific~~and ~~Gas~~end ~~accounted~~users, ~~for~~to ~~approximately~~ensure ~~seven~~our ~~percent~~pipelines ofare ~~the~~offering ~~Partnership’s~~attractive ~~consolidated~~services ~~revenues~~and incompetitive ~~2019~~rates. ~~(2018~~Approximately ~~- six~~ 74 percent). Asof aour ~~utility~~long-term ~~company,~~contract ~~Pacific~~revenues ~~Gas~~are ~~serves~~with ~~residential and industrial~~ customers inwho ~~the~~have ~~state~~an ofinvestment ~~California~~grade ~~and~~rating ~~has~~or anwho ~~ongoing~~have ~~obligation~~provided toguarantees ~~serve~~from ~~its~~investment ~~customers~~grade parties. We have ~~not~~obtained ~~experienced~~financial ~~collection~~assurances ~~issues~~as inpermitted ~~2019~~by FERC and weour dotariffs ~~not~~for ~~expect~~ the ~~bankruptcy~~remaining oflong-term ~~Pacific~~contracts. ~~Gas~~See toPart I, ~~have~~Item 1A. ~~a material impact on our future cash flows and results of operations~~“Risk Factors.”

~~During~~Transactions ~~the~~with ~~fourth~~our ~~quarter~~major ofcustomers ~~2019,~~that weare ~~announced~~at ~~the~~least ~~GTN~~10 percent ~~XPress~~of ~~project,~~ our ~~largest~~consolidated ~~organic~~revenues ~~opportunity~~can inbe ~~TCP’s~~found 20under Note 16-~~year~~Transactions ~~history.~~with ~~This~~major ~~project~~customers ~~includes~~within aPart IV, ~~horsepower~~Item 15. ~~replacement~~“Exhibits ~~program~~ and aFinancial ~~brownfield~~Statement ~~expansion.~~Schedules," ~~The~~which ~~reliability~~information ~~work~~is ~~will~~incorporated ~~enable~~herein ~~increased~~by reference. ~~firm~~Additionally, ~~natural~~our ~~gas~~equity ~~transportation~~investee onGreat ~~GTN,~~Lakes ~~which~~earns ~~together~~a ~~with~~significant ~~the~~portion ~~growth component~~ of ~~the~~its ~~project,~~revenue ~~will~~from ~~sum~~TC toEnergy ~~250,000~~and ~~Dth/d~~its inaffiliates ~~additional~~as ~~long-term~~disclosed ~~contracts~~under onNote ~~the~~17-Related ~~pipeline~~party ~~system. See~~transactions within Part IIV, Item 115. “~~Business-~~Exhibits ~~Recent~~and ~~Business~~Financial ~~Developments-Growth~~Statement ~~Projects~~Schedules,” ~~for~~which ~~more~~ information is incorporated herein by reference.

~~Northern~~GTN – ~~Border~~GTN’s –revenues ~~Northern~~are ~~Border~~substantially issupported aby ~~highly~~long-term ~~competitive~~contracts ~~pipeline~~through ~~system~~the ~~with~~end aof ~~weighted~~2023 ~~average~~with its remaining ~~contract~~contracts ~~length~~extending ofbetween ~~approximately~~2024 4and ~~years~~2045. ~~Northern~~These ~~Border~~ contracts, ~~that~~which ~~include~~have ~~renewal~~historically ~~rights~~been renewed on a long-term basis upon expiration, are primarily held by residential and ~~expiring~~commercial ~~contracts~~LDCs ~~have~~and ~~typically~~power ~~been~~generators ~~renewed~~that ~~for~~use ~~terms~~a diversified portfolio of ~~five~~transportation ~~years~~options to serve their long-term markets and marketers under a variety of contract terms. A ~~significant~~ portion of ~~Northern Border’~~GTN's contract portfolio is contracted by ~~utilities,~~industrial ~~marketers~~shippers and ~~industrial load~~producers. InWe ~~addition,~~expect ~~Northern~~GTN ~~Border~~to ~~sells~~continue ~~seasonal~~to ~~transportation~~be ~~services~~an ~~which~~important ~~have~~transportation ~~traditionally~~component ~~been~~of ~~strongest~~these ~~during~~diversified ~~peak~~portfolios. ~~winter~~Incremental ~~months~~transportation toopportunities ~~serve~~are ~~heating~~based ~~demand~~on ~~and~~the ~~peak~~difference ~~spring/summer~~in ~~months~~value tobetween ~~serve~~Western ~~electric~~Canadian ~~cooling~~natural ~~demand~~gas supplies and ~~storage~~deliveries ~~injection~~to Northern California.

Upstream debottlenecking on TC Energy's NGTL System, which delivers natural gas to GTN, has allowed GTN to sign over 700,000 Dth/day in long-term contracts with in-service dates between 2018 and 2020. The majority of these contracts have terms of at least 15 years.

During the fourth quarter of 2019, we announced the GTN XPress Project, the largest organic growth opportunity in the Partnership's 20-year history. This project includes a horsepower replacement program and a brownfield expansion. The reliability work will enable increased firm natural gas transportation on GTN, which together with the growth component of the project, will sum to 250,000 Dth/d in additional long-term contracts on the pipeline system. See Part I, Item 1. “Business- Recent Business Developments-Growth Projects Update” for more information.

In early 2019, GTN’s largest customer, Pacific Gas and Electric Company (Pacific Gas), filed for Chapter 11 bankruptcy protection. On July 1, 2020, Pacific Gas emerged from its bankruptcy proceedings. Pacific Gas accounted for approximately seven percent of the Partnership’s consolidated revenues in 2020 (2019 - seven percent). As a utility company, Pacific Gas serves residential and industrial customers in the state of California and has an ongoing obligation to serve its customers. We have not experienced collection issues to date and expect this to continue going forward.

Northern Border – Northern Border is a highly competitive pipeline system with a weighted average remaining contract length of approximately 5 years. Northern Border contracts that include renewal rights and expiring contracts have typically been renewed for terms of five years. A significant portion of Northern Border’s contract portfolio is contracted by utilities, marketers and industrial load. In addition, Northern Border sells seasonal transportation services which have traditionally been strongest during peak winter months to serve heating demand and peak spring/summer months to serve electric cooling demand and storage injection.

Great Lakes – Great Lakes' revenue is derived from both short-haul and long-haul transportation services. The majority of its contracts are with TC Energy and affiliates on multiple paths across its system. Great Lakes' ability to sell its available and future capacity will depend on future market conditions which are impacted by a number of factors including weather, levels of natural gas in storage, the capacity of upstream and downstream pipelines and the availability and pricing of natural gas supplies. Demand for Great Lakes' services has historically been highest in the summer to fill the natural gas storage complexes in Ontario and Michigan in advance of the upcoming winter season. During the winter, Great Lakes serves peak heating requirements for customers in Minnesota, Wisconsin, Michigan and the upper Midwest of the U.S.

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 about 0.711 billion cubic feet ~~(equivalent to about 722,000 Dth/day)~~ of natural gas per day on the Great Lakes system. This contract, ~~which contains volume reduction options up to full contract quantity until November 1, 2020,~~ was a direct benefit from TC Energy’s long-term fixed price service on its Canadian Mainline that was launched in 2017. TC Energy’s long-term fixed price service provides long-term capacity to TC Energy’s shippers for the transportation of WCSB natural gas to markets in Eastern Canada and the U.S. See Part I, Item 1. “Business- Recent Business Developments-Other Business Developments” for more information.

~~During~~In ~~the~~early ~~second quarter of 2018~~2020, ~~Great~~TC ~~Lakes~~Energy ~~reached~~approved ~~an agreement on~~ the ~~terms~~Alberta ofXPress ~~new~~Project, ~~long-term~~an ~~transportation~~expansion ~~capacity~~project ~~contracts~~on ~~with~~ its ~~affiliate,~~ ANR Pipeline ~~Company.~~system ~~The~~with ~~contracts~~an ~~are~~estimated ~~for~~in-service adate ~~term~~ of 152022. ~~years~~This ~~from~~project ~~November~~utilizes ~~2021~~existing toaggregate ~~October~~capacity ~~31,~~on ~~2036~~Great ~~with~~Lakes aSystem ~~total contract value~~ of approximately ~~$1.3 billion on 0.9 billion of cubic feet (equivalent to about 913~~168,000 Dth/day) ~~capacity.~~for ~~The~~a ~~contracts~~term ~~contain~~of ~~reduction~~20 ~~options~~years ~~(i)~~ at ~~any~~maximum ~~time~~rates ~~on or before April 1, 2020~~ for ~~any~~a ~~reason~~total ~~and~~contract ~~(ii)~~value ~~any time before April 2021, if TC Energy is not able to secure the required regulatory approval related to anticipated expansion projects. During the first quarter~~ of ~~2019,~~$182 ~~Great~~million ~~Lakes~~starting ~~reached~~in ~~an agreement to amend a volume reduction “for any reason” option by extending the period “on or before” April 1, 2019 to “on or before” April 1, 2020~~2022. ~~All the other terms remained the same.~~

~~PNGTS~~This –contract, ~~PNGTS’~~which ~~revenues~~has ~~are~~a ~~primarily~~full ~~generated~~quantity ~~from~~reduction ~~transportation~~option ~~agreements~~at ~~with~~any ~~LDCs~~time ~~throughout~~before ~~New~~October ~~England~~1, ~~and~~2022, ~~Canada’s~~is ~~Atlantic~~dependent ~~provinces.~~on ~~The~~ANR's ~~majority~~ability ofto ~~PNGTS’~~secure ~~current~~the ~~revenue~~required ~~stream~~regulatory isapprovals ~~supported~~and byother ~~long-term~~requirements ~~contracts entered into via a series~~ of ~~open~~the ~~seasons~~project ~~for~~associated ~~long-term~~with ~~capacity~~these ~~held~~volumes. bySee ~~PNGTS~~Part inI, ~~recent~~Item ~~years~~1. ~~Long~~“Business-~~term~~ ~~contract~~Recent ~~commitments~~Business ~~of approximately 82,000 Dth/day from PNGTS’ Continent~~Developments-~~to-Coast~~ ~~Contracts~~Growth ~~with~~Projects ~~several~~Update” ~~shippers~~ for amore ~~term of 15 years (the C2C Contracts) open season began December 1, 2017, necessitating an increase in PNGTS’ certificated capacity up to approximately 210,000 Dth/day~~information. ~~The C2C Contracts mature in 2032.~~

~~In addition to the C2C Contracts~~TC PipeLines, in 2017, as a result of its PXP open season, PNGTS executed 20-year precedent agreements with several LDCs in New England and Atlantic Canada to re-contract certain system capacity set to expire in 2019 as well as expand the PNGTS system. PXP Phases I and II were placed into service on November 1, 2018 and November 1, 2019, respectively. Phase III of the project is expected to be in service on November 1, LP Annual Report 2020. The total final volume of the project is approximately 183,000 Dth/ day: 40,000 Dth/day from Phase I, 118,400 Dth/day from Phase II, which includes re-contracting and renewal of expiring contracts, and 24,600 Dth/day from Phase III. PXP, together with the C2C expansion brings additional, natural gas supply options to markets in New England and Atlantic Canada in response to the growing need for natural gas transportation capacity in the region. 19

PXP is fully subscribed with no uncontracted firm capacity to meet incremental market demand in this region. In response, PNGTS developed a second expansion project. In early 2019, PNGTS announced the Westbrook XPress project which is

TC PipeLines, LP Annual Report 2019 17

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anPNGTS ~~independent~~– ~~project~~PNGTS’ ~~that~~revenues isare ~~designed~~primarily togenerated befrom ~~phased~~transportation inagreements ~~over~~with aLDCs ~~four-year~~throughout ~~period~~New ~~beginning~~England ~~November~~and 1,Canada’s ~~2019~~Atlantic ~~with Phase I~~provinces. ~~Phases~~The IImajority ~~and~~of ~~III~~PNGTS’ ~~have~~current ~~estimated~~revenue ~~in-service~~stream ~~dates~~is ofsupported ~~November~~by ~~2021~~long-term ~~and~~contracts ~~2022,~~entered ~~respectively.~~into ~~Westbrook~~via ~~XPress~~a ~~will~~series ~~add~~of ~~incremental~~open ~~capacity~~seasons offor ~~approximately~~long-term ~~43,000~~capacity ~~Dth/day,~~held ~~69,000~~by ~~Dth/day,~~PNGTS ~~and~~in ~~18,000~~recent ~~Dth/day, respectively~~years. ~~Westbrook~~Long-term ~~XPress,~~contracts ~~together~~ with ~~PXP,~~several ~~will~~shippers ~~increase~~involving ~~PNGTS’~~commitments ~~capacity~~of ~~by 90 percent from 210,000 Dth/day to~~ approximately ~~400~~82,000 Dth/day. from PNGTS’ ~~signed~~Continent-to-Coast ~~precedent~~Contracts ~~agreements~~ for ~~Phases~~a IIterm ~~and III~~ of ~~Westbrook~~15 ~~XPress,~~years ~~pending~~(the ~~receipt~~C2C ofContracts) ~~various~~began ~~regulatory~~December ~~and~~1, ~~corporate~~2017, ~~approvals.~~necessitating ~~The~~an ~~Westbrook~~increase ~~XPress~~in ~~contracts~~PNGTS’ ~~expire~~certificated ~~between~~capacity ~~2036~~up ~~and~~to ~~2042. See~~approximately ~~Part I~~210,000 ~~Item 1~~Dth/day. ~~“Business-~~The ~~Recent~~C2C ~~Business~~Contracts ~~Developments-Growth~~mature ~~Projects”~~in ~~for more information about PXP and Westbrook XPress~~2032.

~~Iroquois~~In –addition ~~Iroquois~~to ~~transports~~the ~~natural~~C2C ~~gas~~Contracts, ~~under~~in ~~long-term~~2017, ~~contracts~~as ~~that~~a ~~expire~~result ~~between~~of ~~2019~~its ~~and~~PXP ~~2026~~open ~~and~~season, ~~extends~~PNGTS ~~from~~executed TC20-year ~~Energy’s~~precedent ~~Canadian~~agreements ~~Mainline~~with ~~system~~several atLDCs ~~the~~in ~~U.S.~~New ~~border~~England ~~near~~and ~~Waddington,~~Atlantic ~~New~~Canada ~~York~~to re-contract certain system capacity set to ~~markets~~expire in ~~the~~2019 ~~U.S.~~as ~~northeast,~~well ~~including~~as ~~New~~expand ~~York~~the ~~City,~~PNGTS ~~Long~~system. ~~Island~~PXP Phases I, II and ~~Connecticut. Iroquois~~III ~~provides~~were placed into service toduring ~~local~~the ~~gas~~fourth ~~distribution~~quarter ~~companies~~of 2018, ~~electric~~2019 ~~utilities~~ and ~~electric~~2020, ~~power~~respectively. ~~generators,~~The astotal ~~well~~final asvolume ~~marketers~~of ~~and~~the ~~other~~project ~~end~~is ~~users~~approximately 183,000 ~~directly~~Dth/day: ~~or indirectly~~40,000 ~~through~~Dth/day ~~interconnecting~~from ~~pipelines~~Phase ~~and~~I, ~~exchanges~~118,400 ~~throughout~~Dth/day ~~the~~from ~~northeastern~~Phase ~~U.S.~~II, ~~Iroquois~~which ~~also~~includes ~~earns~~re-contracting ~~discretionary~~and ~~transportation~~renewal ~~service~~of ~~revenues~~expiring ~~which~~contracts, ~~can~~and ~~have~~24,600 aDth/day ~~significant~~from ~~earnings~~Phase ~~impact~~III. ~~Discretionary~~PXP, ~~transportation~~together ~~service~~with ~~revenues~~the ~~include~~C2C ~~short-term~~expansion ~~firm~~brings ~~transportation~~additional, ~~service~~natural ~~contracts~~gas ~~with~~supply ~~less~~options ~~than~~to ~~one-year~~markets ~~terms~~in asNew ~~well~~England asand ~~standard~~Atlantic ~~interruptible~~Canada ~~transportation~~in ~~service~~response ~~contracts.~~to Inthe ~~2019,~~growing ~~Iroquois~~need ~~earned~~for ~~approximately~~natural 12gas ~~percent~~transportation ofcapacity ~~its~~in ~~revenues~~the ~~from discretionary services~~region.

~~During~~PXP ~~the~~is ~~second~~fully ~~quarter~~subscribed ofwith ~~2019,~~no ~~Iroquois~~uncontracted ~~initiated~~firm ~~the~~capacity ~~ExC Project~~ to meet ~~current~~incremental ~~and~~market ~~future~~demand ~~gas~~in ~~supply~~this ~~needs~~region. ofIn ~~utility~~response, ~~customers~~PNGTS bydeveloped ~~upgrading~~a ~~its~~second ~~compressor~~expansion ~~stations~~project. ~~along~~In early 2019, PNGTS announced the ~~pipeline.~~Westbrook ~~This~~XPress Project which is an independent project ~~will~~that is designed to be ~~100~~phased ~~percent~~in ~~underpinned~~over ~~with~~a 20four-year ~~contracts~~period ~~and~~beginning isNovember ~~subject~~1, to2019 ~~necessary~~with ~~permits~~Phase ~~and approvals~~I. ~~This~~Phases ~~project~~II ~~has~~and anIII have estimated in-service ~~date~~dates of November ~~2023~~2021 and 2022, respectively. Westbrook XPress will add incremental capacity for Phases I, II and III of approximately 43,000 Dth/day, 69,000 Dth/day, and 18,000 Dth/day, respectively. Westbrook XPress, together with PXP, will increase PNGTS’ capacity by 90 percent from 210,000 Dth/day to approximately 400,000 Dth/day. The Westbrook XPress contracts expire between 2036 and 2042. See Part I, Item 1. “Business- Recent Business Developments-Growth Projects Update” for more information about PXP and Westbrook XPress.

Iroquois – Iroquois transports natural gas under long-term contracts that expire between 2021 and 2032 and extends from TC Energy’s Canadian Mainline system at the U.S. border near Waddington, New York to markets in the U.S. northeast, including New York City, Long Island and Connecticut. Iroquois provides service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, directly or indirectly, through interconnecting pipelines and exchanges throughout the northeastern U.S. Iroquois also earns discretionary transportation service revenues which can have a significant earnings impact. Discretionary transportation service revenues include short-term firm transportation service contracts with less than one-year terms as well as standard interruptible transportation service contracts. In 2020, Iroquois earned approximately 12 percent of its revenues from discretionary services.

During the second quarter of 2019, Iroquois initiated the ExC Project to meet current and future gas supply needs of utility customers by upgrading its compressor stations along the pipeline. This project will be 100 percent underpinned with 20-year contracts and is subject to the receipt of necessary permits and approvals. This project has an estimated in-service date of November 2023. See Part I, Item 1. “Business- Recent Business Developments-Growth Projects Update” for more information.

North Baja – The North Baja pipeline system is an 86-mile bi-directional natural gas pipeline transporting gas between Arizona, California and the Mexican border since 2002. North Baja’s historical steady financial performance is due to its strong contracting levels, having a weighted average remaining firm contract length of about 7 years. North Baja currently has a design capacity of 500 mcf/d of southbound transportation and is capable of transporting 600 mcf/d in a northbound direction.

In April 2019, we concluded a successful binding open season for North Baja XPress ~~project~~Project to transport approximately 495,000 Dth/day of additional volumes of natural gas along North Baja’s mainline system between Arizona and California. The estimated in-service date of the project is ~~November~~February ~~2022~~2023, subject to ~~the~~regulatory ~~satisfaction~~approvals orand ~~waiver~~other requirements of ~~certain~~the ~~conditions precedent including positive FID from Sempra LNG International, LLC~~project. See Part I, Item 1. “Business- Recent Business Developments-Growth Projects Update” for more information.

Bison – As previously disclosed, natural gas is not flowing on the Bison system in response to the recent relative cost advantage of WCSB and Bakken sourced gas versus Rockies production. From its in-service date in 2011 up to the fourth quarter of 2018, Bison was fully contracted on a ship-or-pay basis. During the fourth quarter of 2018, through a Permanent Capacity Release Agreement, Tenaska Marketing Ventures (Tenaska) assumed Anadarko Energy Services Company’s (Anadarko) ship-or-pay contract obligation on Bison, the largest contract on Bison. After assuming the transportation obligation, Bison accepted an offer from Tenaska to terminate this contract. Following the amendment of its tariff to enable this transaction, another customer executed a similar agreement to terminate its contract on Bison. At the completion of the contracts, Bison was released from performing any future services with the two customers and as such, the amounts received were recorded in revenue in 2018.

The two customers represented approximately 60 percent of Bison’s revenue in 2018 and accordingly, in 2019 and 2020, Bison’s revenue was reduced by approximately $47 million. ~~Its~~and ~~remaining~~$49 ~~contracts~~million, respectively, in ~~the~~comparison ~~system~~to ~~expire~~2018 inrevenues ~~January~~when ~~2021.~~ Bison ~~will~~was ~~therefore~~fully ~~be approximately 40 percent~~ contracted. onIts aremaining ~~ship-or-pay~~contracts ~~basis~~ in ~~2020~~the ~~and~~system isexpire ~~expected to generate approximately $30 million~~ in ~~revenue,~~January ~~similar to 2019~~2021.

Based on this development and other qualitative factors, the Partnership evaluated the remaining carrying value of Bison’s property, plant and equipment at December 31, 2018 and concluded that the entire amount was no longer recoverable, resulting in a non-cash impairment charge during the fourth quarter of 2018. We continue to explore alternative transportation-related options for Bison and we believe commercial potential exists to ~~reverse~~allow ~~the direction of~~ natural gas ~~flow~~transported on Bison ~~for~~to flow in both directions, with the southwest direction involving deliveries onto third party pipelines and ultimately ~~connect~~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. See also Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Estimates” for more information.

Tuscarora – Tuscarora’s revenues are substantially supported by long-term contracts with a weighted average remaining contract length of approximately 5 years. We expect Tuscarora to continue be fully contracted on a long-term basis when its current contracts expire.20 TC PipeLines, LP Annual Report 2020

During the fourth quarter of 2019, we announced that we are proceeding with the Tuscarora XPress project, an expansion project through additional compression capability at an existing Tuscarora facility that is expected to increase capacity by approximately 7 percent by November 2021. Tuscarora XPress is 100 percent underpinned by a 20-year contract. See Part I, Item 1. “Business- Recent Business Developments-Growth Projects” for more information.

18 TC PipeLines, LP Annual Report 2019

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During the fourth quarter of 2019, we announced that we are proceeding with the Tuscarora XPress Project, which is an estimated $13 million expansion project through additional compression capability at an existing Tuscarora facility. Tuscarora XPress is 100 percent underpinned by a 20-year contract and will transport approximately 15,000 Dth/day of additional volumes when completed in November 2021. Tuscarora XPress is expected to generate approximately $2 million in revenue on an annualized basis when fully in service.

Competition

Overall, our pipeline systems generate a substantial portion of their cash flow from long-term firm contracts for transportation services and are therefore insulated from competitive factors during the terms of the contracts. If these long-term contracts are not renewed at their expiration, our pipeline systems face competitive pressures which influence contract renewals and rates charged for transportation services.

GTN and Northern Border, through their respective connections with TC Energy's Foothills systems, and Great Lakes and Iroquois, through their respective connections with TC Energy's Canadian Mainline, compete with each other for WCSB natural gas supply as well as with other pipelines, including the Alliance pipeline and the Westcoast pipeline. Northern Border and Great Lakes compete in their respective market areas for natural gas supplies from other basins as well, such as the Bakken, Rocky Mountain area, Mid-Continent, Gulf Coast, Utica and Marcellus basins. GTN primarily competes with pipelines supplying natural gas into California and Pacific Northwest markets.

Bison competes for deliveries with other pipelines that transport natural gas supplies within and away from the Rocky Mountain area, and gas from the Rocky Mountains that is delivered into the Midwest must compete with gas sourced from the Bakken and Western Canada.

North Baja’s southbound pipeline capacity competes with deliveries of LNG received at the Costa Azul terminal in Mexico. If LNG shipments are received at Costa Azul, North Baja’s northbound capacity competes with pipelines that deliver Rocky Mountain area, Permian and San Juan basin natural gas into the southern California area.

Tuscarora competes for deliveries primarily into the northern Nevada natural gas market with natural gas from the Rocky Mountain area.

PNGTS connects with the TQM pipeline at the Canadian border and shares facilities with the MNE from Westbrook, Maine to a connection with the Tennessee Gas Pipeline System near Boston, Massachusetts. PNGTS competes with LNG supplies and gas flows from Canada and with LNG delivered into Boston. Tennessee Gas Pipeline and Algonquin Gas Transmission also compete with PNGTS for gas deliveries into New England markets.

As noted above, Iroquois, through its connection with TC Energy’s Canadian Mainline System, competes for WCSB natural gas supply with other pipelines. Iroquois connects at five locations with three interstate pipelines (Tennessee Gas, CNG Gas Transmission and Algonquin Gas Transmission) and TC Energy’s Canadian Mainline System near Waddington, New York and provides a link between WCSB natural gas deliveries to markets in the states of Connecticut, Massachusetts, New Hampshire, New Jersey, New York, and Rhode Island.

Additionally, our pipeline assets face competition from other pipeline companies seeking opportunities to invest in greenfield natural gas pipeline development opportunities. This competition could result in fewer projects being available that meet our pipeline systems’ investment hurdles or projects that proceed with lower overall financial returns.

Relationship with TC Energy

TC Energy is the indirect parent of our General Partner and at December 31, ~~2019~~2020, owns, through its subsidiaries, approximately 24 percent of our common units, 100 percent of our Class B units, 100 percent of our IDRs and has a two percent general partner interest in us. TC Energy is a major energy infrastructure company, listed on the Toronto Stock Exchange and NYSE, with more than 65 years of experience in the responsible development and reliable operation of energy infrastructure in North America. TC Energy’s business is primarily focused on natural gas and liquids transmission and power generation services, delivering the energy millions of people rely on to power their lives in a sustainable way. TC Energy consists of investments in 57approximately 58,~~900~~000 miles of natural gas pipelines, approximately 3,000 miles of liquids pipelines and ~~653~~535 billion cubic feet of natural gas storage capacity. TC Energy also owns or has interests in approximately 64,~~000~~200 megawatts of power generation. TC Energy operates most of our pipeline systems and, in some cases, contracts for pipeline capacity.

~~See~~On ~~also~~December ~~Part~~14, ~~III~~2020 the Partnership, ~~Item~~the ~~13.~~General ~~“Certain~~Partner, ~~Relationships~~TC ~~and~~Energy, ~~Related~~TC ~~Transactions~~Northern, TC PipeLine USA, and ~~Director~~Merger ~~Independence”~~Sub, ~~for~~entered ~~more~~into ~~information~~the onTC ~~our~~Energy ~~relationship~~Merger Agreement. Pursuant to the TC Energy Merger Agreement, Merger Sub will be merged with and into the Partnership, with the Partnership continuing as the sole surviving entity and an indirect, wholly owned subsidiary of TC Energy.

Subject to the terms and conditions set forth in the TC Energy Merger Agreement, at the effective time of the TC Energy Merger, each common unit representing a fractional part of the limited partner interests in the Partnership issued and outstanding immediately prior to the effective time of the TC Energy Merger, other than common units owned by TC Energy and its affiliates,

TC PipeLines, LP Annual Report 2020 21

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will be cancelled in exchange for 0.70 shares of TC Energy common shares. See also Part I, Item 1. “Business- Recent Business Developments - Planned Merger with TC Energy" for more information on our Merger Agreement with TC Energy.

Government Regulation

Federal Energy Regulatory Commission

All of our pipeline systems are regulated by FERC under the ~~Natural Gas Act of 1938 (~~NGA) and Energy Policy Act of 2005, which gives FERC jurisdiction to regulate effectively all aspects of our business, including:

● •transportation of natural gas in interstate commerce;

● •rates and charges;

~~TC PipeLines~~•terms of service and service contracts with customers, ~~LP Annual Report 2019 19~~ including counterparty credit support requirements;

~~Table~~•certification and construction of ~~Contents~~new facilities;

●•extension ~~terms~~or abandonment of service and ~~service contracts with customers, including counterparty credit support requirements~~facilities;

●•accounts ~~certification~~ and ~~construction of new facilities~~records;

●•depreciation ~~extension or abandonment of service~~ and ~~facilities~~amortization policies;

●•acquisition ~~accounts~~ and ~~records~~disposition of facilities;

●•initiation ~~depreciation~~ and ~~amortization~~discontinuation ~~policies~~of services; and

●•standards ~~acquisition~~of ~~and~~conduct ~~disposition~~for ofbusiness ~~facilities;~~relations with certain affiliates.

● initiation and discontinuation of services; and

● standards of conduct for business relations with certain affiliates.

Our pipeline systems’ operating revenues are determined based on rate options stated in our tariffs which are approved by FERC. Tariffs specify the general terms and conditions for pipeline transportation service including the rates that may be charged. FERC, either through hearing a rate case or as a result of approving a negotiated rate settlement, approves the maximum rates permissible for transportation service on a pipeline system which are designed to recover the pipeline’s cost-based investment, operating expenses and a reasonable return for its investors. Once maximum rates are set, a pipeline system is not permitted to adjust the maximum rates to reflect changes in costs or contract demand until new rates are approved by FERC. Pipelines are permitted to charge rates lower than the maximum tariff rates in order to compete. As a result, earnings and cash flows of each pipeline system depend on a number of factors including costs incurred, contracted capacity and transportation path, the volume of natural gas transported, and rates charged.

2018 FERC Actions

Background:

During the latter part of 2018, the Partnership completed its regulatory filings to address the issues contemplated by Public Law No. 115-97, commonly known as the ~~Tax Cuts and Jobs Act (~~2017 Tax Act) and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by MLPs (collectively, the 2018 FERC Actions).

Pipelines filing FERC Form No. 501-G had four options:

● Option 1: make a limited NGA Section 4 filing to reduce its rates by the reduction in its cost of service shown in its FERC Form No. 501-G. For any pipeline electing this option, FERC guaranteed a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s FERC Form 501-G showed the pipeline’s estimated return on equity (ROE) as being 12 percent or less. Under the Final Rule and notwithstanding the Revised Policy Statement, a pipeline organized as an MLP is not required to eliminate its income tax allowance, but instead can reduce its rates to reflect the reduction in the maximum corporate tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance, along with its Accumulated Deferred Income Tax (ADIT) used for rate-making purposes. In situations where the ADIT balance is a liability, this elimination would have the effect of increasing the pipeline’s rate base used for rate-making purposes;

● Option 2: commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believed that using the limited Section 4 option would not result in just and reasonable rates. If the pipeline committed to file by December 31, 2018, FERC would not initiate a Section 5 investigation of its rates prior to that date;

● Option 3: file a statement explaining its rationale for why it did not believe the pipeline's rates must change; or

● Option 4: take no action. FERC would then consider whether to initiate a Section 5 investigation of any pipeline that had not submitted a limited Section 4 rate filing or committed to file a general Section 4 rate case.

Impact of the 2018 FERC Actions to the Partnership:

The 2018 FERC Actions directly addressed two components of our pipeline systems’ cost-of-service based rates: the allowance for income taxes and the inclusion of ADIT in their rate base. The 2018 FERC Actions also noted that precise treatment of entities with more ambiguous ownership structures must be separately resolved on a case-by-case basis, such as those partially owned by corporations including Great Lakes, Northern Border, Iroquois and PNGTS. Additionally, any FERC-mandated rate reduction did not affect negotiated rate contracts. Prior to the 2018 FERC Actions, none of the Partnership’s pipeline systems had a requirement to file or adjust their rates earlier than 2022 as a result of their existing rate settlements. However, several of our pipeline systems accelerated such adjustments as a result of the 2018 FERC Actions. The resulting impact from the actions taken by our pipelines to address the 2018 FERC Actions requirements are outlined below:

20 22 TC PipeLines, LP Annual Report ~~2019~~2020

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Prior to the 2018 FERC Actions, none of the Partnership’s pipeline systems had a requirement to file or adjust their rates earlier than 2022 as a result of their existing rate settlements. However, several of our pipeline systems accelerated such adjustments as a result of the 2018 FERC Actions. The actions taken by our pipelines are outlined below:

2018 FERC Actions Impact on Maximum Rates

Moratorium, Mandatory
Filing Requirements and
Other Considerations

Great Lakes

2.0% rate reduction effective February 1, 2019

No moratorium in effect; comeback provision with new rates to be effective by October 1, 2022

GTN

A refund of $10 million to its firm customers in 2018; 10.0% rate reduction effective January 1, 2019; additional rate reduction of 6.6% effective January 1, 2020 through December 31, 2021; these reductions will replace the 8.3% rate reduction in 2020 agreed to as part of the last settlement in 2015

Moratorium on rate changes until December 31, 2021; comeback provision with new rates to be effective by January 1, 2022; Settlement agreement reflected an elimination of income tax allowance and ADIT

Northern Border

2.0% rate reduction effective February 1, 2019 to December 31, 2019 extended until July 1, 2024 unless superseded by a subsequent rate case or settlement

No moratorium in effect; comeback provision with new rates to be effective by July 1, 2024

Bison

No rate changes proposed

No moratorium or comeback provisions

Iroquois

3.25% rate reduction effective March 1, 2019; additional 3.25% rate reduction effective April 1, 2020

Moratorium on rate changes until September 1, 2020; comeback provision with new rates to be effective by March 1, 2023

PNGTS

No rate changes

No moratorium or comeback provisions

North Baja

10.8% rate reduction effective December 1, 2018

No moratorium or comeback provisions; approximately 90 percent of North Baja’s contracts are negotiated; 10.8% reduction is on maximum rate contracts only

Tuscarora

1.7% rate reduction effective February 1, 2019; additional rate reduction of 10.8% effective August 1, 2019

Moratorium on rate changes until January 31, 2023; comeback provision with new rates to be effective by February 1, 2023; Settlement agreement reflected an elimination of income tax allowance and ADIT


	Form 501-G Filing Option	Impact on Maximum Rates	Moratorium, MandatoryFiling Requirements andOther Considerations
Great Lakes	Option 1; reflected an elimination of income tax allowance and ADIT; Limited Section 4 accepted by FERC; 501-G Docket remains open	2.0% rate reduction effective February 1, 2019	No moratorium in effect; comeback provision with new rates to be effective by October 1, 2022
GTN	Settlement approved by FERC on November 30, 2018 eliminated the requirement to file Form 501-G	A refund of $10 million to its firm customers in 2018; 10.0% rate reduction effective January 1, 2019; additional rate reduction of 6.6% effective January 1, 2020 through December 31, 2021; these reductions will replace the 8.3% rate reduction in 2020 agreed to as part of the last settlement in 2015	Moratorium on rate changes until December 31, 2021; comeback provision with new rates to be effective by January 1, 2022; Settlement agreement reflected an elimination of income tax allowance and ADIT
Northern Border	Option 1; reflected an elimination of income tax allowance and ADIT; subsequent settlement approved by FERC on May 24, 2019; 501-G docket closed	2.0% rate reduction effective February 1, 2019 to December 31, 2019 extended until July 1, 2024 unless superseded by a subsequent rate case or settlement	No moratorium in effect; comeback provision with new rates to be effective by July 1, 2024
Bison	Option 3; reflected an elimination of income tax allowance and ADIT; accepted by FERC; 501-G docket closed	No rate changes proposed	No moratorium or comeback provisions
Iroquois	Option 3; reflected an elimination of income tax allowance and ADIT; subsequent settlement approved by FERC on May 2, 2019; 501-G docket closed	3.25% rate reduction effective March 1, 2019; additional 3.25% rate reduction effective April 1, 2020	Moratorium on rate changes until September 1, 2020; comeback provision with new rates to be effective by March 1, 2023
PNGTS	Option 3; reflected an elimination of income tax allowance and ADIT; accepted by FERC; 501-G docket closed	No rate changes	No moratorium or comeback provisions
North Baja	Option 1; reflected an elimination of income tax allowance and ADIT; accepted by FERC; 501-G docket closed	10.8% rate reduction effective December 1, 2018	No moratorium or comeback provisions; approximately 90 percent of North Baja’s contracts are negotiated; 10.8% reduction is on maximum rate contracts only
Tuscarora	Option 1; reflected an elimination of income tax allowance and ADIT; subsequent settlement approved by FERC on May 2, 2019; 501-G docket closed	1.7% rate reduction effective February 1, 2019; additional rate reduction of 10.8% effective August 1, 2019	Moratorium on rate changes until January 31, 2023; comeback provision with new rates to be effective by February 1, 2023; Settlement agreement reflected an elimination of income tax allowance and ADIT

The Final Rule allowed pipelines owned by MLPs and other pass through entities to remove the ADIT liability from their rate bases, and thus increase the net recoverable rate base, partially or in some cases wholly mitigated the loss of the tax allowance in cost-of-service based rates. Following the elimination of the tax allowance and the ADIT liability from rate base, rate settlements and related filings of all pipelines held wholly or in part by the Partnership summarized above, the estimated impact of the tax-related changes to our revenue and cash flow is a reduction of approximately $30 million per year on an annualized basis beginning in 2019.

In 2019 and 2020, the estimated impact of the tax-related changes to our revenue and cashflow have been largely mitigated by additional revenue generated from continued strong natural gas flows mainly out of WCSB and from solid contracting levels across the Partnership pipeline assets. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information.

~~TC PipeLines, LP Annual Report 2019 21~~Existing rate settlements:

~~Table~~GTN – On October 16, 2018, GTN filed an uncontested settlement with FERC to address the changes proposed by the 2018 FERC Actions on its rates via an amendment to its prior 2015 settlement (the 2018 GTN Settlement). The 2018 GTN Settlement reflects an elimination of ~~Contents~~the tax allowance previously recovered in rates along with ADIT for rate-making purposes (see details of the 2018 GTN Settlement in the table above).

~~Filings~~Tuscarora ~~required~~– On March 15, 2019, Tuscarora filed an uncontested settlement with FERC to address the issues contemplated by the ~~Final~~2017 ~~Rule~~Tax Act and ~~Rate~~2018 ~~Settlements:~~FERC Actions via an amendment to its prior 2016 settlement (the 2019 Tuscarora Settlement).

GTN

On October 16, 2018, GTN filed an uncontested settlement with FERC to address the changes proposed by the 2018 FERC Actions on its rates via an amendment to its prior 2015 settlement (the 2018 GTN Settlement). The 2018 GTN Settlement reflects an elimination of the tax allowance previously recovered in rates along with ADIT for rate-making purposes (see details of the 2018 GTN Settlement in the table above).

Tuscarora

On December 6, 2018, Tuscarora elected to make a limited NGA Section 4 filing to reduce its maximum rates by approximately 1.7 percent and eliminate its deferred income tax balances previously used for rate setting (Option 1). On March 15, 2019, Tuscarora filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (the 2019 Tuscarora Settlement).

Among the terms of the 2019 Tuscarora Settlement, Tuscarora agreed to reduce its existing maximum system rates by 1.7 percent effective February 1, 2019 through to July 31, 2019, followed by an additional decrease of 10.8 percent for the period August 1, 2019 through the term of the settlement. Tuscarora is required to have new rates in effect on February 1, 2023. Tuscarora and its customers also agreed on a moratorium on rate changes until January 31, 2023. The 2019 Tuscarora Settlement, which was approved by FERC on May 2, 2019, will also reflect an elimination of the tax allowance previously recovered in rates along with ADIT for rate-making purposes.

~~Iroquois~~TC PipeLines, LP Annual Report 2020 23

OnTable December 6, 2018, Iroquois submitted its FERC Form No. 501-G in response to the FERC Final Rule along with an explanation as to why rate changes were not required. On February 28, 2019, Iroquois filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (the 2019 Iroquois Settlement). Among the terms of the 2019 Iroquois Settlement, Iroquois agreed to reduce its existing maximum system rates by 6.5 percent to be implemented in two phases, (i) effective March 1, 2019, a 3.25 percent rate reduction and (ii) effective April 1, 2020, an additional 3.25 percent rate reduction, which will conclude the total 6.5 percent rate reduction from the 2016 settlement rates. The 2019 Iroquois Settlement, which was approved by FERC on May 2, 2019, preserved the 2016 settlement moratorium on further rate changes until September 1, 2020. Unless superseded by a subsequent rate case or settlement, Iroquois will be required to have new rates in effect by March 1, 2023.Contents

~~Existing~~Iroquois ~~Settlements~~– On February 28, 2019, Iroquois filed an uncontested settlement with ~~subsequent~~FERC ~~limited~~to ~~section~~address 4the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (the 2019 Iroquois Settlement). Among the terms of the 2019 Iroquois Settlement, Iroquois agreed to reduce its existing maximum system rates by 6.5 percent to be implemented in two phases, (i) effective March 1, 2019, a 3.25 percent rate ~~reductions~~reduction and (ii) effective April 1, 2020, an additional 3.25 percent rate reduction, which will conclude the total 6.5 percent rate reduction from the 2016 settlement rates. The 2019 Iroquois Settlement, which was approved by FERC on May 2, 2019, preserved the 2016 settlement moratorium on further rate changes until September 1, 2020. Unless superseded by a subsequent rate case or settlement, Iroquois will be required to have new rates in effect by March 1, 2023.

Great Lakes – Great Lakes operates under a settlement approved by FERC effective January 1, 2018 (the 2017 Great Lakes Settlement). The 2017 Great Lakes Settlement did not contain a moratorium and eliminated its revenue sharing mechanism with customers. Great Lakes is required to file new rates effective October 1, 2022. Effective February 1, 2019, FERC approved an additional 2 percent rate reduction and elimination of its tax allowance and ADIT liability from rate base pursuant to Great Lakes’ limited NGA Section 4 filing. The removal of ADIT increased net recoverable rate base and mitigated the loss of Great Lakes’ tax allowance.

Northern Border – Northern Border operates under a settlement approved by FERC effective January 1, 2018 (the 2017 Northern Border Settlement). The 2017 Northern Border Settlement provided for tiered rate reductions from January 1, 2018 to December 31, 2019 that equate to an overall rate reduction of 12.5 percent when compared to 2017 rates by January 1, 2020 (10.5 percent by December 31, 2019 and additional two percent by January 1, 2020). The 2017 Northern Border Settlement did not contain a moratorium and Northern Border is required to file new rates effective July 1, 2024. Effective February 1, 2019, FERC approved an additional two percent rate reduction and elimination of its tax allowance and ADIT liability from rate base pursuant to Northern Border’s limited NGA Section 4 filing. On April 4, 2019, Northern Border filed an amended settlement agreement that extended the two percent rate reduction implemented on February 1, 2019 to July 1, 2024 effective January 1, 2020 unless superseded by a subsequent rate case or settlement. On May 24, 2019, FERC approved the amended settlement agreement and Northern Border’s 501-G proceeding was terminated. The removal of ADIT increased net recoverable rate base and mitigated the loss of Northern Border’s tax allowance.

Bison – Bison operates under the rates approved by FERC in connection with Bison's initial construction and has no requirement to file a new rate proceeding.

North Baja – North Baja operates under the rates approved by FERC in its original certificate proceeding in 2001 and has no requirement to file a new rate proceeding. Effective December 1, 2019, FERC approved a 10.8 percent rate reduction and elimination of its tax allowance and ADIT liability from rate base pursuant to North Baja’s limited NGA Section 4 filing. The removal of ADIT increased net recoverable rate base and partially mitigated the loss of North Baja’s tax allowance.

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PNGTS – PNGTS operates under the rates approved by FERC in PNGTS’ most recent rate proceeding, effective December 1, 2010. PNGTS has no requirement to file a new rate proceeding.

Policy Statement on Return on Equity

FERC issued a Policy Statement on May 21, 2020, regarding the determination of the return on equity (ROE) to be used in designing natural gas and oil pipeline rates. In the Policy Statement, FERC determined that its analysis of the ROE component of a pipeline’s rates should be determined by averaging the results of the Discounted Cash Flow model and the Capital Asset Pricing Model. FERC determined that it will not use the Risk Premium Model. Our pipelines are subject to rate regulation by FERC and any future rate cases we file are subject to the determinations in this Policy Statement. We do not expect changes in this policy to affect us in a materially different manner than other similarly sized natural gas pipeline companies operating in the United States.

NOI on Certificate Policy Statement

FERC issued a Notice of Inquiry on April 19, 2018 (Certificate Policy Statement NOI), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Certificate Policy Statement NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. ~~Any~~No ~~proposed~~further ~~changes~~action tohas ~~the~~occurred ~~current~~since ~~policy~~the ~~will~~Certificate bePolicy ~~prospective~~Statement ~~only~~NOI ~~and~~was ~~it is expected that FERC will take many months to determine whether there will be any changes to proposed natural gas pipeline projects~~issued. We do not expect changes in this policy to affect us in a materially different manner than other similarly sized natural gas pipeline companies operating in the United States.

Environmental Matters

Our assets are subject to a variety of stringent U.S. federal, tribal, state and local environmental laws and regulations relating to air quality, biodiversity, wastewater discharges, waste management, water management, and water quality. These laws and regulations generally require natural gas pipeline companies to obtain and comply with a variety of environmental registrations, licenses, permits and other authorizations required for construction and operations. Consequences of noncompliance with these laws, regulations, or authorizations include, but are not limited to, the following: administrative, civil, and/or criminal penalties; imposition of investigatory, remedial, and/or corrective actions; delay in obtaining necessary authorizations; denial or termination of project authorizations; imposition of restrictions or limitations on project authorizations; addition or removal of conditions or terms in project authorizations; and/or the issuance of orders limiting or prohibiting operations or construction. Violations of certain environmental laws and regulations can result in the imposition of strict, joint and several liability.

~~Federal Environmental Laws and Regulations~~24 TC PipeLines, LP Annual Report 2020

Federal environmental laws, and their related regulations, that most significantly impact our pipeline operations include:

● the Clean Air Act (CAA), which regulates air pollution on a national level by restricting the emission of air pollutants from various stationary and mobile sources and imposes an array of pre-construction, operational, monitoring, and reporting requirements. The CAA authorizes the EPA to adopt climate change regulatory initiatives relating to greenhouse gas (GHG) emissions;

● the Federal Water Pollution Control Act, also known as the Clean Water Act (CWA), which regulates discharges of pollutants into state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected “Waters of the United States” (WOTUS);

● the Oil Pollution Act of 1990 (OPA), which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and damages arising from an oil spill in WOTUS;

● the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA), which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

● the Resource Conservation and Recovery Act (RCRA), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;

● the Toxic Substances Control Act (TSCA), which governs the production, importation, use and disposal of specific chemicals and provides the EPA with authority to require reporting, record-keeping and testing requirements, and restrictions relating to chemical substances and mixtures, including polychlorinated biphenyls (PCBs), asbestos, radon, and lead-based paint;

● the Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories;

● the Endangered Species Act (ESA), which restricts activities that may affect federally identified endangered and threatened species or their habitats by the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; and

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●licenses, ~~the~~permits ~~National~~and ~~Environmental~~other ~~Policy~~authorizations ~~Act~~required ~~(NEPA)~~for construction and operations. Consequences of noncompliance with these laws, ~~which~~regulations, ~~requires~~or ~~federal~~authorizations ~~agencies~~include, tobut ~~evaluate~~are not limited to, the ~~environmental~~following: ~~effects~~administrative, civil, and/or criminal penalties; imposition of ~~major~~investigatory, ~~agency~~remedial, and/or corrective actions; delay in obtaining necessary authorizations; denial or termination of project authorizations; imposition of restrictions or limitations on project authorizations; addition or removal of conditions or terms in project authorizations; and/or ~~prepare~~the ~~environmental~~issuance ~~assessments~~of ~~(EAs)~~orders limiting or ~~more~~prohibiting ~~detailed~~operations or construction. Violations of certain environmental ~~impact~~laws ~~statements~~and ~~(EISs)~~regulations ~~that~~can ~~may~~result bein ~~made~~the ~~available~~imposition ~~for~~of ~~public~~strict, ~~review~~joint and ~~comment~~several liability.

Federal Environmental Laws and Regulations

Federal environmental laws, and their related regulations, each as amended from time to time, that most significantly impact our pipeline operations include:

•the Clean Air Act (CAA), which regulates air pollution on a national level by restricting the emission of air pollutants from various stationary and mobile sources and imposes an array of pre-construction, operational, monitoring, and reporting requirements. The CAA authorizes the EPA to adopt climate change regulatory initiatives relating to greenhouse gas (GHG) emissions;

•the Federal Water Pollution Control Act, also known as the Clean Water Act (CWA), which regulates discharges of pollutants from facilities into state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected “Waters of the United States” (WOTUS);

•the Oil Pollution Act of 1990 (OPA), which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and damages arising from an oil spill in WOTUS;

•the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA), which imposes liability on generators, transporters, disposers and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

•the Resource Conservation and Recovery Act (RCRA), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;

•the Toxic Substances Control Act (TSCA), which governs the production, importation, use and disposal of specific chemicals and provides the EPA with authority to require reporting, record-keeping and testing requirements, and restrictions relating to chemical substances and mixtures, including polychlorinated biphenyls (PCBs), asbestos, radon, and lead-based paint;

•the Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories;

•the Endangered Species Act (ESA), which restricts activities that may affect federally identified endangered and threatened species or their habitats by the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; and

•the NEPA, which requires federal agencies to evaluate the environmental effects of major agency actions and prepare environmental assessments (EAs) or more detailed environmental impact statements (EISs) that may be made available for public review and comment.

Regional, State, Tribal, and Local Environmental Laws and Regulations

In addition to the numerous environmental laws and regulations at the federal level, there ~~are~~exist ~~also~~ regional, state, tribal, and local environmental laws and regulations that sometimes make permitting, development, or expansion of certain projects more extensive and complex. For example, some of our projects may require the acquisition of permits from more than one level of government. Additionally, regional, state, tribal, or local laws and regulations may be more stringent than their federal counterparts. The existence of environmental laws at various levels of government also provide more opportunities for citizens’ suits or other forms of opposition to new developmental projects or the expansion of existing projects. These factors all have the potential to substantially restrict or delay project permitting, development, or expansion of projects and increase costs to ~~the~~gas ~~Partnership~~pipeline ~~in the process. See Risk Factors under Part I~~companies, ~~Item 1A of this Form 10 K for further discussion on environmental laws and regulations,~~ including ~~with~~the ~~respect to climate change~~Partnership, ~~including~~in ~~methane~~the ~~and other GHG emissions, ozone standards, site remediation; and other regulations relating to environmental protection~~process.

Judicial Decisions, Enforcement Policies, Executive Actions

In addition to the adoption and implementation of federal and state environmental laws and regulations, judicial decisions interpreting those laws and regulations, enforcement policies as well as the issuance of executive actions at all levels of government can also significantly increase operational or compliance costs for gas pipeline companies. Uncertainty surrounding the interpretation of certain laws and regulations due to conflicting rulings on environmental issues in a given court system may be an added burden on operations and compliance-related decision-making.

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Notably, President Biden issued several executive orders on his first day in office on January 20, 2021, including an Executive Order (EO) for Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis. The EO directs agencies to review agency actions promulgated, issued, or adopted between January 20, 2017 and January 20, 2021, for consistency with the public health and environmental protection policy goals of the EO. If inconsistent, the EO directs agencies to consider suspending, revising, or rescinding the agency actions. Several federal environmental regulations of interest to our business, and which are discussed in this section, are subject to review under the EO, including the Navigable Waters Protection Rule and air/GHG emissions regulations. Specifically, the EO directed EPA to review its recent methane technical amendment to the NSPS for stationary sources and to propose revisions to existing source standards by September 2021.

The new Administration’s chief of staff also issued a memorandum regarding a Regulatory Freeze Pending Review on January 20, 2021, to the heads of executive departments and agencies. Notably, the regulatory freeze asks department and agency heads to consider postponing the effective date of rules which have already been published in the Federal Register, and subsequently opening a comment period and reconsidering the rule as needed. The USACE’s reissuance of the NWPs and the USFWS’s new MBTA rule are subject to reconsideration under this memorandum.

Notable Water-Related Environmental Developments Potentially Impacting the Partnership

While constructing, maintaining, repairing, and/or replacing pipelines and related facilities, there may be a discharge of pollutants and/or dredged or fill material into WOTUS. Such activities are regulated under the CWA and may require special authorization from the EPA, USACE and/or States such as a CWA Section 401 water quality certification, CWA Section 402 National Pollutant Discharge Elimination System (NPDES) permit, and/or a CWA Section 404 permit for discharge of dredge or fill material, such as Nationwide Permit (NWP) 12. In 2020, the CWA was in the national spotlight with numerous high-profile regulatory actions and litigation related to the definition of WOTUS (the scope of waters federally regulated under the CWA), CWA Section 404’s NWP program, and the CWA Section 401 water quality certification process. The reversal in whole or in part of any of these regulatory actions may have a material impact on the Partnership’s business through, for example, increased compliance-related costs, project permitting delays, and more.

The Navigable Waters Protection Rule, issued under former President Trump’s administration and the most recent regulation defining the scope of waters under CWA jurisdiction, WOTUS, became effective on June 22, 2020. This rule replaces the 2015 Clean Water Rule issued under former President Obama’s administration by narrowing the definition of WOTUS and significantly reducing the number of federally regulated bodies of water. The expansion and narrowing of the definition of WOTUS has been a controversial and longstanding issue. A narrowing of the definition is favorable for the pipeline industry since it reduces the number of pipeline projects subject to burdensome and costly CWA regulation and permitting programs by limiting affected waters subject to protection under the CWA. This rule is currently being challenged in high profile cases in federal courts throughout the country. While the new rule is favorable to our industry, it’s tenure may be curtailed if there are successful court challenges and President Biden's administration, with its robust environmental protection agenda, chooses to again expand the definition of WOTUS through rulemaking.

While constructing, maintaining, repairing, and/or replacing our pipelines and related facilities, our activities may discharge dredged or fill material into WOTUS and, in effect, may require a USACE CWA Section 404 individual or general permit. NWPs are general permits issued by USACE to streamline the authorization of activities that result in no more than minimal individual and cumulative adverse environmental effects. If the environmental impact is not minimal, the regulated community may need to apply for the more time-consuming and burdensome individual permits that evaluate discharge activities on a case-by-case basis. Historically, NWP 12 has been specifically used by utilities, including oil and gas pipelines, telecommunications lines, sewage lines, water lines, and more. The CWA Section 404 NWP Program has been under the national spotlight since April 15, 2020, when a Montana federal District Court ruled against TC Energy’s use of an allegedly invalid NWP 12 for its Keystone XL project and enjoining the USACE from issuing NWP 12s for utility activities nationwide. The Court believed the USACE violated the ESA when it renewed NWP 12 in 2017 and remanded NWP 12 back to the USACE to remedy the identified issue. The U.S. Supreme Court granted an emergency stay of the district court’s order, except as it applied to Keystone XL, while the decision’s merits were being appealed in the Ninth Circuit Court of Appeals by the federal defendants. This ongoing litigation has created tremendous uncertainty within the pipeline industry regarding the scope of pipeline activities still allowed to use NWP 12 and concern over the potential material, long-term harms to pipeline projects throughout the country if the appeal of the district court’s order in the Ninth Circuit is unsuccessful. In response to the uncertainty, many pipeline companies, including ourselves, had to reconsider permitting strategies for projects that were depending on the use of NWP 12. For example, companies have incurred additional costs and project delays by switching to alternative nationwide permits or the significantly more time-consuming individual permits. In some cases, companies have had to assume some risk in continuing to use NWP 12, particularly for those projects already in the construction phase. Other pipeline companies have also been challenged in federal courts throughout the country on similar NWP 12 grounds, indicating an increasing litigation risk to the Partnership’s continued use of NWP 12, and potentially other NWPs.

After the Keystone XL NWP 12 District Court decision, the USACE began rulemaking to reissue or renew the 2017 NWPs, including NWP 12, which are set to expire in 2022. On January 13, 2021, a final rule was published reissuing and modifying 12 of the existing NWPs, including NWP 12, and issuing four new NWPs. The rulemaking notably did not remedy the District Court’s identified ESA non-compliance that was central to the legal dispute. The reissuance also included a restructured NWP 12 that separated utilities covered under the permit into three NWPs, with the more contentious oil and gas pipelines isolated from the rest.

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The rule is effective March 15, 2021. Under President Biden's administration, the NWP reissuance rulemaking and the underlying issues in the Keystone XL NWP 12 litigation may be reconsidered in an unfavorable manner to the oil and gas pipeline industry. Additionally, the NWP reissuance may be subject to the regulatory freeze pending the review described in the Biden Administration’s January 20, 2021 memorandum. With uncertainty surrounding the use of NWP 12 for pipeline projects nationwide, particularly growth projects, the Partnership may be materially affected by experiencing project permitting delays and increased vulnerability to lawsuits. However, TC Energy continues to explore creative permitting strategies to minimize and mitigate the additional risks posed by the current regulatory uncertainty.

Furthermore, the EPA’s final rule amending regulations implementing Section 401 of the CWA, which requires states and/or authorized tribes to grant, deny, or waive a water quality certification for major federal licenses and permits, became effective on September 11, 2020. The new rule clarifies various aspects of the current Section 401 regulations, and notably narrows the scope of state and tribal review to preclude them from considering issues other than water quality in their certifications of permits and to curtail delays in decision-making. This rule is very beneficial for the permitting of our pipeline projects but is another such rule that, as expected, is being challenged heavily in court. It is imperative that the Section 401 certification process not cause additional uncertainty and delays that may cause additional material compliance costs to the Partnership and make execution of our various projects more difficult. The success of this final rule is important for our business and is something that will continue to be monitored so that the extent of the impacts to our business can be better understood.

Notable Species-Related Environmental Developments Potentially Impacting the Partnership – Environment (Species)

In 2020, the USFWS developed a rule which notably clarifies that criminal liability under the MBTA will apply only to actions “directed at” migratory birds, its nests, or its eggs and not lawful activities, such as pipeline facility construction, maintenance, repair, and related activities, which inadvertently result in the “incidental take” of migratory birds. This controversial rulemaking is very beneficial to pipeline companies, including the Partnership, since it reduces regulatory burdens, pipeline construction complications and obstacles, and mitigates criminal liability from construction activities which unintentionally impact migratory birds. The rule was finalized in December 2020 and will be effective February 8, 2021. However, it is one of the agency actions that may be subject to the regulatory freeze pending the review described in President Biden's Administration’s January 20, 2021 memorandum. The Partnership may be materially affected if the administration reverts back to the original interpretation that incidental take is not free of liability, in addition to expanding the lists of protected threatened and endangered wildlife and plants under the ESA. Additionally, in December 2020, former President Trump's administration finalized two noteworthy ESA rules. In one rule, the USFWS and NMFS established a definition for “habitat” for the sole purpose of designating critical habitat. In another rule, the USFWS identified several factors that may be considered when determining whether to exclude certain lands from critical habitat designations, including economic impacts. The latter rule allows an area to be excluded from critical habitat designation if the benefits of exclusion outweigh the benefits of inclusion for that area (as long as the exclusion does not cause species extinction). While this rule is favorable to industry, particularly pipeline companies, it is also expected to be reconsidered by President Biden's administration.

Notable Air-Related Environmental Developments Potentially Impacting the Partnership

Federal and State non-GHG Air Pollutant Regulations

In 2020, the EPA, under former President Trump's administration proposed and promulgated several air-related rules under the federal CAA that were met with significant opposition from environmental advocacy groups as well as state and local governments. For example, the EPA made the controversial decision in 2020 to retain, without revision the National Ambient Air Quality Standards (NAAQS) for ground level Ozone and Particulate Matter, that were established in 2015 by former President Obama's administration. The decision to not make these standards more stringent were highly criticized by environmental advocacy groups as well as state and local governments and are currently being challenged in federal court. President Biden's administration is likely to reconsider the rulemaking and could make the standards more stringent. There was similar opposition to EPA’s November 2020 withdrawal of the “Once in Always in” policy requiring sources of hazardous air pollutants (HAPs) that were once considered a “major source” of HAPs to be subject to the more stringent emissions standards even if the source reduces its emissions below the “major source” threshold later. These EPA actions are very beneficial to industry since they reduce our regulatory burdens and compliance-related costs, however the rules, in their current form, may not be permanent with the pending litigation challenging the rules and President Biden's aggressive climate protection agenda. These air regulations are subject to review under the January 20, 2021 EO.

Furthermore, the State of Oregon’s development and implementation of its 2021 air quality protection plan in furtherance of the federal Regional Haze Rule may have a material impact on the Partnership. The EPA’s Regional Haze Rule requires states to improve visibility in national parks and wilderness within their jurisdictions by identifying sources of emissions and reasonable control methods to improve visibility. In the development phase of its state plan, the Oregon Department of Environmental Quality (ODEQ) has identified two GTN stations with turbines that may require GTN to incur material capital expenditures related to installation of emissions controls under the final state plan.

Federal Climate Change and Greenhouse Gas (GHG) Emissions Regulation

The threat of climate change continues to attract considerable attention in the U.S. and throughout the globe. The spotlight on GHG regulation as a means to combat climate change is expected to continue to increase compliance, construction, and operating costs for pipeline companies, including the Partnership, particularly under President Biden's aggressive climate change

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agenda, which included the issuance of a slate of executive orders within his first week in office demonstrating an unprecedented commitment to climate policy. Federal, state and local governments are using tools like executive orders, legislation, regulatory actions, and more to regulate GHGs. At the federal level, for example, EPA has promulgated regulations requiring the monitoring and reporting of GHGs and limiting GHGs directly from certain sources of emissions. Governmental, scientific, and public concern over GHG emissions from the oil and gas industry, in particular, is growing considerably. President Biden’s new executive orders included a pause on new oil and gas leasing on federal lands, a revocation of the Keystone XL Presidential Permit, and more. Furthermore, while the EPA has historically been the sole federal regulator of GHGs, on December 27, 2020, former President Trump signed into law the 2020 PIPES Act, which notably made PHMSA another federal regulator of methane emissions from pipeline facilities. While we cannot predict the extent of the impact on the Partnership and the rest of the oil and gas industry from the increased GHG regulation, we can be sure that it will be material.

In recent years, there has been a particular focus on the regulation of the specific GHG, methane. Methane is the primary component of the natural gas flowing through our pipelines and is sometimes release into the atmosphere through pipeline leaks and blowdowns during pipeline maintenance, repair, testing, and other such activities. Natural gas companies and trade organizations are proactively evaluating the impact of methane to the climate crisis, approaches to measuring methane releases more accurately, and methane leak monitoring, reporting, detection, and mitigation practices and available technology. This research and analysis is not only important to understanding how to cost-effectively comply with the ever-increasing regulation of methane, but also to prove to fossil fuel opponents that the value of natural gas far outweigh the impact on climate.

Since the climate crisis is now regularly used to challenge the construction of natural gas pipeline projects, anytime methane regulations were relaxed under former President Trump's administration, particularly for the oil and gas industry, they were swiftly challenged in court, including a notable methane regulation in 2020. On August 13, 2020, the EPA, under former President Trump's administration issued policy and technical amendments to the NSPS, for stationary sources of air emissions. The policy amendments, (Methane Policy Rule), effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and VOC requirements for the remaining sources that were established by former President Obama's administration. The technical amendment included changes to fugitive emissions monitoring and repair schedules for gathering and boosting compressor stations and low-production wells, recordkeeping and reporting requirements, and more. The Partnership sees the amendments as positive for the industry since it eliminates NSPS for natural gas transmission pipelines. However, it is important to note that the Partnership is still committed to many of the NSPS requirements for pipelines. This is important because, as expected, the amendments were immediately challenged in federal court. Moreover, President Biden's January 20, 2021 EO for Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis specifically directed EPA to review the technical amendment by September 2021. A reconsideration of the more controversial policy amendment is expected to follow. The same EO directed EPA to also propose existing source standards by September 2021. The extent to which these directives will impact the Partnership remains unknown.

State GHG Regulation

In the absence of consistency and predictability in GHG emissions legislation, regulation and policies at the federal level, state and local governments have increasingly and more aggressively pursued GHG regulation within their own jurisdictions. This trend is likely to continue to grow under President Biden's leadership. A bipartisan coalition of governors from twenty-five states and U.S. territories have established the U.S. Climate Alliance to combat climate change through the implementation of state policies that are consistent with the U.S. goal of the Paris Agreement. Many of these policies are currently affecting or expected to affect our assets residing in those specific states and increase our compliance-related costs, the extent of which is yet unknown.

In addition to issuing executive orders, legislation, and promulgating regulations for GHG emissions, states and local governments in California, Oregon, and Washington have taken advantage of tools like cap-and-trade programs, carbon taxes, and GHG reporting and tracking programs. For example, the Governor of Oregon issued an executive order in March 2020 to reduce and regulate GHGs in the state through the establishment of new annual GHG emissions reduction goals that must be met through the development of a new carbon cap and reduce program and enhanced clean fuel standards, which take effect no later than January 1, 2022. Rulemaking to implement the executive order has been ongoing since Spring 2020. The Northwest Gas Association, a trade organization of the Pacific Northwest Gas Industry, is representing the interests of interstate pipeline company members, including TC Energy, on the Rulemaking Advisory Committee for the development of the program. The extent to which GTN assets in Oregon will be impacted remains unknown, as the program is not expected to be proposed until Summer 2021. Additionally, the Washington Department of Ecology began rulemaking in 2020 to implement the Governor’s order to strengthen and standardize the consideration of climate change risks, vulnerability, and impacts in environmental assessments for certain major industrial and fossil fuel projects. During Washington’s 2020 legislative session, legislators also passed a law committing the State to becoming carbon-neutral by 2050 and strengthening intermediate reduction goals. In addition to California’s climate change plan that includes a GHG cap-and-trade program and methane leak regulations for oil and gas sites, the Governor issued an executive order in September 2020 requiring all new cars and light trucks sold in the state to be zero emission by 2035 and heavy and medium trucks to be zero emission by 2045. The promotion of electrification and use of legal tools for GHG regulation is also gaining traction at the local level. For example, in November 2020 a carbon tax was proposed to the Portland City Commission and in December 2020, the Governor of Washington and Mayor of Seattle followed in the footsteps of local government in California by introducing proposals that would cut demand for natural gas through building

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electrification ordinances. As such, the increasing state and local GHG regulation and promotion of electrification may materially affect our business, financial condition, demand for our systems and services, operations, compliance-related costs, and more.

Political Risks, Litigation Risks, Financial Risks

The political risks to the Partnership’s business for the immediate future is expected to be higher than it has been under former President Trump's administration. President Biden touted a comprehensive and aggressive environmental protection plan during his campaign that he promised to begin implementing immediately after taking office. Within his first week in the White House, President Biden took unprecedented executive actions in furtherance of human health and environmental protection, as well as environmental justice. Having identified climate change as one of his administration’s top four priorities, President Biden signed a number of executive actions, starting with rejoining the Paris Agreement, the largest international effort to combat climate change, which former President Trump had officially withdrawn the U.S. from on November 4, 2020. Similarly, President Biden issued an executive order on January 27, 2021, directing the Secretary of the Interior to pause, to the extent consistent with applicable law, the issuance of new oil and gas leases on federal public lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. President Biden's robust climate change plan includes a pledge to achieve a clean energy economy by 2050 by implementing a number of initiatives through executive orders, legislation, and regulations. His climate agenda includes methane regulation, promotion of electrification, and more. The political risk to the Partnership's business is further increased by climate change-related pledges made by candidates seeking public office at the local, state, and federal levels. During former President Trump's administration, Democratic Party-sponsored legislative initiatives, such as the Clean Leadership and Environmental Action for our Nation’s (CLEAN) Future Act and the Climate Crisis Action Plan, were proposed in 2020 but did not advance beyond the House. Now, the likelihood of passing comprehensive climate change legislation at the federal level has significantly increased. President Biden's climate agenda could require us or our customers to incur increased, potentially significant, costs to comply with new, more stringent GHG regulations. Additionally, entry into the Paris Agreement could adversely affect demand for the production of oil and natural gas and, thus, reduce demand for the services we provide to our customers.

Litigation Risk

Over the years, litigation risks have steadily increased as environmental protection, and particularly climate change, has garnered a great deal of attention on the global stage. Large interstate pipeline projects, in particular, have been challenged in court on various environmental grounds including water protection, endangered species and habitat protection, and climate change. Litigation risk for the Partnership increased in 2020 when environmental groups and various governments took issue with former President Trump's relaxation of burdensome regulation of industry. While environmental regulation under President Biden's administration is expected to be more stringent and thus more burdensome on industry, increased litigation will likely be due to industry challenging certain environmental regulations, legislation and executive directives. As mentioned earlier, there is a high litigation risk from those who want to oppose pipeline projects on the grounds they are using invalid NWP 12s and/or other NWPs.

Financial Risk

There are also growing financial risks as stakeholders of fossil fuel companies become increasingly concerned about the potential effects of climate change and consider shifting some or all of their investments into non-fossil fuel energy related sectors. Additionally, some institutional lenders, who provide financing to fossil-fuel energy companies, have become more attentive to sustainable lending practices and may elect not to provide funding for fossil fuel energy companies. Additionally, the expected increase in the regulation of oil and gas companies under President Biden, particularly on the basis of climate change, will likely materially increase compliance-related costs, costs to litigate regulatory actions, and more. Finally, increasing concentrations of GHGs in the Earth's atmosphere may produce climatic events like storms and floods which may have a material adverse effect on the financial condition and results of operations on us and our customers.

Waste Remediation Related Environmental Issues Potentially Impacting the Partnership

We own, lease, or operate numerous properties that have been used for natural gas pipeline operations for many years. Additionally, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. Under environmental laws such as TSCA, CERCLA, and RCRA, we could incur strict joint and several liability due to damages to natural resources as well as for remediating hydrocarbons, hazardous substances or wastes disposed of or released by us or prior owners or operators. For example, during routine maintenance activities of our pipelines and related facilities, we may discover historical hydrocarbon or PCB contamination. Discovery of such contaminants would require prompt notification to the appropriate governmental authorities and corrective actions to timely mitigate the contamination. Moreover, an accidental release of materials into the environment during our operations may cause us to incur significant costs and liabilities. Remedial costs, penalties from governmental agencies, and other damages could have a material adverse effect on our liquidity, results of operations, and financial condition. We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal and for damages to natural resources or other claims related to releases of regulated substances at or from such third-party sites.

Total Financial Impact of Compliance with Environmental Laws and Regulations

~~At this time~~TC PipeLines, the ultimate financial impact of complying with U.S. environmental laws and regulations is indeterminable. Compliance obligations can result in significant costs associated with installing and maintaining pollution controls, fines and penalties resulting from any regulatory violations, and potential limitations on operations. Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated facilities, and with damage claims arising from the contamination. The timing and complete extent of future expenditures related to environmental matters is difficult to estimate accurately because (1) interpretation and enforcement of environmental laws and regulations are constantly changing or evolving; (2) new claims can be brought against our existing or discontinued assets; (3) our pollution control and clean-up cost estimates may change, especially when our current estimates are based on preliminary site investigations or agreements; (4) new contaminated facilities and sites may be found, or what we know about existing sites and facilities could change; and (5) where there is potentially more than one responsible party involved in litigation, we cannot estimate our joint and several liability with certainty. LP Annual Report 2020 29

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Currently, the ultimate financial impact of complying with U.S. environmental laws and regulations is indeterminable. Compliance obligations can result in significant costs associated with installing and maintaining pollution controls, fines and penalties resulting from any regulatory violations, and potential limitations on operations. Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated facilities, and with damage claims arising from the contamination. The timing and complete extent of future expenditures related to environmental matters is difficult to estimate accurately because (1) interpretation and enforcement of environmental laws and regulations are constantly changing or evolving; (2) new claims can be brought against our existing or discontinued assets; (3) our pollution control and clean-up cost estimates may change, especially when our current estimates are based on preliminary site investigations or agreements; (4) new contaminated facilities and sites may be found, or what we know about existing sites and facilities could change; and (5) where there is potentially more than one responsible party involved in litigation, we cannot estimate our joint and several liability with certainty.

We have incurred and will continue to incur operating and capital expenditures costs, some of which could be material, as environmental laws and regulations continue to evolve, change, and become stricter and more robust. Additional regulatory restrictions continue to be placed on activities that may have a detrimental effect on the environment. For this reason, new laws and regulations, amendments and reinterpretations, and stricter enforcement permitting programs result in compliance and remediation obligations that can have a material adverse effect on our operations and financial position now and in the future. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operational results.

Pipeline Safety Matters

Our gas pipeline systems are subject to federal pipeline safety statutes, such as the Natural Gas Pipeline Safety Act of 1968 (NGPSA), the Pipeline Safety Improvement Act of 2002 (the PSI Act), the Pipeline Inspection, Protection, and Enforcement Act of 2006 (the PIPES Act), the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the 2011 Pipeline Safety Act) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the 2016 Pipeline Safety Act), as well as regulations promulgated and administered by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities to ensure adequate protection for the public and to prevent accidents and failures. Pursuant to this act, PHMSA has promulgated regulations governing, among other things, maximum operating pressures, pipeline patrols and leak surveys, public awareness, operation and maintenance procedures, operator qualification, minimum depth requirements and emergency procedures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs to comprehensively evaluate certain relatively higher risk areas, known as HCAs and moderate consequence areas (MCAs) along pipelines and take additional safety measures to protect people and property in these areas in the event of a pipeline leak or rupture. The HCAs for gas pipelines are predicated on high-population areas, which may include Class 3 and Class 4 areas. An MCA for gas pipelines is also based on population totals in addition to the existence of certain principal, high-capacity roadways, but an MCA does not meet the relative higher population totals of an HCA and therefore are located outside of HCA coverages.

Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business, financial condition or results of operations.

~~24 TC PipeLines~~Moreover, ~~LP Annual Report~~ changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For instance, several years after publishing the gas mega proposed rulemaking, PHMSA elected to split the proposed rulemaking into three rules, also known as the "Gas Mega Rule" with the first of these rules, relating to onshore gas transmission pipelines, published as a final rule in October 2019. The October 2019 final rule relates specifically to gas transmission pipelines and, among other things, updates reporting and records retention standards for covered pipelines and expands the level of required integrity assessments that must be completed on certain pipeline segments outside of high consequence areas (HCAs). The October 2019 final rule also requires operators to review maximum allowable operating pressure records and perform specific remediation activities where records are not available. The Partnership will continue to assess the operational and financial impact related to the October 2019 final rule over its 15-year implementation window that began July 1, 2020 and seek to optimize recovery of those costs. The remaining rulemakings comprising the Gas Mega Rule are expected to be issued in 2021. On January 11, 2021, PHSMA finalized a published June 2020 proposed a rulemaking that would seek to ease regulatory burdens on gas transmission, distribution and gathering lines. However, we expect President Biden's administration to reconsider this rulemaking or possibly have it withdrawn.

Congress enacted the 2016 Pipeline Safety Act, which reauthorized PHMSA’s hazardous liquid and gas pipeline programs only through federal Fiscal Year 2019. On December 27, 2020, the 2020 PIPES Act was signed into law and authorizes general funding for PHMSA as well as prescribes a number of priorities for PHMSA through federal fiscal year 2023. Key items include: additional due process protections for operators during enforcement proceedings; updating the federal safety standards for the operation and maintenance of large-scale liquefied natural gas facilities; clarifying the applicability of the pipeline safety regulations to idle pipelines; and reviewing each operator’s operation and maintenance plan within two years. The 2020 Pipes

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~~not~~Act ~~have~~also established a ~~material~~new ~~adverse~~three-year ~~effect~~program onfor ~~our~~advancing ~~business,~~pipeline ~~financial~~safety ~~condition~~technologies, ortesting, ~~results~~and ofoperational ~~operations. See~~practices ~~Risk~~and ~~Factors~~increasing ~~under~~the ~~Part~~number ~~I, Item 1A~~ of ~~this~~PHMSA ~~Form~~inspection ~~10-K~~and ~~for~~enforcement ~~further~~personnel ~~discussion~~by ~~on pipeline safety matters~~20%.

~~During~~Other ~~2016, PHMSA also~~ proposed ~~new~~ rules and issued a Notice of Public Rule Making for natural gas transmission and gathering lines that would, if adopted, impose more stringent inspection, reporting, and integrity management requirements on operators. However, PHMSA has since decided to split its 2016 proposed rule, which has become known as the “gas mega rule,” into three separate rulemakings, focusing on (1) maximum allowable operating pressure, integrity assessments and non-high consequence areas known as moderate consequence areas; (2) repair criteria, safety features for pigging, inspections and corrosion control; and (3) gathering lines. The first of these three rulemakings, relating to onshore gas transmission pipelines, was published as a final rule on October 1, 2019, becomes effective on July 1, 2020, and imposes numerous requirements on such pipelines, including maximum allowable operating pressure (MAOP) reconfirmation, the assessment of additional pipeline mileage outside of HCAs (including all MCAs and those Class 3 and Class 4 areas found not to be in HCAs) within 14 years of the publication date and at least once every 10 years thereafter, the reporting of exceedances of MAOP, and the consideration of seismicity as a risk factor in integrity management. We are currently assessing the operational and financial impact related to this final rule which will become effective on July 1, 2020 with a 15-year implementation deadline. The remaining rulemakings comprising the gas mega rule are expected to be issued in 2020.:

Valve Installation and Minimum Rupture Detection Standards- On ~~July~~February 316, ~~2018,~~2020 PHMSA published ana ~~advance~~Notice ~~notice~~ of ~~proposed~~Proposed ~~rulemaking~~Rulemaking (~~ANPRM~~NPRM) ~~requesting~~entitled ~~public~~Pipeline ~~comment~~Safety: onValve ~~the~~Installation ~~additional~~and ~~safety~~Minimum ~~measures~~Rupture ~~pipelines~~Detection ~~facilities~~Standards. ~~are~~The ~~required~~NPRM proposes to ~~take~~revise inexisting ~~response~~regulation tofor ~~class~~gas ~~location~~transmission ~~changes~~pipelines ~~due~~ to ~~population~~address ~~growth.~~congressional ~~The~~mandates, ~~class~~incorporate ~~location~~recommendations ~~concept~~from ~~predates~~ the ~~extension~~National ofTransportation ~~Integrity~~Safety ~~Management~~Board, ~~(IM)~~and ~~principles~~to ~~and~~reduce itthe ~~has~~consequences ~~been~~of ~~argued~~large-volume, ~~that~~uncontrolled ~~public~~releases ~~safety~~of ~~can~~natural begas ~~improved~~pipeline ifruptures. IMSpecifically, ~~measures~~the ~~are~~NPRM ~~implemented~~seeks asto anset ~~alternative~~requirements tofor ~~pressure~~the ~~reductions~~placement, ~~pipe replacements~~function, orand ~~hydrostatic~~maintenance ~~pressure~~of ~~testing.~~automatic ~~While~~shut ~~this~~off ~~rulemaking~~and/or ~~process~~remote-control ismainline ~~expected~~valves to bemitigate ~~lengthy,~~the ~~efforts~~effects of a pipeline rupture. The NPRM also seeks to ~~modernize~~set ~~the~~time ~~existing~~requirements ~~PHMSA~~for ~~regulations~~the ~~may~~identification ~~have~~of, aand ~~material~~response ~~effect~~to, onpipeline ~~costs~~ruptures.

Class Location Change Requirements - On October 3114, ~~2019~~2020, PHMSA, ~~released~~published ~~its~~an ~~“Enhanced~~NPRM ~~Emergency~~entitled ~~Order~~Class ~~Procedures”~~Location ~~final~~Change ~~rule,~~Requirements. ~~which~~PHMSA ~~replaces~~is anproposing ~~interim~~to ~~final~~revise ~~rule~~the ~~issued~~Federal byPipeline ~~PHMSA~~Safety Regulations to amend the requirements for gas transmission pipeline segments that experience a change in ~~2016~~class location. Under the existing regulations,~~and~~ ~~allows~~pipeline ~~PHMSA~~segments tolocated ~~respond~~in toareas ~~imminent~~where ~~threats~~the ~~during~~population ~~natural~~density ~~disasters,~~has ~~and~~significantly ~~when~~increased ~~serious~~must ~~flaws~~perform ~~are~~one ~~discovered~~of inthe ~~pipes~~following oractions: inreduce ~~equipment~~the ~~manufacturing~~pressure ~~processes~~of the pipeline segment, orpressure ~~when~~test anthe ~~accident~~pipeline ~~reveals~~segment anto ~~industry~~higher ~~practice~~standards, isor ~~unsafe~~replace the pipeline segment. ~~The~~This ~~final~~proposed rule ~~addressed~~would ~~comments~~add ~~made~~an inalternative ~~response~~set toof ~~the~~requirements ~~2016~~operators ~~interim~~could ~~final~~use, ~~rule~~based on implementing integrity management principles and pipe eligibility criteria, ~~which~~to ~~resulted~~manage incertain ~~several~~pipeline ~~changes~~segments inwhere the ~~final~~class ~~rule~~location has changed from a Class 1 location to a Class 3 location. ~~The~~Through ~~Partnership~~required isperiodic ~~currently~~assessments, ~~reviewing~~repair ~~the~~criteria, ~~final~~and ~~rule~~other ~~but~~extra ~~does~~preventive ~~not~~and ~~expect~~mitigative ~~any~~measures, ~~material~~PHMSA ~~issues~~expects inthis ~~complying~~alternative approach would provide long-term safety benefits consistent with the ~~final~~current ~~rule,~~natural ~~which~~gas ~~took~~pipeline ~~effect~~safety onrules ~~December~~while 2,also ~~2019~~providing cost savings for pipeline operators.

~~The~~While ~~Partnership~~the ~~expects~~above ~~new~~rulemaking ~~pipeline~~process ~~safety~~is ~~legislation~~expected to be ~~proposed and finalized in 2020 that will reauthorize PHMSA pipeline safety programs~~lengthy, ~~which~~efforts expired under the 2016 Pipeline Safety Act at the end of September 2019. Any such new pipeline safety legislation could impose more stringent or costly compliance obligations on us and could require us to ~~pursue~~modernize ~~additional capital projects or conduct integrity or maintenance programs on an accelerated basis, any or all of which tasks could result in~~ the ~~Partnership~~existing ~~incurring~~PHMSA ~~increased~~regulations ~~operating costs that~~ could have a material ~~adverse~~ effect on our costs ~~of transportation services as well as our business, results of operations and financial condition~~.

~~The~~Compliance with existing pipeline safety laws and implementing regulations could cause our pipeline systems to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure their continued safe and reliable operation and to comply with the federal pipeline safety statutes and regulations. ~~Additional~~The ~~rule~~promulgation ~~makings~~of new laws and rulemaking regarding pipeline safety are likely and, despite compliance with applicable ~~rules~~laws and regulations, our pipelines may experience leaks and ruptures that could impact the surrounding population and environment. This may result in civil and/or criminal fines and penalties or third-party property damage claims and could require additional testing or upgrades on the pipeline system unrelated to the incident. It is possible that these costs may not be covered by insurance or recoverable through rate increases. There can be no assurance that future compliance with the requirements will not have a material adverse effect on our pipeline systems and the Partnership's financial position, operational costs, cash flow and our ability to maintain current distribution levels to the extent the increased costs are not recoverable through rates.

U.S. Occupational Safety and Health Administration (OSHA)

Our pipelines are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act ~~(OSHA)~~ and comparable state statutes, whose purpose is to protect the health and safety of workers. The OSHA and analogous state agencies oversee the implementation of these laws and regulations. Additionally, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.

Historically, worker safety and health compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operational results. While pipeline operators may increase expenditures in the future to comply with higher industry and regulatory safety standards, such increases in costs of compliance, and the extent to which they might be recoverable through our pipeline’s rates, cannot be estimated at this time.

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costs of compliance, and the extent to which they might be recoverable through our pipeline’s rates, cannot be estimated at this time.

Cyber security

We rely on our information technology to process, transmit and store electronic information, including information pipeline operators use to safely operate our assets. We, our operators and other energy infrastructure companies in jurisdictions where we do business continue to face cyber security risks. Cyber security events could be directed against companies in the energy infrastructure industry.

A breach in the security of our information technology could expose our business to a risk of loss, misuse or interruption of critical information and functions. This could affect our operations, damage our assets and result in safety incidents, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions and potential litigation, which could have a material adverse effect on our operations, financial position and results of operations.

TC Energy, the indirect parent of our General Partner and the operator of most of our assets, has a cyber security strategy which aligns with industry and recognized standards for cyber security. This strategy includes cyber security risk assessments, preventions, continuous monitoring of networks and other information sources for threats to the organization, comprehensive incident response plans/processes and a cyber security awareness program for employees. Although TC Energy also has insurance which may cover losses from physical damage to our facilities as a result of a cyber security event, the insurance does not cover all events in all circumstances. There is no certainty that costs incurred related to securing against these threats will be recovered through rates.

~~EMPLOYEES~~TC PipeLines, LP Annual Report 2020 31

WeTable ~~do not have any employees. We are managed and operated by our General Partner. Subsidiaries~~ of TC Energy operate most of our pipelines systems pursuant to operating agreements, with the exception of the Iroquois pipeline system and the Joint Facilities. The Iroquois pipeline system is operated by a wholly owned subsidiary of Iroquois. The Joint Facilities are operated by MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.Contents

incident response plans/processes and a cyber security awareness program for employees. Although TC Energy also has insurance which may cover losses from physical damage to our facilities as a result of a cyber security event, the insurance does not cover all events in all circumstances. There is no certainty that costs incurred related to securing against these threats will be recovered through rates.

HUMAN CAPITAL RESOURCES

We do not have any employees. While human capital is necessary for us to operate our business, we are managed and operated by our General Partner, therefore we do not directly make decisions regarding our service providers. Subsidiaries of TC Energy operate most of our pipelines systems pursuant to operating agreements, with the exception of the Iroquois pipeline system and the Joint Facilities. The Iroquois pipeline system is operated by a wholly owned subsidiary of Iroquois. The Joint Facilities are operated by MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.

AVAILABLE INFORMATION

We make available free of charge on or through our website (www.tcpipelineslp.com) our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the Exchange Act), as soon as reasonably practicable after we electronically file the material with, or furnish it to, the Securities and Exchange Commission (SEC). Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and the Audit Committee Charter of our General Partner are also available on our website under “Corporate Governance.” We will also provide copies of these documents at no charge upon request. The information contained on our website is not part of this report.

Item 1A. Risk Factors

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. Realization of any of the risks described below could have a material adverse effect on our business, financial condition, including valuation of our equity investments, results of operations and cash flows, including our ability to make distributions to our unitholders. Investors should review and carefully consider all information contained in this report, including the following discussion of risks when making investment decisions relating to our Partnership.

RISKS RELATED TO THE PARTNERSHIP

The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow, financial reserves and working capital borrowings, rather than on our profitability, which may prevent us from making distributions, even during periods in which we earn net income.

The amount of cash we have available for distribution depends primarily upon our cash flows and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when losses are incurred and may not make cash distributions during periods when we earn net income.

~~26 TC PipeLines~~The amount of cash we generate from our operations, fluctuates based on, among other ~~LP Annual Report 2019~~things:

•the rates we charge for our transmission and changes in demand for our transportation services;

•legislative or regulatory action affecting the demand for natural gas, the supply of natural gas, the rates we can charge, how we contract for services, our existing contracts, operating costs and operating flexibility;

•the commodity price of natural gas, which could reduce the quantities of natural gas available for transport;

•the creditworthiness of our customers;

•changes in, or new, statutes, regulations or governmental policies by federal, state and local authorities with respect to protection of the environment;

•changes in accounting rules and/or tax laws or their interpretations;

•nonperformance or force majeure by, or disputes with or changes in contract terms with, major customers, suppliers, dealers, distributors or other business partners; and

•changes in, or new, statutes, regulations, governmental policies and taxes, or their interpretations.

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

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~~Our~~transportation ~~ability~~and storage capacity caused the New York Mercantile Exchange (NYMEX) West Texas Intermediate oil futures price to ~~make~~go ~~cash~~as ~~distributions~~low isas ~~dependent~~approximately ~~primarily~~negative on$37. ~~our~~This ~~cash~~negative ~~flow,~~pricing ~~financial~~resulted ~~reserves~~from the holders of expiring front month oil purchase contracts being unable or unwilling to take physical delivery of crude oil and ~~working~~accordingly ~~capital~~forced ~~borrowings~~to make payments to purchasers of such contracts in order to transfer the corresponding purchase obligations.

~~The~~Although ~~amount~~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 ~~cash~~low wecrude ~~can~~oil ~~distribute~~and onnatural ~~our~~gas ~~units~~prices ~~principally~~would ~~depends~~negatively ~~upon~~impact exploration and development of new crude oil and natural gas supplies. In response to the ~~amount~~sharp decline in oil and natural gas prices, many producers have announced cuts or suspension of ~~cash~~exploration weand ~~generate~~production ~~from~~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 ~~operations,~~pipelines. ~~which~~Sustained ~~will~~low ~~fluctuate~~oil ~~based~~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, ~~among~~liabilities, ~~other things:~~business, financial condition, results of operations and cash flow.

●Capital ~~the~~projects ~~rates~~or wefuture ~~charge~~acquisitions ~~for~~that ~~our~~appear ~~transmission~~to ~~and~~be ~~changes~~accretive inmay ~~demand~~fail ~~for~~to materialize as anticipated or nevertheless reduce our ~~transportation~~cash ~~services;~~available for distributions.

●If ~~legislative~~we orcannot ~~regulatory~~successfully ~~action~~finance ~~affecting~~and ~~the~~complete ~~demand~~capital ~~for~~projects ~~natural~~or ~~gas,~~make ~~the~~and ~~supply~~integrate ofacquisitions ~~natural~~that ~~gas~~are accretive, ~~the~~we ~~rates~~may not be able to maintain or grow our distributions. Even if we ~~can~~complete ~~charge,~~capital ~~how~~projects or make acquisitions that we ~~contract~~believe ~~for~~will ~~services~~be accretive, these capital projects or acquisitions may nevertheless reduce our ~~existing~~cash ~~contracts,~~from ~~operating~~operations ~~costs~~on ~~and~~a ~~operating~~per-unit ~~flexibility;~~basis. Any capital project or acquisition involves potential risks, including:

●•an inability to complete capital projects on schedule or within the ~~commodity~~budgeted ~~price~~cost due to, among other factors, the unavailability of ~~natural~~required ~~gas~~construction personnel, ~~which~~equipment ~~could~~or ~~reduce~~materials and the ~~quantities~~risk of ~~natural~~cost ~~gas~~overruns ~~available~~resulting ~~for~~from ~~transport~~inflation or increased costs of materials, labor and equipment;

●•a ~~the~~decrease ~~creditworthiness~~in our liquidity as a result of using a significant portion of our ~~customers~~available cash or borrowing capacity to finance the project or acquisition;

●•an ~~changes~~inability ~~in,~~to orreceive ~~new,~~cash ~~statutes,~~flows ~~regulations~~from ora ~~governmental~~newly ~~policies~~built byor ~~federal,~~acquired ~~state~~asset ~~and~~until ~~local~~it ~~authorities~~is ~~with respect to protection of the environment~~operational; and

●•unforeseen ~~changes~~difficulties operating in ~~accounting~~new ~~rules~~business ~~and/or~~areas ~~tax laws~~ or ~~their~~new ~~interpretations;~~geographic areas.

●As ~~nonperformance~~a orresult, ~~force~~our ~~majeure~~new byfacilities may not achieve expected investment returns, which could adversely affect our results of operations, financial position or ~~disputes~~cash ~~with~~flows. If any completed capital projects or ~~changes~~acquisitions inreduce ~~contract~~our ~~terms~~cash ~~with,~~from ~~major~~operations ~~customers,~~on ~~suppliers,~~a ~~dealers~~per-unit basis, ~~distributors~~our orability ~~other~~to ~~business~~make ~~partners;~~distributions ~~and~~may be reduced.

● changes in, or new, statutes, regulations, governmental policies and taxes, or their interpretations.

Significant changes in energy prices could impact supply and demand balances for natural gas.

Prolonged low oil and natural gas prices can have a positive impact on demand but can negatively impact exploration and development of new natural gas supplies that could impact the availability of natural gas to be transported by our pipelines. Similarly, high commodity prices can increase levels of exploration and development but can reduce demand for natural gas leading to reduced demand for transportation services. Sustained low or high oil and natural gas prices could also impact shippers’ creditworthiness that could impact their ability to meet their transportation service cost obligations.

Failure to complete capital projects or acquire additional assets may inhibit our strategy of providing long-term steady and predictable cash distributions.

If we cannot successfully finance and complete capital projects or make and integrate acquisitions that are accretive, we may not be able to maintain historical levels of cash flow and distributions. For example, if we are unable to replace cash flow that may be reduced through future rate proceedings or contract expirations on our pipeline systems, we could be required to take additional proactive measures, including further reductions from the current quarterly level of $0.65 per common unit, to facilitate repayments of debt as may be needed to maintain compliance with financial covenants, in addition to taking other significant strategic actions.

Capital projects or future acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per unit basis.

Even if we complete capital projects or make acquisitions that we believe will be accretive, these capital projects or acquisitions may nevertheless reduce our cash from operations on a per-unit basis. Any capital project or acquisition involves potential risks, including:

● an inability to complete capital projects on schedule or within the budgeted cost due to, among other factors, the unavailability of required construction personnel, equipment or materials and the risk of cost overruns resulting from inflation or increased costs of materials, labor and equipment;

● a decrease in our liquidity as a result of using a significant portion of our available cash or borrowing capacity to finance the project or acquisition;

● an inability to receive cash flows from a newly built or acquired asset until it is operational; and

● unforeseen difficulties operating in new business areas or new geographic areas.

As a result, our new facilities may not achieve expected investment returns, which could adversely affect our results of operations, financial position or cash flows. If any completed capital projects or acquisitions reduce our cash from operations on a per unit basis, our ability to make distributions may be reduced.

Our indebtedness may limit our ability to obtain additional financing, make distributions or pursue business opportunities.

The amount of the Partnership’s current or future debt could have significant consequences to the Partnership including the following:

● •our ability to obtain additional financing, if necessary, for working capital, acquisitions, payment of distributions or other purposes may be impaired, or such financing may not be available on favorable terms;

~~TC PipeLines, LP Annual Report 2019 27~~•credit rating agencies may view our debt level negatively;

~~Table~~•covenants ofcontained ~~Contents~~in our existing debt arrangements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;

●•our ~~credit~~need ~~rating~~for ~~agencies~~cash ~~may~~to ~~view~~fund ~~our~~interest payments on the debt ~~level~~reduces ~~negatively~~the funds that would otherwise be available for operations, future business opportunities and distributions to our unitholders; and

●•our ~~covenants~~flexibility ~~contained~~ in ~~our~~responding ~~existing debt arrangements will require us~~ to ~~continue~~changing tobusiness ~~meet~~and ~~financial~~economic ~~tests~~conditions ~~that~~ may ~~adversely affect our flexibility in planning for and reacting to changes in our business;~~be limited.

● our need for cash to fund interest payments on the debt reduces the funds that would otherwise be available for operations, future business opportunities and distributions to our unitholders; and

● our flexibility in responding to changing business and economic conditions may be limited.

In addition, our ability to access capital markets to raise capital on favorable terms will be affected by our debt level, our operating and financial performance, the amount of our current maturities and debt maturing in the next several years and by prevailing market conditions. Moreover, if the rating agencies were to downgrade our credit ratings, we could experience an increase in our borrowing costs, face difficulty accessing capital markets or incurring additional indebtedness, lack the ability to receive open credit from our suppliers and trade counterparties, be unable to benefit from swings in market prices and shifts in market structure during periods of volatility in the oil and gas markets or suffer a reduction in the market price of our common units. If we are unable to access the capital markets on favorable terms at the time a debt obligation becomes due in the future, we may refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities, or sell assets. The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected rates.

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If we are unable to obtain needed capital or financing on satisfactory terms to fund capital projects or future acquisitions, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase.

Over time, our industry’s fundamentals have historically made it difficult for some entities to obtain funding. In order to fund some capital project expenditures, we may be required to use cash from our operations, incur borrowings or sell additional common units or other limited partner interests. Using cash from operations will reduce distributable cash flow to our common unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering, the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining funds for capital project expenditures through equity or debt financings, the terms thereof may be less favorable to us and could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate. If funding is not available to us when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our financial condition, credit ratings, results of operations, cash flows and ability to make quarterly cash distributions to our unitholders.

Exposure to variable interest rates and general volatility in the financial markets and economy could adversely affect our business, our common unit price, results of operations, cash flows and financial condition.

As of December 31, 2019, $112 million of our total $2,012 million of consolidated debt was subject to variable interest rates. As a result, our results of operations, cash flows and financial condition could be adversely affected by significant increases in interest rates. From time to time, we may enter into interest rate swap arrangements which may increase or decrease our exposure to variable interest rates but there is no assurance that these will be sufficient to offset rising interest rates. As of December 31, 2019, the $450 million borrowed under the Partnership’s term loan credit facility under a term loan agreement as amended on September 29, 2017 (the 2013 Term Loan Facility) was hedged by forward starting swap arrangements.

For more information about our interest rate risk, see Part II, Item 7A. "Quantitative and Qualitative Disclosures About Market Risk – Market Risk."

Any impairment of our goodwill, long-lived assets or equity investments will reduce our earnings and could negatively impact the value of our common units.

Consistent with U.S. Generally Accepted Accounting Principles (GAAP), we evaluate our goodwill for impairment at least annually. Our long-lived assets and equity investments, including intangible assets with finite useful lives, are evaluated whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test requires us to consider whether the fair value of the equity investment, not just that of the underlying net assets, has declined and whether that decline is other than temporary. If we determine that impairment is indicated, we would be required to take an immediate non-cash charge to earnings with a corresponding effect on equity and balance sheet leverage as measured by debt to total capitalization.

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For example, in the fourth quarter of 2018, we recognized impairment charges on Tuscarora’s goodwill balance amounting to $59 million and Bison’s long-lived assets totaling $537 million.

The risk of future impairments related to our goodwill, long-lived assets or equity investments, will continue to exist. If underlying business assumptions change, there can be no assurance that a future impairment charge will not be made with respect to our remaining balances of our goodwill, equity investments and long-lived assets. This could have a negative impact on the common unit price.

For more information, see Part II, Item 6 “Selected Financial Data” for summary of impairments recognized on our equity investments, goodwill and long-lived assets in the last 5 years. See also Part II, Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates - Impairment of Goodwill, Long-Lived Assets and Equity Investments.”

We do not own a controlling interest in our equity investments in Northern Border, Great Lakes and Iroquois, which limits our ability to control these assets.

We do not own a controlling interest in our equity investments in Northern Border, Great Lakes and Iroquois and are therefore unable to cause certain actions to occur without the agreement of the other owners. As a result, we may be unable to control the amount of cash distributions received from these assets or the cash contributions required to fund our share of their operations. The major policies of these assets are established by their management committees, which consist of individuals who are designated by each of the partners including us. These management committees generally require at least the affirmative vote of a majority of the partners’ percentage interests to take any action. Because of these provisions, without the concurrence of other partners, we would be unable to cause these assets to take or not to take certain actions, even though those actions may be in the best interests of the Partnership or these assets. Further, these assets may seek additional capital contributions. Our funding of these capital contributions would reduce the amount of cash otherwise available for distribution to our unitholders. In the event we do not elect or are unable to make a capital contribution to these assets, our ownership interest would be diluted.

Any disagreements with the other owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.

RISKS RELATED TO THE TC ENERGY MERGER

Because the market value of TC Energy common shares that Unaffiliated TCP Unitholders will receive in the TC Energy Merger may fluctuate, Unaffiliated TCP Unitholders cannot be sure of the market value of the merger consideration that they will receive in the TC Energy Merger.

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As merger consideration, Unaffiliated TCP Unitholders will receive a fixed number of TC Energy common shares, not a number of shares that will be determined based on a fixed market value. The market value of TC Energy common shares and the market value of TC PipeLines common units at the effective time may vary significantly from their respective values on the date that the TC Energy Merger Agreement was executed or at other dates, such as the date of this Annual Report on Form 10-K or the date of the special meeting. Stock price changes may result from a variety of factors, including changes in TC Energy’s or the Partnership’s respective businesses, operations or prospects, regulatory considerations and general business, market, industry or economic conditions. The exchange ratio will not be adjusted to reflect any changes in the market value of TC Energy common shares, the comparative value of the Canadian dollar and U.S. dollar or market value of the TC PipeLines common units. Therefore, the aggregate market value of the TC Energy common shares that an Unaffiliated TCP Unitholder is entitled to receive at the time that the TC Energy Merger is completed could vary significantly from the value of such shares on the date of this Annual Report on Form 10-K, the date of the special meeting or the date on which an Unaffiliated TCP Unitholder actually receives its TC Energy common shares.

Upon completion of the TC Energy Merger, TC PipeLines unitholders will become TC Energy shareholders, and the market price for TC Energy common shares may be affected by factors different from those that historically have affected TC PipeLines.

Upon completion of the TC Energy Merger, TC PipeLines unitholders will become TC Energy shareholders. TC Energy’s businesses differ from those of the Partnership, and accordingly, the results of operations of TC Energy will be affected by some factors that are different from those currently affecting the results of operations of the Partnership.

The TC Energy Merger Agreement may be terminated in accordance with its terms and there is no assurance when or if the TC Energy Merger will be completed.

The completion of the TC Energy Merger is subject to the satisfaction or waiver of a number of conditions as set forth in the TC Energy Merger Agreement, including, among others, (i) the adoption of the TC Energy Merger Agreement by an affirmative vote of the holders of a majority of all of the outstanding TC PipeLines common units entitled to vote at the special meeting, (ii) the approval in connection with the TC Energy Merger for listing on the NYSE and the Toronto Stock Exchange of the TC Energy common shares to be issued to TC PipeLines unitholders in connection with the TC Energy Merger, subject to official notice of issuance, (iii) the expiration or early termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and any required approval or consent under any other applicable antitrust law must have been obtained, (iv) no governmental entity of competent jurisdiction shall have enacted, issued, promulgated, enforced or entered any law or governmental order (whether temporary, preliminary or permanent) that is in effect and restrains, enjoins, makes illegal or otherwise prohibits the consummation of the transactions contemplated by the TC Energy Merger Agreement, (v) the registration statement having been declared effective by the SEC and (vi) other customary closing conditions, including the accuracy of each party’s representations and warranties (subject to specified materiality qualifiers), and each party’s material compliance with its covenants and agreements contained in the TC Energy Merger Agreement. There can be no assurance as to when these conditions will be satisfied or waived, if at all, or that other events will not intervene to delay or result in the failure to complete the TC Energy Merger.

In addition, the Partnership will be obligated to (i) pay TC Energy a termination fee equal to $25 million or (ii) pay TC Energy an expense reimbursement amount equal to $4 million. The TC Energy Merger Agreement also provides that upon termination of the TC Energy Merger Agreement under certain circumstances TC Energy will be obligated to pay the Partnership an expense reimbursement amount equal to $4 million.

Failure to complete, or significant delays in completing, the TC Energy Merger could negatively affect the trading prices of the TC PipeLines common units or the future business and financial results of TC PipeLines.

The completion of the TC Energy Merger is subject to certain customary closing conditions and there is no certainty that the various closing conditions will be satisfied and that the necessary approvals will be obtained. If these or other conditions are not satisfied or if there is a delay in the satisfaction of such conditions, then TC Energy and TC PipeLines may not be able to complete the TC Energy Merger timely or at all, and such failure or delay may have other adverse consequences. If the TC Energy Merger is not completed or is delayed, TC Energy and TC PipeLines will be subject to a number of risks, including:

•TC Energy and the Partnership may experience negative reactions from the financial markets, including negative impacts on the market price of TC PipeLines common units, particularly to the extent that their current market price reflects a market assumption that the TC Energy Merger will be completed;

•TC Energy and the Partnership will not realize the expected benefits of the combined company; and

•some costs relating to the TC Energy Merger, such as investment banking, legal and accounting fees, and financial printing and other related charges, must be paid even if the TC Energy Merger is not completed.

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The Partnership and TC Energy will incur substantial transaction fees and costs in connection with the TC Energy Merger.

The Partnership and TC Energy have incurred and expect to incur additional material non-recurring expenses in connection with the TC Energy Merger and completion of the transactions contemplated by the TC Energy Merger Agreement, including costs relating to obtaining required approvals. The Partnership and TC Energy have incurred significant legal, advisory and financial services fees in connection with the process of negotiating and evaluating the terms of the TC Energy Merger. Additional significant unanticipated costs may be incurred in the course of coordinating the businesses of the Partnership and TC Energy after completion of the TC Energy Merger. Even if the TC Energy Merger is not completed, the Partnership and TC Energy will need to pay certain costs relating to the TC Energy Merger incurred prior to the date the TC Energy Merger was abandoned, such as legal, accounting, financial advisory, filing and printing fees. Such costs may be significant and could have an adverse effect on the parties’ future results of operations, cash flows and financial condition. In addition to its own fees and expenses, each of TC PipeLines and TC Energy may be required to reimburse the other party for its reasonable out-of-pocket expenses incurred in connection with the TC Energy Merger Agreement, subject to a cap of $4 million, in the event the TC PipeLines unitholders or TC Energy shareholders, respectively, do not approve the matters required to be voted upon by TC PipeLines unitholders or TC Energy shareholders, respectively, and the TC Energy Merger Agreement is terminated.

President Biden’s revocation of the federal permit for the Keystone XL will negatively affect TC Energy's earnings.

On January 20, 2021, President Biden signed an executive order revoking the existing Presidential Permit for the Keystone XL pipeline. As a result, TC Energy has suspended advancement of the project while it reviews the decision, assesses its implications and considers its options. TC Energy has ceased capitalizing costs, including interest during construction, effective January 20, 2021, and is evaluating the carrying value of its investment in the pipeline, net of project recoveries. TC Energy expects to record a substantive, predominantly non-cash, after-tax charge to its earnings in first quarter 2021, which will be excluded from comparable earnings. Additionally, accounting implications in first quarter 2021 and beyond, will depend on the assessment and consideration of options, including the impacts that this has had on contractual arrangements. As a result, TC Energy cannot quantify the magnitude of the impairment charge and related recoveries at this time. These steps, absent intervening events, will negatively affect TC Energy's earnings and could have a negative impact on TC Energy’s stock price.

RISKS RELATED TO OUR PIPELINE SYSTEMS

We may experience changes in demand for our transportation services which may lead to an inability of our pipelines to charge maximum rates or renew expiring contracts.

Our primary exposure to market risk and competitive pressure occurs at the time existing shipper contracts expire and are subject to renegotiation and renewal. Majority of our pipeline systems’ revenue is generated from long-term, fixed fee transportation agreements. Depending on market conditions at the time of contract expiration and renewal, shippers may be unwilling to renew their contracts for long terms or at favorable rates. The inability of our pipeline systems to extend or replace expiring contracts on comparable terms could have a material adverse effect on our business, financial condition, results of operations and our ability to make cash distributions. Our ability to extend and replace expiring contracts, particularly long-term firm contracts, on terms comparable to existing contracts, depends on many factors beyond our control, including:

● •changes in upstream and downstream pipeline capacity, which could impact the pipeline’s ability to contract for transportation services;

● •the availability and supply of natural gas in Canada and the U.S.;

● •competition from alternative sources of supply;

● •competition from other existing or proposed pipelines;

● •contract expirations and capacity on competing pipelines;

● •changes in rates upstream or downstream of our pipeline systems, which can affect our pipeline systems’ relative competitiveness;

● •basis differentials between the market location and location of natural gas supplies;

● •the liquidity and willingness of shippers to contract for transportation services on a long-term fixed fee basis; and

● •the impact of regulations, public policy and consumer demand for renewal energy on shipper contracting practices.

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Rates and other terms of service for our pipeline systems are subject to approval and potential adjustment by FERC, which could limit the ability to recover all costs of capital and operations and negatively impact their rate of return, results of operations and cash available for distribution.

Our pipeline systems are subject to extensive regulation over effectively all aspects of their business, including the types and terms of services they may offer to their customers, construction of new facilities, creation, modification or abandonment of services or facilities, and the rates that they can charge to shippers. Under the Natural Gas Act, their rates must be just, reasonable and not unduly discriminatory. Actions by FERC, such as refusing to honor existing moratoria on rate changes, could adversely affect our pipeline systems’ ability to recover all current or future costs and could negatively impact their rate of return, results of operations and cash available for distribution. This could result in lower than anticipated distributable cashflow and necessitate a distribution reduction from the current quarterly level of $0.65 per common unit.

~~We are dependent on the continued availability of and demand for natural gas in relation to our pipeline systems.~~36 TC PipeLines, LP Annual Report 2020

AsTable ~~the long-term contracts on our pipeline systems expire, the demand for transportation service on our pipeline systems will depend on the availability~~ of supply from the basins connected to our systems and the demand for natural gas in the markets we serve. Natural gas availability from basins depends upon numerous factors including basin production costs, production levels, environmental regulation, availability of storage and natural gas prices. Our pipeline systems are also dependent on the continued demand for natural gas in their market areas. If supply and/or demand should significantly fall, our pipeline systems may be at risk for loss of contracting or contracting at discounted rates which could impact our revenues.Contents

~~Our~~services or facilities, and the rates that they can charge to shippers. Under the NGA, their rates must be just, reasonable and not unduly discriminatory. Actions by FERC, such as refusing to honor existing moratoria on rate changes, could adversely affect our pipeline systems’ ~~business~~ability ~~systems~~to ~~could~~recover beall current or future costs and could negatively ~~impacted~~impact bytheir ~~security~~rate ~~threats~~of return, ~~including~~results ~~cyber~~of ~~security~~operations ~~threats,~~and cash available for distribution. This could result in lower than anticipated distributable cash flow and ~~related~~necessitate ~~disruptions~~a distribution reduction from the current quarterly level of $0.65 per common unit.

In 2012, the U.S. Department of Homeland Security issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations or “cyber security” events. During 2016, PHMSA posted warnings to all pipeline owners and operators of the importance of safeguarding and securing their pipeline facilities and monitoring their supervisory control and data acquisition (SCADA) systems for abnormal operations and/or indications of unauthorized access or interference with safe pipeline operations based on recent incidents involving environmental activists.

These potential security events might include our pipeline systems or operating systems and may result in damage to our pipeline facilities and affect our ability to operate or control our pipeline assets; their operations could be disrupted and/or customer information could be stolen.

We depend on the secure operation of our physical assets to transport the energy we deliver and our information technology to process, transmit and store electronic information, including information TC Energy uses to safely operate our pipeline systems. Security breaches could expose our business to a risk of loss, misuse or interruption of critical physical assets or information and functions that affect the pipeline operations. Such losses could result in operational impacts, damage to our assets, public or personnel safety incidents, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions, litigation and a potential material adverse effect on our operations, financial position and results of operations. There is no certainty that costs incurred related to securing against threats will be recovered through rates.

If our pipeline systems do not make additional capital expenditures sufficient to offset depreciation expense, our rate base will decline and our earnings and cash flow could decrease over time.

Our pipeline systems are allowed to collect from their customers a return on their assets or “rate base” as reflected in their financial records, as well as recover a portion of that rate base over time through depreciation. In the absence of additions to the rate base through capital expenditures, the rate base will decline over time, and in the event of a rate proceeding, this could result in reductions in revenue, earnings and cash flows of our pipeline systems.

Our pipeline systems’ indebtedness and commitments may limit their ability to borrow additional funds, make distributions to us or capitalize on business opportunities.

Our pipeline systems’ respective debt levels and commitments could have negative consequences to each of them and the Partnership, including the following:

● •their ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on favorable terms;

● •their need for cash to fund interest payments on the debt reduces the funds that would otherwise be available for operations, future business opportunities and distributions to us;

● •their debt level may make them more vulnerable to competitive pressures or a downturn in their business or the economy generally; and

● •their debt level may limit their flexibility in responding to changing business and economic conditions.

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Our pipeline systems’ ability to service their respective debt will depend upon, among other things, future financial and operating performance which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond their control.

Our pipeline systems are subject to operational hazards and unforeseeable interruptions that may not be covered by insurance.

Our pipeline systems are subject to inherent risks such as, ruptures, earthquakes, adverse weather conditions, natural disasters, terrorist activity, civil disobedience or acts of aggression, third-party activity, and pipeline or equipment failure. Any of these risks could cause damage to one of our pipeline systems, business interruptions, a release of pollution or contaminants into the environment or other environmental hazards, or injuries to persons and property. The Partnership could suffer a substantial loss of revenue and incur significant costs to the extent they are not covered by insurance under our pipeline systems’ shipper contracts, as applicable. Additionally, if one of our pipeline systems was to experience a serious pipeline failure, a regulator could require us to conduct testing of the pipeline system or upgrade segments of a pipeline unrelated to the failure, resulting in potential costs not covered by insurance or recoverable through rate increases. We could also face a potential reduction in operational parameters which could reduce the capacity available for sale.

Our ~~pipelines~~pipeline ~~could~~systems bemay ~~subject~~experience tosignificant ~~penalties~~costs and ~~fines~~liabilities ifrelated ~~they fail~~ to ~~comply~~compliance with FERC regulations and pipeline safety laws and regulations.

Our pipelines are subject to substantial penalties and fines in the event that our pipeline systems have failed to comply with all applicable FERC-administered statutes, rules, regulations and orders, or the terms of their tariffs on file with FERC. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA and ~~NGPA~~the Natural Gas Policy Act of 1978 to impose penalties for violations of up to approximately $1.2931 million per day for each violation, to revoke existing certificate authority and to order disgorgement of profits associated with any violation.

~~Our~~Additionally, our pipeline systems ~~may~~are ~~experience~~subject to pipeline safety statutes and regulations administered by PHMSA that require compliance with stringent operational and safety standards. For example, the ongoing implementation of the pipeline integrity management programs could cause our pipeline systems to incur significant ~~costs~~and unanticipated capital and ~~liabilities~~operating ~~related~~expenditures for repairs or upgrades deemed necessary to ~~compliance~~ensure their continued safe and reliable operation. Additionally, we are subject to pipeline safety requirements that may impose more stringent safety obligations, require installation of new or modified safety controls, or perform capital or operating projects on an accelerated basis. Failure to comply with PHMSA’s regulations could subject our pipeline systems to penalties, fines or restrictions on our pipeline systems’ operations. New legislation or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety ~~laws~~aspects of our operations, which could cause us to incur increased operating and ~~regulations~~capital costs and result in operational delays.

Our ~~pipeline~~compliance ~~systems~~with ~~are~~these ~~subject~~applicable toPHMSA pipeline safety ~~statutes~~requirements ~~and~~could ~~regulations~~have ~~administered~~a bymaterial ~~PHMSA~~adverse effect on our operations, ~~which~~financial ~~require~~position, ~~pipeline~~cash ~~operators~~flows, and our ability to ~~develop~~maintain ~~integrity~~current ~~management~~distribution ~~programs.~~levels to the extent the increased costs

The ongoing implementation of the pipeline integrity management programs could cause our pipeline systems to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure their continued safe and reliable operation and to comply with the federal pipeline safety statutes and regulations. Additionally, we are subject to pipeline safety requirements that may impose more stringent safety obligations, require installation of new or modified safety controls, or perform capital or operating projects on an accelerated basis. Failure to comply with PHMSA’s regulations could subject our pipeline systems to penalties, fines or restrictions on our pipeline systems’ operations. New legislation or regulations adopted by PHMSA in recentTC ~~years may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations~~PipeLines, ~~which could cause us to incur increased operating and capital costs and result in operational delays.~~ LP Annual Report 2020 37

The adoption of new PHMSA regulations could result in our pipeline systems incurring significant expenditures to comply, which could have a material adverse effect on our operations, financial position, cash flows, and our ability to maintain current distribution levels to the extent the increased costs are not recoverable through rates. For further discussion on pipeline safety matters, see Part I, Item 1 “Government Regulation” – “Pipeline Safety Matters.”

Our pipeline systems are subject to federal, state and local environmental laws and regulations that could impose significant compliance-related costs and liabilities, or make the execution of our growth projects uneconomic or impossible.

New environmental laws, regulations, and enforcement policies could potentially increase our compliance-related costs. For example, since 2015, the EPA has made numerous revisions to the National Ambient Air Quality Standard (NAAQS) for ground-level ozone and its implementation under the CAA. Revisions included making the standard stricter and designating attainment and nonattainment regions. State implementation of the revised ozone NAAQS could increase our compliance costs, for example, by increasing our capital expenditures to install required emissions controls on certain equipment and by increasing operating costs through the prolonging of the permitting process.

Additionally, the promulgation of environmental regulations interpreting the complex and highly contentious definition of WOTUS under the CWA could give rise to significant future compliance-related costs. In 2015, the EPA and U.S. Army Corps of Engineers (Corps) released the Clean Water Rule, which expanded the definition of waters protected under the CWA. The rule would affect the oil and gas pipeline industry for example, by subjecting companies to federal regulation and permitting requirements under the CWA for construction, repair, replacement and even routine maintenance of pipeline facilities in or near waters in the expanded definition. Since 2015, numerous revisions to the rule have been made and debate on the subject between stakeholders has been ongoing. The numerous legal challenges to the many iterations of the rule have led to conflicting court decisions. In 2019, the EPA and the Corps rescinded the rule and on January 23, 2020, the EPA and Corps issued a final rule re-defining the jurisdiction of the federal government with respect to Waters of the U.S., making such jurisdiction narrower than was allowed under the rescinded 2015 Clean Water Rule. Upon being published in the Federal Register and the passage of 60 days thereafter, the January 23, 2020 final rule will

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~~become~~are ~~effective~~not ~~and~~recoverable ~~the~~through ~~United States will be covered under a single regulatory scheme as it relates to federal jurisdictional reach over Waters of the U~~rates.~~S. However,~~ ~~there~~For ~~remains~~further ~~the~~discussion ~~expectation~~on ~~that~~pipeline ~~the~~safety ~~January 23~~matters, ~~2020~~see ~~final~~Part ~~rule will be legally challenged in federal district court. To the extent that any challenge to the January 23~~I, ~~2020~~Item ~~final~~1 ~~rule~~“Government isRegulation” ~~successful~~– ~~and~~“Pipeline ~~the~~Safety 2015 rule or a revised rule expands the scope of the Clean Water Act’s jurisdiction in areas where we conduct operations, pipeline companies such as us may become subject to more burdensome federal regulation and CWA permitting requirementsMatters. ~~Although there is insufficient information at this time to assess the extent of the impact, an increase in operating costs and capital expenditures is expected.~~”

~~Additionally,~~Our inpipeline ~~2019~~systems ~~the~~are ~~EPA~~subject ~~published a proposed rule~~ to ~~implement CWA Section 401~~federal, ~~which~~state ~~requires states~~ and~~/or~~ ~~authorized~~local ~~tribes~~environmental tolaws ~~grant, deny, or waive a water quality certification for major federal licenses~~ and ~~permits. The proposed rule clarifies various aspects of the current Section 401~~ regulations, ~~including~~that ~~the~~could ~~actions~~impose ~~triggering~~significant acompliance-related ~~Section~~costs ~~401 review, as well as the timeliness~~ and ~~scope of state and tribal review. Notably~~liabilities, ~~the~~or ~~EPA~~make ~~narrows~~ the ~~scope~~execution of ~~state~~our ~~and~~growth ~~tribal~~projects ~~review~~uneconomic toor preclude them from considering issues other than water quality in their certifications and curtails delays in decision-making by defining the amount of time states and tribes have to consider permit applicationsimpossible.

~~Furthermore~~Owing to the nature of our pipeline operations, ~~under~~we ~~certain~~are subject to stringent environmental laws and regulations wethat ~~may~~compel becompliance ~~exposed~~with tonumerous ~~substantial~~obligations ~~liabilities~~that ~~for~~are ~~pre-existing~~applicable ~~contamination~~to ~~connected~~our tooperations ~~past~~including acquisition of permits or ~~current~~other ~~operations.~~approvals ~~For~~before ~~example~~conducting regulated activities, ~~during~~restrictions ~~routine~~on ~~maintenance~~the ~~activities~~types, quantities and concentration of ~~our~~materials ~~pipelines~~that can be released into the environment; limitation or prohibition of construction and ~~related~~operating ~~facilities~~activities in environmentally sensitive areas such as wetlands, weurban ~~may~~areas, ~~discover~~wilderness ~~historical~~regions ~~hydrocarbon~~and orother ~~PCB~~protected ~~contamination.~~areas; ~~Discovery~~requiring capital expenditures to comply with pollution control requirements, and imposition of ~~such~~substantial ~~contaminants~~liabilities ~~would~~for ~~require~~pollution ~~prompt~~resulting ~~notification~~from our operations. Failure to comply with these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctions including administrative, civil and criminal penalties, the ~~appropriate~~imposition ~~governmental~~of ~~authorities~~investigatory, remedial and corrective ~~actions~~action toobligations ~~timely~~or ~~mitigate~~the incurrence of capital expenditures; the ~~contamination.~~occurrence ~~Moreover~~of restrictions, andelays ~~accidental~~or ~~release~~cancellations in the permitting or performance of ~~materials~~projects, ~~into~~and the ~~environment~~issuance ~~during~~of ~~the~~orders ~~course~~enjoining or conditioning performance of some or all of our operations ~~may~~in ~~cause~~a usparticular toarea. ~~incur~~Environmental ~~significant~~compliance and enforcement costs and liabilities in connection with our natural gas pipelines may come, for example, from air emissions and product-related discharges, impacts to regulated water bodies and threatened or endangered species as well as historical industry operations and waste disposal practices. ~~Remedial~~For ~~costs~~example, ~~penalties~~an accidental release from ~~governmental~~one ~~agencies~~of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages ~~could~~and ~~have~~fines aor ~~material~~penalties ~~adverse~~for ~~effect~~related onviolations ~~our~~of ~~liquidity~~environmental laws or regulations. Moreover, ~~results~~the adoption and implementation of ~~operations~~new environmental laws, regulations, judicial decisions, and ~~financial~~enforcement ~~condition.~~policies ~~For~~could ~~further~~potentially ~~discussion~~increase onour compliance-related costs, particularly in the realm of climate change and GHG regulation. Some high-profile federal environmental ~~matters~~laws and regulations that may impose significant compliance related costs and make the execution of our pipeline projects more difficult include the uncertainty surrounding the use of the USACE’s NWPs, ~~see~~specifically ~~Part~~NWP I12, ~~Item~~for 1utility construction, maintenance, repair, and relocation activities affecting WOTUS. The ever-changing definition of WOTUS, amendments made to the CWA Section 401 water quality certification process, the criminalization of the “~~Government~~incidental ~~Regulation~~take” –of migratory birds, its nests, or its eggs under the MBTA, policy and technical amendments made to NSPS for stationary sources of air emissions, the “~~Environmental~~Once ~~Matters~~in Always in” HAPs policy, and the new authority given to PHMSA to regulate methane emissions from pipelines are additional examples of federal actions that will likely impose additional compliance-related costs and make project execution more difficult.

Furthermore, the Partnership may be specifically burdened by compliance-related costs at the state level in Oregon due to the implementation of the EPA’s Regional Haze Rule. In 2020, the State of Oregon identified two GTN Stations as significant sources of regional haze precursor emissions to Class I areas in Oregon. This identification was made as part of the State’s development of its 2021 air quality protection plan implementing the federal Regional Haze Rule that requires states to improve visibility in national parks and wilderness. The Rule required ODEQ to identify sources of emissions that could be reduced with reasonable control methods to improve visibility in Class I areas under its state plan. The identification of the two GTN stations triggered the need to submit a four-factor analysis for five turbines at the stations. A four-factor analysis under the Regional Haze Rule is used to determine if there are “reasonable” controls available for reducing the visibility impairing emissions, primarily Nitrogen Oxides (NOx) for the GTN facilities. Based on the four-factor analyses ODEQ removed one turbine from consideration for additional controls. If GTN is ultimately required to install NOx controls on the four remaining units under review in Oregon’s final state implementation plan, the capital expenditures that will be incurred by GTN could be material.

Increased compliance costs, the incurrence of remedial costs, penalties from governmental agencies, and other damages could have a material adverse effect on our liquidity, results of operations, and financial condition. For further discussion on environmental matters, see Part I, Item 1 “Government Regulation” – “Environmental Matters”.

Our operations are subject to a series of risks arising from the threat of climate change that could lead to increased construction and operating costs and could also potentially reduce demand for our systems and services.

Climate change continues to attract considerable public, governmental, and scientific attention ~~both domestically~~ in the ~~U.S.~~United States and internationally. ~~Considered to be the leading driver of climate change, GHG emissions remain at the forefront of the climate change debate.~~ The Partnership, along with the greater oil and gas industry, has a vested interest in the climate change debate since increased scrutiny on the cause of climate change subjects our operations to avarious ~~number of~~ regulatory, political, litigation, and financial risks. These risks may lead to material adverse effects on our business, financial condition, and results of operations. In the United States, no comprehensive federal climate change legislation has been implemented but President Biden taking office and Democratic control of the U.S. House of Representatives and Senate, the adoption of such legislation is very likely in the coming years. President Biden's administration has made efforts to combat climate change one of its top four priorities and, as promised, took immediate action within President Biden's first week in office by issuing a number of executive actions addressing climate change. These early executive actions included an executive order to rejoin the Paris Agreement, and directive to heads of federal departments and agencies to review agency actions promulgated, issued, or adopted between January 20, 2017 and January 20, 2021, for consistency with public health and environmental protection policy goals of the EO. If inconsistent, the EO directs agencies to consider suspending, revising, or rescinding the agency actions. Notably, the EO includes directives related

~~Regulatory Risk~~38 TC PipeLines, LP Annual Report 2020

With the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, efforts continue to be made at all levels of government within the U.S. to regulate GHGs and define the parameters of regulation. While no comprehensive climate change legislation has been implemented at the federal level, the EPA and numerous state agencies have pursued legal initiatives to reduce GHG emissions using tools like cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that require monitoring and reporting of GHG emissions and limiting GHGs directly from certain sources. Additionally, in 2019 the White House Council on Environmental Quality (CEQ) published draft guidance to assist federal agencies with the consideration of GHG emissions in NEPA analyses of environmental impacts of proposed major federal actions, such as some interstate natural gas pipeline projects. The CEQ took a deferential approach in its guidance by encouraging federal agencies to consider GHG emissions if it would be meaningful to the agencies’ decision-making and to rely on their expertise, experience, and the “rule of reason.”

In recent years, there has been a particular focus on the regulation of methane, a GHG. The regulation of methane emissions is of importance to the oil and gas industry since methane is the primary component in natural gas. In 2012 and 2016, the EPA promulgated rules requiring certain new, modified or reconstructed facilities in the oil and gas sector to reduce methane and specific volatile organic compounds (VOCs). Notably, the rules required the installation of technology to detect and repair methane leaks from pipelines, new wells, and storage facilities. In 2019, the EPA proposed amendments to the rules to remove regulatory duplication and requested comments on alternative measures that would further this aim. The first approach is to eliminate methane and VOC requirements for sources in the transmission and storage segment in the oil and gas industry, and rescind the methane requirements for sources in the production and processing segments. An alternative approach would be to rescind the methane-specific requirements that apply to all sources in the oil and natural gas industry, without removing the transmission and storage sources from the current source category. Under either alternative, the EPA plans to retain emissions limits for VOCs. While the relaxation of methane requirements on the oil and gas industry is positive, if the proposed amendments are made final, they will likely be legally challenged by interested parties. For example, in the month following the proposed amendments, legislation was introduced in the U.S. Senate to combat methane pollution from pipelines by reducing leaks of methane and other hazardous gases and pollutants. Similar methane leak reduction language was introduced as an amendment to the Senate Commerce, Science, and Transportation Committee’s Pipeline Safety Act (PSA) reauthorization bill. The

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~~reauthorization~~to the establishment of the ~~PSA~~social ~~allows~~cost of GHGs and specifically directs EPA to review its recent methane technical amendment to the NSPS for stationary sources and to propose revisions to existing source standards by September 2021. The new Administration also revoked the ~~continued~~Keystone ~~funding~~XL presidential permit and put a pause on new oil and gas leases on federal lands. Moreover, the EPA and numerous state and local governments have pursued legal initiatives to reduce GHG emissions using tools like cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that require monitoring and reporting of ~~PHMSA~~GHG emissions and ~~its~~limiting ~~pipeline~~GHGs ~~safety~~directly ~~program~~from certain sources. ~~Methane~~The general trend towards increased regulation of GHG emissions ~~provisions~~in ~~are~~the ~~now~~oil ~~being~~and ~~considered~~natural gas sector as a means to combat climate change, supported by President Biden's administration’s climate agenda, could increase the Partnership’s costs of regulatory compliance and/or reduce demand for ~~inclusion~~our systems and services due to regulations and policies incentivizing consumer use of alternative energy sources (such as wind, solar geothermal, tidal and biofuels), and imposing limitations and restrictions on fossil fuel-related activities that reduce demand for GHG-intensive fossil fuels. Litigation and financial risks as a result of climate change may also adversely impact fossil fuel activities by our customers that, in turn, could have an adverse effect on the demand for our service. These political, litigation, and financial risks may result in our customers restricting or cancelling production activities, incurring liability for infrastructure damages as a ~~final~~result ~~bill~~of climatic changes, or impairing their ability to continue to operate in an economic manner, which ~~would~~also ~~essentially~~could ~~authorize~~reduce ~~PHMSA~~demand for our services and have a material adverse effect on the Partnership’s business and operations. For further discussion on environmental matters, see Part I, Item 1 “Government Regulation” – “Legal Initiatives to beCombat ~~another~~Climate ~~federal~~Change ~~regulator~~and ofRestrict Greenhouse Gas (GHG) ~~emissions~~Emissions”.

The trend towards increased regulation of GHG emissions in the oil and natural gas sector as a means to combat climate change could increase the Partnership’s costs of regulatory compliance and/or reduce demand for our systems and services due to regulations and policies incentivizing the use of alternative fuels by consumers and reducing demand for GHG-intensive fossil fuels. However, at this time there remains a great deal of uncertainty in GHG emissions legislation, regulation, and policies at the federal level, as the governing Administration attempts to alleviate burdensome GHG requirements placed on industry that may hinder economic development.

Political Risk

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the U.S., including climate change related pledges made by candidates seeking the office of the President of the United States in 2020. More than one candidate running for the Democratic nomination for President has declared to combat climate change through various means such as banning hydraulic fracturing of crude oil and natural gas wells and banning new leases for production of minerals on federal properties, including onshore lands and offshore waters. A new Presidential Administration could also pursue the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as the reversal of the United States’ withdrawal from the Paris Agreement in November 2020. The Paris Agreement is a non-binding United Nations-sponsored international accord to combat climate change through the establishment of individually-determined GHG emissions reduction goals. The current Administration began the lengthy process of withdrawing the United States from the Agreement in 2019, but the fate of the withdrawal may be dependent on the results of the 2020 Presidential Election.

Litigation Risk

Litigation risks are also increasing, as a number of state and local governments have sought to bring suit against energy companies, including natural gas transmission companies, in an effort to curb energy infrastructure as a means to further regulate GHGs. While state and local governments are considering certain legislative options, they are also increasingly evaluating litigation as an option. For example, some suits alleged that certain energy companies created public nuisances by contributing to global warming effects, such as rising seas levels, and are therefore responsible for resulting roadway and infrastructure damages. Other suits have alleged that the companies have been aware of their operations causing adverse effects of climate change for some time but have defrauded their investors by failing to adequately disclose those impacts. Moreover, state and local governments, as well as non-governmental organizations, are increasingly challenging, on a number of environmental and non-environmental grounds related to GHG review, the granting of federal and state environmental permits even though FERC authorization has been obtained.

Financial Risk

There are also growing financial risks as stockholders and bondholders who are currently invested in fossil-fuel energy companies become increasingly concerned about the potential effects of climate change and consider shifting some or all of their investments into non-fossil fuel energy related sectors. Additionally, some institutional lenders, who provide financing to fossil-fuel energy companies, have become more attentive to sustainable lending practices and may elect not to provide funding for fossil fuel energy companies. The lending and investing practices of institutional lenders have also been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change and the continued funding of fossil fuel producers.

Steadily increasing support for climate change legislation and regulations restricting or regulating GHGs by states and U.S. territories could increase operating and capital costs for our customers and reduce demand for our systems and services.

In the absence of consistency and predictability in GHG emissions legislation, regulation and policies at the federal level, state and U.S. territories are taking GHG regulation into their own hands. The commitment to lowering GHGs is growing significantly and steadfast. In addition to passing legislation and promulgating regulations for GHG emissions, numerous states have taken advantage of tools like cap-and-trade programs, carbon taxes, as well as GHG reporting and tracking programs. A bipartisan coalition of governors from twenty-five states and U.S. territories have established the U.S. Climate Alliance to combat climate change through the implementation of state policies that are consistent with the U.S. goal of the Paris Agreement. Many of these policies are currently affecting or expected to affect our assets residing in those specific states and significantly increase our compliance-related costs. For example, Oregon recently established a program to regulate air emissions from industrial and commercial facilities by requiring the performance of health risk assessments for new and existing facilities and amending existing air permits if necessary. This may impact GTN’s compressor stations in Oregon in the coming years. Additionally, a historically contentious piece of cap-and-trade

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legislation, which would have significant impacts on our GTN assets in Oregon, is expected to return for consideration by the Oregon legislature in 2020. GTN is expected to be further impacted by Washington state’s enactment of a 100 percent clean energy law. Our Tuscarora facilities in California may also be impacted by the state’s new climate change plan that includes a GHG cap-and-trade program and regulations on the monitoring and repair of methane leaks at oil and gas sites.

The regulation of GHGs to combat climate change is garnering increasing support, particularly at the state level. The increasing adoption and implementation of legislation and regulations that require reporting of GHGs or otherwise restrict emissions of GHGs will likely increase both operating costs and capital expenditures. Compliance-related costs and additional operating restrictions could have a material adverse effect on our business, financial condition, demand for our systems and services, results of operations, and cash flows. Finally, increasing concentrations of GHGs in the Earth's atmosphere may lead to significant climate changes with an increase in frequency and severity of storms, droughts, floods and other weather events that may have an adverse effect on our financial condition, results of operations, and the financial condition and operations of our customers.

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

The presence of a chemical substance, dithiazine, has been discovered at several facilities on the GTN system, as well as some upstream and downstream connecting pipelines. Dithiazine is a byproduct of triazine which is a liquid chemical scavenger used in the natural gas production industry to remove hydrogen sulfide (H2S) from natural gas streams. None of our pipelines utilize triazine in the facilities or operations, however, dithiazine may drop out of gas streams, under certain conditions, in a powdery form at certain points of pressure reduction. The powdered dithiazine has the potential to interfere with equipment functionality if a sufficient quantity of the material accumulates in certain appurtenances, leading to increased preventative and corrective action costs.

GTN and TC Energy are ~~gathering information and~~ working collaboratively with customers, producers, vendors, ~~and other stakeholders in an effort to develop and implement a joint plan to address each stakeholders’ respective issues, and have informed~~ federal and state regulators, trade associations, and other stakeholders ofto address the ~~issue~~matter. GTN has also taken steps, incurred costs and made capital expenditures to address the matter. Between 2018 and ~~2019~~2020, GTN has spent capital expenditures of approximately $1320 million and has incurred operating costs of approximately $23 million. Unless the issue is resolved, GTN expects to spend approximately $63 million in capital expenditures and $1 million in operating costs ~~between~~in ~~2020 and~~ 2021 to further resolve the matter. There is no assurance that significant additional costs will not be incurred in the future or that dithiazine or other substances will not be identified on our other pipeline systems.

We are exposed to credit risk when a customer fails to perform its contractual obligations.

Our pipeline systems are subject to a risk of loss resulting from the nonperformance by a customer of its contractual obligations. Our exposure generally relates to receivables for services provided and future performance over the remaining contract terms under firm transportation contracts. Our pipelines’ FERC approved tariffs limit the amount of credit support that they may require in the event that a customer’s creditworthiness is or becomes unacceptable. If a significant customer has financial problems, which result in a delay or failure to pay for services provided by them or contracted for with them, it could have a material adverse effect on our business and results of operations.

The operation of portions of our pipeline systems requires easements or rights-of-way across land owned by Native American tribes, governmental authorities and other third parties, the cost or denial of which could result in disruption to operations and higher costs that adversely affect our business, financial condition and results of operations.

The majority of the land on which our pipeline systems are located is leased pursuant to easements, rights-of-way and other land use rights from individual landowners, Native American tribes, governmental authorities and other third parties, the majority of which are perpetual and obtained through agreements with land owners or legal process, if necessary. Certain rights, however, are subject to renewal and, with respect to tribal land held in trust by the Bureau of Indian Affairs (BIA), approval by the applicable tribal governing authorities and the BIA. The cost of obtaining or renewing rights-of-way across tribal land can be significantly high. The inability to renew a right-of-way on tribal land at reasonable cost could require capital expenditures for removal and relocation of portions of pipeline and disrupt operations. Such costs could negatively impact the results of operations and cash available for distribution from our pipeline systems.

During the second quarter of 2018, rights-of-way expired for approximately 7.6 miles of our Great Lakes pipeline on tribal land located within the Fond du Lac Reservation (Fond Du Lac) and Leech Lake Reservation (Leech Lake) in Minnesota and the Bad River Reservation (Bad River) in Wisconsin. Great Lakes subsequently received a demand letter in April 2019 from the Fond duDu Lac Tribal Chairman to immediately cease operation of the Great Lakes pipeline and begin the process of removing all infrastructure from tribal land. Following receipt of the demand letter, weGreat Lakes executed a Memorandum of Agreement with ~~the~~ Fond duDu Lac ~~tribal authorities~~ relating to the negotiation of a new right-of-way. ~~and~~Great ~~are~~Lakes ~~negotiating~~continues ~~or in discussions~~ to ~~obtain~~negotiate ~~new rights-of-way~~ with ~~the~~Fond ~~tribal~~Du ~~authorities~~Lac ~~for~~and ~~the~~are ~~three~~in ~~reservations.~~advanced Wediscussions ~~cannot~~with ~~predict~~Bad ~~the outcome of these negotiations~~River. IfIn welate ~~are~~2020, ~~unable~~Great toLakes ~~obtain~~has ~~new~~reached ~~easements~~an oragreement ~~rights-of-way~~with ~~across~~Leech ~~all~~Lake orsubject ato ~~portion~~further ofapproval from the ~~tribal lands at reasonable rates, or at all,~~ BIA.

~~34 TC PipeLines~~While Great Lakes has progressed on the renewal process, ~~LP Annual Report 2019~~ we cannot predict the full outcome of these negotiations. If we are unable to obtain new easements or rights-of-way across all or a portion of the tribal lands at reasonable rates, or at all, Great Lakes may be required to acquire the necessary rights at significant cost or remove and re-route portions of the pipeline at significant capital expense and disruption to operations that could have a material adverse effect on our financial condition, results of operations and cash flows.

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Great Lakes may be required to acquire the necessary rights at significant cost or remove and re-route portions of the pipeline at significant capital expense and disruption to operations that could have a material adverse effect on our financial condition, results of operations and cash flows.

RISKS RELATED TO OUR PARTNERSHIP STRUCTURE

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We do not have the same flexibility as corporations to accumulate cash and equity to protect against illiquidity in the future.

We are required by our Partnership Agreement to make quarterly distributions to our unitholders of all available cash, reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units and other limited partner interests may decrease in direct correlation with decreases in the amount we distribute per common unit. Accordingly, if we experience a liquidity shortfall in the future, we may not be able to recapitalize by issuing more equity.

Common unitholders have limited voting rights and are not entitled to elect our General Partner or its board of directors and cannot remove our General Partner without its consent.

The General Partner is our manager and operator. Unlike the stockholders in a corporation, holders of our common units have only limited voting rights on matters affecting our business. Unitholders have no right to elect our General Partner or its board of directors. The members of the board of directors of our General Partner, including the independent directors, are appointed by its parent company and not by the unitholders.

~~Common~~Additionally, ~~unitholders~~our ~~cannot~~General ~~remove~~Partner may not be removed except by the vote of the holders of at least 662/3 percent of the outstanding common units. These required votes would include the votes of common units owned by our General Partner ~~without~~and its ~~consent~~affiliates. TC Energy's ownership of approximately 24 percent of our outstanding common units at December 31, 2020, has the practical effect of making removal of our General Partner difficult.

Our General Partner may not be removed except by the vote of the holders of at least 662/3 percent of the outstanding common units. These required votes would include the votes of common units owned by our General Partner and its affiliates. TC Energy's ownership of approximately 24 percent of our outstanding common units at December 31, 2019, has the practical effect of making removal of our General Partner difficult.

In addition, the Partnership Agreement contains some provisions that may have the effect of discouraging a person or group from attempting to remove our General Partner or otherwise change our management. If our General Partner is removed as our general partner under circumstances where cause does not exist and common units held by our General Partner and its affiliates are not voted in favor of that removal:

● •any existing arrearages in the payment of the minimum quarterly distributions on the common units will be extinguished; and

● •our General Partner will have the right to convert its general partner interests and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Our Partnership Agreement restricts voting and other rights of unitholders owning 20 percent or more of our common units.

The Partnership Agreement contains provisions limiting the ability of unitholders to call meetings of unitholders or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. Further, if any person or group other than our General Partner or its affiliates or a direct transferee of our General Partner or its affiliates acquires beneficial ownership of 20 percent or more of any class of common units then outstanding, that person or group will lose voting rights with respect to all of its common units. As a result, unitholders have limited influence on matters affecting our operations and third parties may find it difficult to attempt to gain control of us or influence our activities.

We may issue additional common units and other partnership interests, without unitholder approval, which would dilute the existing unitholders’ ownership interests. In addition, issuance of additional common units or other partnership interests may increase the risk that we will be unable to maintain the quarterly distribution payment at current levels.

Subject to certain limitations, we may issue additional common units and other partnership securities of any type, without the approval of unitholders.

Based on the circumstances of each case, the issuance of additional common units or securities ranking senior to, or on parity with, the common units may dilute the value of the interests of the then-existing holders of common units in the net assets of the Partnership. In addition, the issuance of additional common units may increase the risk that we will be unable to maintain the quarterly distribution payment at current levels.

Our common unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner generally has unlimited liability for the obligations of a limited partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. We are organized under Delaware law and conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states. Our unitholders could be liable for any and all of our obligations as if our unitholders were a general partner if a court or government agency determined that:

TC•the Partnership had been conducting business in any state without compliance with the applicable limited partnership statute; ~~PipeLines, LP Annual Report 2019 35~~or

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~~interests~~•the ~~for~~right, or the ~~obligations~~exercise of athe ~~limited~~right, ~~partnership~~by ~~have~~the ~~not~~unitholders ~~been~~as ~~clearly~~a ~~established~~group into ~~some~~remove ~~states.~~or ~~Our~~replace ~~unitholders~~our ~~could~~General bePartner, ~~liable~~to ~~for~~approve ~~any~~some ~~and~~amendments ~~all~~to ofthe ~~our~~Partnership ~~obligations~~Agreement asor ifto ~~our~~take ~~unitholders~~other ~~were~~action aunder ~~general~~the ~~partner~~Partnership ifAgreement aconstituted ~~court~~participation orin ~~government~~the ~~agency~~“control” ~~determined that:~~of the Partnership’s business.

● the Partnership had been conducting business in any state without compliance with the applicable limited partnership statute; or

● the right, or the exercise of the right, by the unitholders as a group to remove or replace our General Partner, to approve some amendments to the Partnership Agreement or to take other action under the Partnership Agreement constituted participation in the “control” of the Partnership’s business.

In addition, under some circumstances, such as an improper cash distribution, a unitholder may be liable to the Partnership for the amount of a distribution for a period of three years from the date of the distribution.

Our General Partner has a limited call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any time our General Partner and its affiliates own 80 percent or more of the common units, the General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or us, to acquire all of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a consequence, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they would desire to receive upon sale. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, ~~2019~~2020, the General Partner and its affiliates own approximately 24 percent of our outstanding common units.

Our Partnership Agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

The Partnership Agreement contains provisions that eliminate the fiduciary standards to which the General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our Partnership Agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the Partnership Agreement does not provide for a clear course of action. This provision entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our General Partner may make in its individual capacity include:

● •how to allocate corporate opportunities among us and its other affiliates;

● •whether to exercise its limited call right;

● •whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board of Directors;

● •whether to elect to reset target distribution levels;

● •whether to transfer the incentive distribution rights to a third party; and

● •whether or not to consent to any merger or consolidation of the Partnership or amendment to the Partnership Agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the Partnership Agreement, including the provisions discussed above.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

Our common units are listed on the NYSE. Because we are a publicly traded limited partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our Board of Directors or to establish a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

The credit and business risk profiles of our General Partner and TC Energy could adversely affect our credit ratings and profile.

The credit and business risk profiles of our General Partner and TC Energy may be factors in credit evaluations of a master limited partnership because our General Partner can exercise control over our business activities, including our cash distribution and acquisition strategy and business risk profile. Other factors that may be considered are the financial conditions of our General Partner and TC Energy, including the degree of their financial leverage and their dependence on cash flows from us to service their indebtedness.

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Costs reimbursed to our General Partner are determined by our General Partner and reduce our earnings and cash available for distribution.

Prior to making any distribution on the common units, we reimburse our General Partner and its affiliates, including officers and directors of the General Partner, for all expenses incurred by our General Partner and its affiliates on our behalf. During the year ended December 31, ~~2019~~2020, we paid fees and reimbursements to our General Partner in the amount of $4 million (~~2018~~2019 and ~~2017~~2018- $4 million each). Our General Partner, in its sole discretion, determines the amount of these expenses. In addition, our General Partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by ~~the General Partner. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions.~~

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the General Partner. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions.

Changes in TC Energy’s costs or their cost allocation practices could have an effect on our results of operations, financial position and cash flows.

Under the Partnership Agreement, the Partnership’s pipeline systems operated by TC Energy are allocated certain costs of operations at TC Energy’s sole discretion. Accordingly, revisions in the allocation process or changes to corporate structure may impact the Partnership’s operating results. TC Energy reviews any changes and their prospective impact for reasonableness, however there can be no assurance that allocated operating costs will remain consistent from period to period.

TAX RISKS

Our tax treatment depends on our status as a partnership and exemption from entity level taxes for U.S. federal, state and local income tax purposes. If we were to be treated as a corporation or otherwise become subject to a material amount of entity level taxation for U.S. federal, state and local tax purposes, our cash available for distribution to unitholders and the value of our common units could be substantially reduced.

The anticipated after-tax benefit of an investment in us depends largely on our classification as a partnership for U.S. federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes if the Internal Revenue Service (IRS) were to determine that we fail to satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. Failing to meet the qualifying income requirement or any legislative, administrative or judicial change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation at the entity level.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income taxes on our taxable income at the applicable corporate tax rate, and we would likely have to pay state income taxes at varying rates. Distributions to our unitholders (to the extent of our earnings and profits) would generally be taxed again to unitholders as corporate dividends, and no income, gains, losses, deductions or credits would flow through to our unitholders. In the event of a tax imposed upon us as a corporation, the cash available for distribution to our unitholders could be substantially reduced and result in a material reduction in the anticipated cash flow and after-tax return to unitholders, which in turn would likely have a negative impact on the value of our common units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Our Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for U.S. federal, state, or local income tax purposes, then specified provisions of the Partnership Agreement relating to distributions will be subject to change. These changes would include a decrease in cash distributions to unitholders.

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

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

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

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income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future. We believe the income that we treat as qualifying satisfies the requirements under current regulations.

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

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. ~~Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.~~

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Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Under our limited Partnership Agreement, our general partner is permitted to make elections under the new rules to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own our common units during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.

Unitholders may be required to pay taxes on income from us even if they receive no cash distributions.

Because unitholders are treated as partners to whom we allocate taxable income which could be different in amount than the cash distributed, unitholders may be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their allocable share of our income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions equal to their allocable share of our taxable income or even the tax liability that results from that income.

Tax gains or losses on the disposition of common units could be different than expected.

If unitholders sell their common units, they will recognize a taxable gain or loss equal to the difference between the amount realized and their adjusted tax basis in those common units. Prior distributions in excess of the total net taxable income that a unitholder was allocated for a common unit, which distributions decreased the unitholder's tax basis in that common unit, will, in effect, become taxable income if the common unit is sold at a price greater than its adjusted tax basis in that common unit, even if the price is less than the original cost. A substantial portion of the amount realized on the sale of common units, whether or not representing a gain, may be ordinary income to unitholders due to certain items such as potential depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units. If the IRS were to successfully contest some conventions we use, unitholders could recognize more taxable gain on the sale of common units than would be the case under those conventions without the benefit of decreased taxable income in prior years.

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Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, our unitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, subject to certain exceptions in the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act, discussed below) under the 2017 Tax Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” may be limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the 2020 taxable year, the CARES Act generally increases the 30% adjusted taxable income limitation to 50%. For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization or depletion is not capitalized into cost of goods sold with respect to inventory. The interest limitation does not apply to regulated pipeline businesses and, therefore, we believe that our interest expense is fully deductible. If the IRS contests this position or if further guidance is issued contrary to the positions taken, the unitholder’s ability to deduct this interest expense could be limited.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

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Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business ~~(effectively connected income)~~. Income allocated to our unitholders and any gain from the sale of our common units will generally be considered “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person,. ~~and~~While wethe ~~are~~determination ~~required~~of toa ~~deduct~~partner’s ~~and~~amount ~~withhold~~realized ~~from~~generally ~~the~~includes ~~transferee~~any ~~amounts~~decrease ~~that~~of ~~should~~a ~~have~~partner’s ~~been~~share ~~withheld~~of by the ~~transferees~~partnership’s ~~but~~liabilities, ~~were~~recently ~~not~~issued ~~withheld.~~Treasury ~~Because~~regulations provide that the “amount realized” ~~includes~~on a ~~partner’s~~transfer ~~share~~ of ~~the~~an ~~partnership’s~~interest ~~liabilities,~~in ~~10%~~a ofpublicly ~~the~~traded ~~amount~~partnership, ~~realized~~such ~~could~~as ~~exceed~~our ~~the~~common ~~total~~units, ~~cash~~will ~~purchase~~generally ~~price~~be ~~for~~ the ~~units.~~amount ~~However,~~of ~~pending~~gross ~~the~~proceeds ~~issuance~~paid ofto ~~final~~the ~~regulations,~~broker effecting the ~~IRS~~applicable ~~has~~transfer ~~suspended~~on behalf of the ~~application~~transferor, ofand ~~this~~thus ~~withholding~~will ~~rule~~be todetermined ~~transfers~~without ofregard ~~publicly~~to ~~traded~~any ~~interests~~decrease in ~~publicly~~that ~~traded~~partner’s ~~partnerships.~~share Ifof ~~recently~~a ~~promulgated~~publicly ~~regulations~~traded ~~are~~partnership’s ~~finalized~~liabilities. asThe ~~proposed,~~Treasury ~~such~~ regulations ~~would~~further provide, ~~with~~that ~~respect~~withholding toon ~~transfers~~a transfer of ~~publicly~~an ~~traded~~interest ~~interests~~ in a publicly traded ~~partnerships~~partnership ~~effected~~will ~~through~~not be imposed on a ~~broker,~~transfer that ~~the~~occurs ~~obligation~~prior to ~~withhold~~January is1, ~~imposed~~2022. onFor ~~the~~a ~~transferor’s~~transfer ~~broker~~of ~~and~~interests ~~that~~in a ~~partner’s~~publicly ~~“amount~~traded ~~realized”~~partnership ~~does~~that ~~not~~is ~~include~~effected through a ~~partner’s~~broker ~~share~~on ofor aafter ~~publicly~~January ~~traded~~1, ~~partnership’s~~2022, ~~liabilities~~the ~~for~~obligation ~~purposes~~to ofwithhold ~~determining~~is ~~the~~imposed ~~amount~~on ~~subject~~the totransferor’s ~~withholding~~broker. ~~However,~~Prospective itforeign isunitholders ~~not~~should ~~clear~~consult ~~when~~their ~~such~~tax ~~regulations~~advisors ~~will~~regarding bethe ~~finalized~~impact ~~and~~of ifthese ~~they~~rules ~~will~~on bean ~~finalized~~investment in ~~their~~our ~~current~~common ~~form~~units.

We treat a purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization conventions that may not conform to all aspects of specified Treasury Regulations. A successful challenge to those conventions by the IRS could adversely affect the amount of tax benefits available to unitholders or could affect the timing of tax benefits or the amount of taxable gain from the sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to unitholders’ tax returns.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the Allocation Date), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Final Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Final Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the General Partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets.

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Although we may, from time to time, consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction. Pursuant to the Bipartisan Budget Act of 2015, the IRS can isolate the resulting allocation adjustments that increase tax from those that decrease tax and assess tax at the partnership level, without netting the adjustments. Such a result would reduce the cash available for distribution by the partnership.

A successful IRS challenge to these methods, calculations or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount or character of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not live in any of those jurisdictions. We may be required to withhold income taxes with respect to income allocable or distributions made to our unitholders. In addition, unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements.

We currently own assets in multiple states, many of which currently impose a personal income tax on individuals. Generally, these states also impose income taxes on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is the unitholders' responsibility to file all required U.S. federal, state and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.

GENERAL RISKS RELATED TO THE PARTNERSHIP

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 as discussed in detail in this section, any of which could have a materially adverse impact on our business, financial condition and results of operation.

Our pipeline systems’ business systems could be negatively impacted by security threats, including cyber security threats, and related disruptions.

Cyber-attacks are becoming more sophisticated, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. In fact, PHMSA has posted warnings to all pipeline owners and operators of the importance of safeguarding and securing their pipeline facilities and monitoring their supervisory control and data acquisition (SCADA) systems for abnormal operations and/or indications of unauthorized access or interference with safe pipeline operations based on recent incidents involving environmental activists.

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We are exposed to credit risk when a customer fails to perform its contractual obligations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Please read Item 1. Business for a description of our principal physical properties and a map showing the locations of our pipeline systems. Our pipeline systems are constructed and operated on property owned by individuals, governmental authorities, Native American tribes and other third parties pursuant to leases, easements, rights-of-way, permits and licenses, the majority of which are perpetual. Our pipeline systems also own or lease land for compressor stations, meter stations and pipeline field offices. Certain land use rights, in particular rights-of-way on tribal land held in trust by the BIA, are subject to periodic renewal, periodic payments, encumbrances and/or restrictions. We believe that we generally have sufficient rights, title and interest in the properties needed to operate our pipeline systems and conduct our business and that such periodic renewals, rental payments, encumbrances and restrictions should not materially detract from the value of our pipeline systems or materially interfere with the operation of their business.

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licenses, the majority of which are perpetual. Our pipeline systems also own or lease land for compressor stations, meter stations and pipeline field offices. Certain land use rights, in particular rights-of-way on tribal land held in trust by the BIA, are subject to periodic renewal, periodic payments, encumbrances and/or restrictions. We believe that we generally have sufficient rights, title and interest in the properties needed to operate our pipeline systems and conduct our business and that such periodic renewals, rental payments, encumbrances and restrictions should not materially detract from the value of our pipeline systems or materially interfere with the operation of their business.

See Part I, Item 1A “Risk Factors-Risks Related to Our Pipeline Systems” for further information regarding risks related to property rights.

Item 3. Legal Proceedings

We may be involved in various legal proceedings from time to time that arise in the ordinary course of business. Information regarding our pipeline systems’ rate proceedings is described in Item 1. "Business – Government Regulation – Regulatory and Rate Proceedings" is incorporated herein by reference. Information on our legal proceedings can be found under Note 222 – Contingencies within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

Item 4. Mine Safety Disclosures

None.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

As of February 19, ~~2020~~2021, there were approximately 2726 holders of record of our common units. Our common units trade on the NYSE under the symbol “TCP.”

~~As of February 19, 2020, the Partnership had 71,306,396 common units outstanding, of which 54,221,565 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of~~ 46 TC ~~Energy~~ PipeLines, including 5,797,106 common units held by our General Partner. Additionally, TC Energy, through our General Partner, owns 100 percent of our IDRs and a two percent general partner interest in the Partnership. TC Energy also holds 100 percent of our 1,900,000 outstanding Class B units. There is no established public trading market for our IDRs and Class B units. LP Annual Report 2020

Further details regarding our distributions can be found under Note 15-Cash Distributions within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

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As of February 19, 2021, the Partnership had 71,306,396 common units outstanding, of which 54,221,565 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of TC Energy, including 5,797,106 common units held by our General Partner. Additionally, TC Energy, through our General Partner, owns 100 percent of our IDRs and a two percent general partner interest in the Partnership. TC Energy also holds 100 percent of our 1,900,000 outstanding Class B units. There is no established public trading market for our IDRs and Class B units.

Further details regarding our distributions can be found under Note 14-Cash Distributions within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

Item 6. Selected Financial Data

The selected financial data should be read in conjunction with the financial statements, including the notes thereto, and Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


(millions of dollars, except per common unit amounts)		2020						2019						2018			2017		2016		(a)
(millions of dollars, except per common unit amounts)	2019			2018			2017			2016(a)			2015(a)
Income Data (for the year ended December 31)
Income Data (for the year ended December 31)
Transmission revenues		399						403						549		(d)	422		426
Transmission revenues		403			549	(e)		422			426			417
Equity earnings(b)		170						160						173			124		97
Equity earnings(b)		160			173			124			97			97
Impairment of goodwill(c)		—						—						59			—		—
Impairment of equity‑method investment(c)		—			—			—			—			(199)
Impairment of long‑lived assets(d)		—						—						537			—		—
Impairment of goodwill(d)		—			59			—			—			—
Net income (loss)		301						297						(165)			263		263
Impairment of long‑lived assets(e)		—			537			—			—			—
Net income (loss) attributable to controlling interests		284						280						(182)			252		248
Net income (loss)		297			(165)			263			263			58
Basic and diluted net (loss) income per common unit		$	3.90					$	3.74					$	(2.68)		$	3.16	$	3.21	(e)
Net income (loss) attributable to controlling interests		280			(182)			252			248			37
Cash Flow Data (for the year ended December 31)
Basic and diluted net (loss) income per common unit	$	3.74		$	(2.68)		$	3.16		$	3.21	(f)	$	(0.03)	(f)
Cash distribution declared per common unit		$	2.60					$	2.60					$	2.60		$	3.94	$	3.71
Cash Flow Data (for the year ended December 31)
Balance Sheet Data (at December 31)
Cash distribution declared per common unit	$	2.60		$	2.60		$	3.94		$	3.71		$	3.51
Total assets		3,145						2,853						2,899			3,559		3,354
Balance Sheet Data (at December 31)
Long‑term debt, net		1,768						1,880						2,072			2,352		1,859
Total assets		2,853			2,899			3,559			3,354			3,459	(g)
Partners’ equity		833						760						699			1,068		1,272
Long‑term debt (including current maturities)		2,012			2,108			2,403			1,911			1,971	(g)
Partners’ equity		760			699			1,068			1,272			1,391

(a)Recast information to consolidate PNGTS as a result of an additional 11.81 percent in PNGTS that was acquired from a subsidiary of TC Energy on June 1, 2017. Prior to this transaction, the Partnership owned a 49.9 percent interest in PNGTS that was acquired from TC Energy on January 1, 2016. Please read Note 2 – Significant Accounting Policies – Basis of Presentation section of the Notes to the Consolidated Financial Statements included in Part IV Item 15. “Exhibits and Financial Statement Schedules”.

(ab)Equity ~~Recast~~earnings ~~information~~represent toour ~~consolidate~~share ~~PNGTS as a result of an additional 11.81 percent~~ in ~~PNGTS~~investee’s ~~that~~earnings ~~was~~and ~~acquired~~do ~~from~~not ainclude ~~subsidiary~~any ofimpairment TCcharge ~~Energy~~ on ~~June~~our 1,equity ~~2017~~investments. Prior to this transaction, the Partnership owned a 49.9 percent interest in PNGTS that was acquired from TC Energy on January 1, 2016. Please read Note 2 – Significant Accounting Policies – Basis of Presentation section of the Notes to the Consolidated Financial Statements included in Part IV Item 15. “Exhibits and Financial Statement Schedules”.

(bc)Please ~~Equity~~read ~~earnings~~Note ~~represent~~4 ~~our~~– ~~share~~Goodwill inand ~~investee’s~~Regulatory, ~~earnings~~Notes ~~and~~to dothe ~~not~~Consolidated ~~include~~Financial ~~any~~Statements ~~impairment~~included ~~charge~~in onPart ~~our~~IV ~~equity~~Item ~~investments~~15. “Exhibits and Financial Statement Schedules” for more information.

(cd)Please ~~Represents~~read ~~the~~Note ~~impairment~~7 ~~charge~~– onProperty, ~~our~~plant ~~investment~~and inEquipment, ~~Great~~Notes ~~Lakes.~~to ~~The~~the ~~equity~~Consolidated ~~earnings~~Financial asStatements ~~presented~~included in ~~2015~~Part ~~did~~IV, ~~not~~Item ~~include~~15. ~~this~~“Exhibits ~~impairment~~and ~~charge~~Financial Statement Schedules” for more information.

(de)Represents ~~Please~~basic ~~read~~and ~~Note~~diluted 4net –income ~~Goodwill~~per ~~and~~common ~~Regulatory,~~unit ~~Notes~~prior to ~~the Consolidated Financial Statements included in Part IV Item 15. “Exhibits and Financial Statement Schedules” for more information.~~recast

~~(e) Please read Note 7 – Property~~TC PipeLines, ~~plant and Equipment, Notes to the Consolidated Financial Statements included in Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more information.~~ LP Annual Report 2020 47

(f) Represents basic and diluted net income per common unit prior to recast.

(g) As a result of the application of Accounting Standards Update (ASU) No. 2015-03 “Interest-Imputation of Interest” and similar to the presentation of debt discounts, debt issuance costs previously reported as other assets in the balance sheet were reclassified as an offset against their respective debt liabilities.

42 TC PipeLines, LP Annual Report 2019

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management's Discussion and Analysis (MD&A) is intended to give our unitholders an opportunity to view the Partnership through the eyes of our management. ~~We have done so by providing management's current assessment of, and outlook of the business of the Partnership.~~ This MD&A should be read in conjunction together with Part I Item 1. “Business” and the accompanying December 31, ~~2019~~2020 audited financial statements and notes included in Part IV, Item 15. “Exhibits and Financial Statement Schedules.” Our discussion and analysis includes the following:

● •EXECUTIVE OVERVIEW;

● •HOW WE EVALUATE OUR OPERATIONS;

● •RESULTS OF OPERATIONS;

● •LIQUIDITY AND CAPITAL RESOURCES;

● •CRITICAL ACCOUNTING ESTIMATES;

● •CONTINGENCIES; and

● •RELATED PARTY TRANSACTIONS.

EXECUTIVE OVERVIEW

Financial Performance Highlights

Our ~~2019~~2020 highlights are summarized as follows:

● •Generated net income attributable to controlling interests of $~~280~~284 million or $3.7490 per common unit compared to ~~a net loss of~~ $~~182~~280 million or $23.6874 per common unit in ~~2018~~2019

● •Generated adjusted earnings of $~~280~~284 million or $3.7490 per common unit compared to $~~317~~280 million or $43.1874 per common unit in ~~2018~~2019

● •Generated ~~both~~ EBITDA and Adjusted EBITDA of $~~460~~479 million and $488 million in ~~2019~~2020, respectively compared to $27460 million and $~~526~~517 million in ~~2018~~2019, respectively

● •Declared and paid cash distributions totaling $2.60 per common unit, or $0.65 per quarter, for both ~~2019~~2020 and ~~2018~~2019

● •Generated Distributable Cash ~~flow~~Flow of $~~340~~255 million compared to $~~391~~340 million in ~~2018~~2019

●•S&P ~~Reduced~~and ~~debt~~Moody's ~~balance~~affirmed bythe ~~$106~~Partnership's ~~million~~credit ~~during~~rating ~~2019~~of BBB/Stable and Baa2/Stable, respectively

●Please ~~Received~~see ~~approval~~the ~~from~~“How ~~FERC~~We ~~for~~Evaluate ~~both~~Our ~~Iroquois~~Operations" ~~and~~section ~~Tuscarora~~for ~~rate~~more ~~settlements~~information on ~~May~~our 2non-GAAP financial measures: EBITDA, ~~2019~~Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit and Distributable Cash Flows.

●Planned ~~S&P~~Merger ~~upgraded~~with ~~credit~~TC ~~rating to BBB/Stable from BBB-/Stable~~Energy

~~Please~~On ~~see~~December ~~“How~~14, We2020, ~~Evaluate~~the ~~Our~~Partnership ~~Operations~~entered ~~Section”~~into ~~for~~the ~~more~~TC ~~information~~Energy onMerger ~~our~~Agreement ~~Non-GAAP~~pursuant ~~Financial~~to ~~Measures:~~which ~~EBITDA~~TC Energy will acquire all the outstanding common units of the Partnership not beneficially owned by TC Energy or its affiliates, ~~Adjusted~~in ~~earnings~~exchange ~~and~~for ~~Adjusted~~0.70 ~~earnings~~TC ~~per~~Energy common ~~unit~~share ~~and~~for ~~Distributable~~each ~~Cash~~outstanding ~~Flows~~Partnership common unit.

~~Outlook~~The transaction is expected to close late in the first quarter of ~~Our~~2021 ~~Business~~subject to the approval by the holders of a majority of outstanding common units of the Partnership and customary regulatory approvals. Upon closing, the Partnership will be an indirect, wholly-owned subsidiary of TC Energy and will cease to be a publicly traded master limited partnership.

~~With~~(Please ~~the~~see ~~return~~also to“Item a1. ~~stable regulatory environment in 2019 and our financial metrics solidly in line with a self~~Business-~~funding~~ ~~business~~Recent ~~model,~~Business weDevelopments” believe our pipeline systems, which are largely backed by long-term, ship-or-pay contracts, will deliver consistent financial performance going forward and support our current quarterly distribution level of $0.65 per common unit for ~~the~~more ~~foreseeable future~~information.)

We have transformed our business strategy and are focusing on taking advantage of North America’s abundant natural gas supply and our assets’ connectivity to premium markets to compete for organic growth within our existing footprint. Our largest assets, GTN, Northern Border and Great Lakes, continued to benefit from positive market conditions in 2019. Additionally, PNGTS’ PXP and Westbrook XPress projects continued to advance, with PXP Phase II and Westbrook XPress Phase I going into service on November 1, 2019. In 2019, we also announced the following new growth projects:

● GTN XPress project, the largest organic opportunity in our 20-year history, which will enhance system reliability through horsepower replacements and other reliability work and will provide up to 250,000 Dth/day of additional firm transportation services by late 2023; and

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● Tuscarora XPress project, an expansion project that will transport an additional 15,000 Dth/day of natural gas along Tuscarora’s system, increasing its capacity by seven percent.

Additionally, following successful binding open seasons, we announced the following projects which are in development and still subject to various conditions including corporate and regulatory approvals and final contracting or investment decisions:

● North Baja XPress project, an expansion project that will transport an additional 495,000 Dth/day of additional volumes of natural gas along North Baja’s mainline system with an estimated in-service date of November 2022; and

● Iroquois ExC Project which involves compressor enhancements at existing compressor stations along the Iroquois pipeline that will increase Iroquois’ capacity by approximately 125,000 Dth/day with an estimated in-service date of November 2023.

We continue to pursue new opportunities to capture the highest value from our pipelines and are actively seeking opportunities to further optimize our pipelines’ capacity through potential expansion projects or commercial, regulatory and operational changes in response to positive supply fundamentals. Finally, we continue to evaluate redeployment alternatives for our Bison pipeline following expiration of its remaining long-term contracts in January 2021, including the potential to reverse the pipeline to transport growing associated natural gas supplies from the Bakken area. The safe and reliable operation of our pipeline assets remains our top priority as we prudently fund ongoing capital expenditures, repay debt and manage our financial metrics.

(Please see also “Item 1. Business- Recent Business Developments” for more information on these projects and other matters that could potentially impact our results of operations in the future.)

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 each enhance the understanding of our operating performance. We use the following non-GAAP financial measures:

EBITDA

We use EBITDA as an approximate measure of our current operating profitability. It measures our earnings from our pipeline systems before certain expenses are deducted.

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 (see also discussion below). We provide Adjusted EBITDA as an additional performance measure of the current operating profitability of our assets.

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Adjusted EBITDA, Adjusted Earnings and Adjusted Earnings per common unit

The evaluation of our financial performance and position from the perspective of earnings, and EBITDA is inclusive of the following 2018 items which are one-time or non-cash in nature:

● •Bison’s contract termination proceeds amounting to $97 million recognized as revenue;

● •the $537 million impairment charge related to Bison’s remaining balance of property, plant and equipment; and

● •the $59 million impairment charge related to Tuscarora’s goodwill.

However, we do not believe this is reflective of our underlying operations during the periods presented. Therefore, we have presented Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit as non-GAAP financial measures that exclude the 2018 impacts of the $596 million non-cash impairment charges and the one-time $97 million revenue item relating to Bison’s contract terminations. We had no similar adjustments in the ~~2019~~2020 and ~~2017~~2019 periods.

Distributable Cash Flows

Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period. Our distributable cash flow includes Adjusted EBITDA and therefore excludes 2018’s $596 million non-cash impairment charges and the one-time $97 million revenue item from receipt of proceeds relating to Bison’s contract terminations.

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

44 TC PipeLines, LP Annual Report 2019

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RESULTS OF OPERATIONS

The ownership interests in our pipeline assets were our only material sources of income during the periods presented. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems.

Year Ended December 31, 2020 Compared with the Year Ended December 31, 2019


(unaudited)			$	%
(millions of dollars, except per common unit amounts)	2020	2019	Change(b)	Change(b)
Transmission revenues	399	403	(4)	(1)
Equity earnings	170	160	10	6


Operating, maintenance and administrative	(100)	(105)	5	5
Depreciation	(89)	(78)	(11)	(14)
Financial charges and other	(73)	(83)	10	12
Net income (loss) before taxes	307	297	10	3
Income taxes	(6)	1	(7)	*
Net income (loss)	301	298	3	1
Net income attributable to non‑controlling interests	17	18	(1)	(6)
Net income (loss) attributable to controlling interests	284	280	4	1
Adjusted earnings (a)	284	280	4	1

Net income (loss) per common unit	3.90	3.74	0.16	4
Adjusted earnings per common unit (a)	3.90	3.74	0.16	4

(a)Adjusted earnings and Adjusted earnings per common unit are non-GAAP financial measures for which reconciliations to the appropriate GAAP measures are provided below.

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

* Change is greater than 100 percent.

For the year ended December 31, 2020, the Partnership generated net income attributable to controlling interests and adjusted earnings of $284 million compared to $280 million for the same period in 2019, resulting in a net income per common unit during the year of $3.90 compared to $3.74 per common unit in 2019. This increase was primarily due to the net effect of:

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

TC PipeLines, LP Annual Report 2020 49

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experienced by a neighboring pipeline that were not repeated in 2020; and (iv) lower opportunity for the sale of discretionary services 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 in November 2019, and from PXP Phase III, which entered into service in November 2020 partially offset by lower discretionary services sold by PNGTS in 2020 compared to 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.

Equity Earnings - The $10 million increase was largely due to the following

•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 third quarter of 2020. As noted under "Recent Business Developments" within Item 1, 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 more consistent with historical results; and

•higher earnings from our equity investment in Great Lakes primarily due to lower operating costs associated with its compliance programs and a decrease in TC Energy's allocated personnel costs.

Operating, maintenance and administrative costs - The $5 million decrease was primarily due to the decrease in TC Energy's allocated costs related to personnel partially offset by higher operating costs related to our pipeline systems' compliance programs and costs incurred related to the planned TC Energy Merger.

Depreciation and amortization - The $11 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 $10 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.

Income Taxes - The $7 million increase was primarily due to an increase in PNGTS' deferred taxes due to a change in New Hampshire's Business Profits Tax rate effective in 2021 and an increase in PNGTS' current income taxes due to its higher net income before taxes.

Year Ended December 31, 2019 Compared with the Year Ended December 31, 2018


(unaudited)(millions of dollars, except per common unit amounts)		2019		2018		$Change(b)	%Change(b)
(unaudited)				$	%
Transmission revenues		403		549		(146)	(27)
(millions of dollars, except per common unit amounts)	2019		2018	Change(b)	Change(b)
Equity earnings		160		173		(13)	(8)
Transmission revenues	403		549	(146)	(27)
Impairment of long-lived assets		—		(537)		537	100
Equity earnings	160		173	(13)	(8)
Impairment of goodwill		—		(59)		59	100
Impairment of long-lived assets	—		(537)	537	100
Operating, maintenance and administrative		(105)		(101)		(4)	(4)
Impairment of goodwill	—		(59)	59	100
Depreciation		(78)		(97)		19	20
Operating, maintenance and administrative	(105)		(101)	(4)	(4)
Financial charges and other		(83)		(92)		9	10
Depreciation	(78)		(97)	19	20
Net income (loss) before taxes		297		(164)		461	*
Financial charges and other	(83)		(92)	9	10
Income taxes		1		(1)		2	*
Net income (loss) before taxes	297		(164)	461	*
Net income (loss)		298		(165)		463	*
Income taxes	1		(1)	2	*
Net income attributable to non‑controlling interests		18		17		1	6
Net income (loss)	298		(165)	463	*
Net income (loss) attributable to controlling interests		280		(182)		462	*
Net income attributable to non‑controlling interests	18		17	1	6
Adjusted earnings(a)		280		317		(37)	(12)
Net income (loss) attributable to controlling interests	280		(182)	462	*
Net income (loss) per common unit		3.74		(2.68)		6.42	*
Adjusted earnings (a)	280		317	(37)	(12)
Adjusted earnings per common unit(a)		3.74		4.18		(0.44)	(11)

Net income (loss) per common unit	3.74		(2.68)	6.42	*
Adjusted earnings per common unit (a)	3.74		4.18	(0.44)	(11)

50 TC PipeLines, LP Annual Report 2020

~~(a)~~Table ~~Adjusted~~of ~~earnings and Adjusted earnings per common unit are non-GAAP measures for which reconciliations to the appropriate GAAP measures are provided below.~~Contents

(ba)Adjusted ~~Positive~~earnings ~~number~~and ~~represents~~Adjusted aearnings ~~favorable~~per ~~change;~~common ~~bracketed~~unit orare ~~negative~~non-GAAP ~~number~~financial ~~represents~~measures anfor ~~unfavorable~~which ~~change~~reconciliations to the appropriate GAAP measures are provided below.

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

* Change is greater than 100 percent.

For the year ended December 31, 2019, the Partnership generated net income attributable to controlling interests of $280 million compared to a loss of $182 million for the same period in 2018, resulting in a net income per common unit during the year of $3.74 compared to a loss $2.68. The loss in 2018 was primarily due to the recognition of non-cash impairments relating to Bison’s property, plant and equipment and Tuscarora’s goodwill partially offset by the $97 million revenue proceeds from Bison’s contract terminations in the fourth quarter of 2018. See Part II, Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Impairment of Goodwill, Long-Lived Assets and Equity Investments" section for more details.

Adjusted earnings was lower by $37 million for the year ended December 31, 2019, a decrease of $0.44 per common unit. This decrease was primarily due to the net effect of:

Transmission revenues – Excluding the non-recurring $97 million revenue proceeds from Bison’s contract terminations in 2018 noted above, revenues for 2019 were lower by $49 million due largely to the decrease in revenue from Bison. As a result of early contract pay out, Bison was only approximately 40 percent contracted beginning in 2019 compared to 100 percent contracted in 2018, resulting in decreased revenue of approximately $48 million.

Revenue from GTN, North Baja, Tuscarora and PNGTS was largely comparable to prior year. The scheduled rate decreases on our pipelines as a result of the 2018 FERC Actions were primarily offset by increased discretionary revenue as a result of strong natural gas flows mainly out of WCSB and solid contracting across our Consolidated Subsidiaries. See also Part I, Item 1. “Business – Government Regulations – 2018 FERC Actions.”

Equity Earnings – The $13 million decrease was primarily due to the net effect of the following:

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

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

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increase in TC Energy's allocated management and corporate support functions expenses and common costs such as insurance.

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

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

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

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

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

Financial charges and other – The $9 million decrease in financial charges and other expenses was primarily attributable to the repayment of our $170 million Term Loan during the fourth quarter of 2018 and repayment of borrowings under our Senior Credit Facility during the first quarter of 2019.

Year Ended December 31, 2018 Compared with the Year Ended December 31, 2017


(unaudited)			$	%
(millions of dollars, except per common unit amounts)	2018	2017	Change(b)	Change(b)
Transmission revenues	549	422	127	30
Equity earnings	173	124	49	40
Impairment of long-lived assets	(537)	—	(537)	(100)
Impairment of goodwill	(59)	—	(59)	(100)
Operating, maintenance and administrative	(101)	(103)	2	2
Depreciation	(97)	(97)	—	—
Financial charges and other	(92)	(82)	(10)	(12)
Net income (loss) before taxes	(164)	264	(428)	*
Income taxes	(1)	(1)	—	—
Net income (loss)	(165)	263	(428)	*
Net income attributable to non‑controlling interests	17	11	6	55
Net income (loss) attributable to controlling interests	(182)	252	(434)	*
Adjusted earnings(a)	317	252	65	26
Net income (loss) per common unit	(2.68)	3.16	5.84	*
Adjusted earnings per common unit(a)	4.18	3.16	1.02	32

(c) Adjusted earnings and Adjusted earnings per common unit are non-GAAP measures for which reconciliations to the appropriate GAAP measures are provided below.

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

* Change is greater than 100 percent.

During 2018, the Partnership generated a net loss attributable to controlling interests of $182 million compared to net income of $252 million in 2017, resulting in a net loss per common unit during the year of $2.68 after allocations to the General Partner and to the Class B units. The resulting loss was primarily due to the recognition of non-cash impairments relating to Bison’s property, plant and equipment and Tuscarora’s goodwill partially offset by the $97 million revenue proceeds from Bison’s contract terminations. See Part II, Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Impairment of Goodwill, Long-Lived Assets and Equity Investments" section for more details.

Adjusted earnings increased by $65 million, an increase of $1.02 per common unit. This increase was primarily due to the net effect of:

Transmission revenues – Excluding the $97 million revenue proceeds from Bison’s contract terminations, our 2018 annual revenues were higher than those in 2017 by $30 million due to the following:

● Higher net revenue from GTN primarily due to incremental long-term services sold by GTN associated with increased available upstream capacity following debottlenecking activities on TC Energy’s pipelines partially offset by lower revenues from its short-term discretionary services compared to the same period in 2017. The increase was further offset by the $10 million provision for revenue sharing payment made by GTN as part of the 2018 GTN Settlement whereby GTN agreed to refund $10 million to its maximum rate customers from January 1 to October 31, 2018;

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● Higher revenue from PNGTS primarily due to incremental contracting from PNGTS’ C2C Contracts and the PXP Phase I contracts combined with an increase in discretionary services due to inclement weather in the northeast U.S. during the first quarter of 2018, partially offset by certain expiring winter contracts; and

● Increase in short-term firm transportation services sold by North Baja.

Equity earnings – The $49 million increase in 2018 compared to 2017 was primarily due to the inclusion of equity earnings from Iroquois for the full twelve months of 2018 compared to only seven months in 2017 (our 49.34 percent ownership was effective June 1, 2017), as well as the increase in Iroquois’ short-term discretionary services sold during the 2018 period as a result of the colder winter weather in the northeast U.S. Additionally, equity earnings from Great Lakes increased as a result of higher short-term incremental sales during the year and the elimination of Great Lakes’ revenue sharing mechanism that began in 2018 as part of 2017 Great Lakes Settlement.

Financial charges and other – The $10 million increase was mainly attributable to additional borrowings to finance the Partnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017 (the 2017 Acquisition) combined with an increase in interest charges on our variable rate debt.

Net income (loss)attributable to non-controlling interests – The Partnership had a net increase amounting to $6 million primarily due to the increase in revenue earned by PNGTS.

Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per common unit

Reconciliation of Net income (loss) attributable to controlling interests to Adjusted earnings


Reconciliation of Net income (loss) attributable to controlling interests to Adjusted earnings
(millions of dollars)
Year ended December 31	2020	2019	2018
Net income attributable to controlling interests	284	280	(182)
Add: Impairment of goodwill	—	—	59
Add: Impairment of long-lived assets	—	—	537
Less: Revenue proceeds from Bison’s contract terminations	—	—	(97)
Adjusted earnings	284	280	317


(millions of dollars)
Year ended December 31	2019	2018	2017
Net income attributable to controlling interests	280	(182)	252
Add: Impairment of goodwill	—	59	—
Add: Impairment of long-lived assets	—	537	—
Less: Revenue proceeds from Bison’s contract terminations	—	(97)	—
Adjusted earnings	280	317	252

TC PipeLines, LP Annual Report 2020 51

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Reconciliation of Net income (loss) per common unit to Adjusted earnings per common unit


Reconciliation of Net income (loss) per common unit to Adjusted earnings per common unit
Year ended December 31	2020	2019	2018
Net income (loss) per common unit ‑ basic and diluted(a)	3.90	3.74	(2.68)
Add: per unit impact of impairment of goodwill	—	—	0.81	(b)
Add: per unit impact of impairment of long-lived assets	—	—	7.38	(c)
Less: per unit impact of revenue proceeds from Bison’s contract terminations	—	—	(1.33)	(d)
Adjusted earnings per common unit	3.90	3.74	4.18


Year ended December 31	2019	2018		2017
Net income (loss) per common unit‑basic and diluted(a)	3.74	(2.68)		3.16
Add: per unit impact of impairment of goodwill	—	0.81	(b)	—
Add: per unit impact of impairment of long-lived assets	—	7.38	(c)	—
Less: per unit impact of revenue proceeds from Bison’s contract terminations	—	(1.33)	(d)	—
Adjusted earnings per common unit	3.74	4.18		3.16

(a)See also Note 14 of the Partnership’s consolidated financial statements included in Part IV. Item 15. "Exhibits and Financial Statement Schedules” for details of the calculation of net income (loss) per common unit.

(b)Computed by dividing the $59 million impairment charge, after deduction of amounts attributable to the General Partner with respect to its two percent interest, by the weighted average number of common units outstanding during the period.

(ac)Computed ~~See~~by ~~also~~dividing ~~Note~~the 14$537 million ofimpairment ~~the~~charge, ~~Partnership’s~~after ~~consolidated~~deduction ~~financial~~of ~~statements~~amounts ~~included~~attributable into ~~Part~~the ~~IV.~~General ~~Item~~Partner ~~15.~~with ~~"Exhibits~~respect ~~and~~to ~~Financial~~its ~~Statement~~two percent ~~Schedules”~~interest, ~~for~~by ~~details~~the ofweighted ~~the~~average ~~calculation~~number of ~~net~~common ~~income~~units ~~(loss)~~outstanding ~~per~~during ~~common unit~~the period.

(bd) Computed by dividing the $59 97 million ~~impairment charge~~revenue, after deduction of amounts attributable to the General Partner with respect to its two percent interest, by the weighted average number of common units outstanding during the period.

(c) Computed by dividing the $537 million impairment charge, after deduction of amounts attributable to the General Partner with respect to its two percent interest, by the weighted average number of common units outstanding during the period.

(d) Computed by dividing the $97 million revenue, after deduction of amounts attributable to the General Partner with respect to its two percent interest, by the weighted average number of common units outstanding during the period.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

AtOverall ~~December~~Current ~~31,~~Financial 2019, the balance of our cash and cash equivalents was higher than our position at December 31, 2018 by approximately $50 million and our overall debt balance was lower by $106 million. We continue to use available cash to fund ongoing capital expenditures and repay debt to levels that prudently manage our financial metrics.Condition

~~TC PipeLines, LP Annual Report 2019 47~~Cash and Debt position - Our overall long-term debt balance increased by approximately $188 million primarily as result of the financing put in place during the period for our expansion projects. The increase included an excess $20 million of liquidity from utilization of PNGTS's revolving credit facility during the fourth quarter to fund forecasted capital spending on Westbrook XPress.

The $20 million excess liquidity as noted above, 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 cash flows resulted in an increase in the balance of our cash and cash equivalents to $200 million at December 31, 2020 compared to our position at December 31, 2019 of approximately $83 million.

Working capital position - At December 31, 2020, our current assets totaled $257 million and current liabilities amounted to $487 million, leaving us with a working capital deficit of $230 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 February 24, 2021 and (4) if needed, 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.

52 TC PipeLines, LP Annual Report 2020

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WeOur ~~believe~~pipeline ~~our~~systems’ ~~cash~~principal ~~position,~~sources ~~remaining~~of ~~borrowing~~liquidity ~~capacity~~are oncash ~~our~~generated ~~Senior~~from ~~Credit~~operating ~~Facility~~activities, ~~(see~~long-term ~~table~~debt ~~below)~~offerings, bank credit facilities and ~~our~~equity ~~operating~~contributions ~~cash~~from ~~flows~~owners. ~~are~~Except ~~sufficient~~as noted below, our pipeline systems expect to fund ~~our~~their ~~short-term~~respective ~~liquidity~~expansion ~~requirements,~~projects ~~including~~primarily ~~distributions~~with todebt. Except as noted below, our ~~unitholders~~pipeline systems' normal recurring operating expenses, ~~ongoing~~maintenance capital expenditures, debt service and ~~required~~cash ~~debt~~distributions are ~~repayments~~primarily funded with their operating cash flows.

~~The~~•Since ~~following~~the ~~table~~fourth ~~sets~~quarter ~~forth~~of ~~the~~2010, ~~available~~however, ~~borrowing~~Great ~~capacity~~Lakes ~~under~~has ~~the~~funded ~~Partnership’s~~its ~~Senior~~debt ~~Credit~~repayments ~~Facility:~~with cash calls to its owners and we have contributed approximately $10 million each for 2020 and 2019 and $9 million for 2018.


(millions of dollars)
December 31	2019	2018	2017
Total capacity under the Senior Credit Facility	500	500	500
Less: Outstanding borrowings under the Senior Credit Facility	—	40	185
Available capacity under the Senior Credit Facility	500	460	315

•In December 2020 and August 2019, the Partnership made an equity contribution to Iroquois of approximately $2 million and $4 million, respectively. This amount represented the Partnership’s 49.34 percent share of a cash call from Iroquois to cover costs of regulatory approvals related to their ExC Project.

•From time to time, Northern Border requests equity contributions from or makes returns of capital distributions to its partners to manage its preferred capitalization levels. In June 2019, we received a return of capital distribution from Northern Border amounting to $50 million and used those proceeds to partially repay our 2013 Term Loan Facility due in 2021.

~~Our~~•Bison’s ~~pipeline~~remaining ~~systems’~~contracts ~~principal~~continued ~~sources~~in effect until January of ~~liquidity~~2021. ~~are~~In ~~cash~~2019 and 2020, Bison generated ~~from~~revenues ~~operating~~of ~~activities,~~$32 ~~long-term~~million ~~debt~~and ~~offerings~~$31 million, ~~bank~~respectively. ~~credit~~We ~~facilities~~continue to explore alternative transportation-related options for Bison and ~~equity~~we ~~contributions~~believe ~~from~~commercial ~~their~~potential ~~owners.~~exists ~~Except~~to asallow ~~noted~~for ~~below,~~the ~~our~~flow ~~pipeline~~of ~~systems~~natural ~~have~~gas ~~historically~~on ~~funded~~Bison ~~operating~~in ~~expenses~~both directions, ~~debt~~with ~~service~~the southwest direction involving deliveries onto third party pipelines and ~~cash~~ultimately ~~distributions~~connecting into the Cheyenne hub. In any event, Bison will continue to ~~their~~incur ~~owners~~costs ~~primarily~~related ~~with~~to property tax and operating ~~cash~~and ~~flow~~maintenance costs of approximately $6 million per year.

●Maintenance ~~Since~~and ~~the~~expansion ~~fourth~~capital ~~quarter~~expenditures ofare ~~2010,~~funded ~~however,~~by ~~Great~~a ~~Lakes~~variety ~~has~~of ~~funded~~sources, ~~its~~as ~~debt~~noted ~~repayments~~above. ~~with~~The ~~cash~~ability ~~calls~~of toour ~~its~~pipeline ~~owners~~systems ~~and~~to weaccess ~~have~~the ~~contributed~~debt ~~approximately~~capital ~~$10~~markets ~~million~~under inreasonable ~~2019~~terms ~~and~~depends $9upon ~~million~~their ~~each~~financial ~~for~~condition ~~2018~~ and ~~2017~~prevailing market conditions.

●The ~~In August 2019, the~~ Partnership’s ~~made~~pipeline ansystems ~~equity~~monitor ~~contribution~~the tocreditworthiness ~~Iroquois~~ of ~~approximately~~their $4customers ~~million.~~and ~~This~~have ~~amount~~credit ~~represented~~provisions ~~the~~included ~~Partnership’s~~in ~~49.34~~their ~~percent~~tariffs ~~share~~which, ofalthough agoverned $7by ~~million~~FERC, ~~capital~~allow ~~call~~them ~~from~~to ~~Iroquois~~request toa ~~cover~~certain ~~costs~~amount of ~~regulatory~~credit ~~approvals~~support ~~related~~as tocircumstances ~~their ExC Project~~dictate.

● From time to time, Northern Border requests equity contributions from or makes returns of capital distributions to its partners to manage its preferred capitalization levels. In June 2019, we received a return of capital distribution from Northern Border amounting to $50 million and used those proceeds to partially repay our 2013 Term Loan Facility due in 2021. In 2017, we made an equity contribution to Northern Border amounting to $83 million, which was used by Northern Border to reduce the outstanding balance on its revolver. The $50 million and $83 million amounts represent our 50 percent share of Northern Border’s distribution and contribution, respectively.

● Bison’s remaining contracts will continue 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 reverse the direction of natural gas flow on Bison for deliveries onto third party pipelines and ultimately connect into the Cheyenne hub. Notwithstanding the results of these commercial activities, Bison will continue to incur costs related to property tax and operating and maintenance costs of approximately $6 million per year.

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 on their financial condition and general market conditions.

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

Summarized Cash Flow


Year Ended December 31,(millions of dollars)		2020		2019	2018
Year Ended December 31,
Net cash provided by (used in):
(millions of dollars)	2019		2018	2017
Operating activities		413		412	540
Net cash provided by (used in):
Investing activities		(262)		(32)	(35)
Operating activities	412		540	376
Financing activities		(34)		(330)	(505)
Investing activities	(32)		(35)	(761)
Net increase in cash and cash equivalents		117		50	—
Financing activities	(330)		(505)	354
Cash and cash equivalents at beginning of the period		83		33	33
Net increase in cash and cash equivalents	50		—	(31)
Cash and cash equivalents at end of the period		200		83	33
Cash and cash equivalents at beginning of the period	33		33	64
Cash and cash equivalents at end of the period	83		33	33

Cash Flow Analysis for the Year Ended December 31, 2020 compared to Same Period in 2019

~~48 TC PipeLines, LP Annual Report 2019~~Operating Cash Flows

The Partnership's operating cashflows for the twelve months ended December 31, 2020 compared to the same period in 2019 were comparable primarily due to the net effect of the positive impact of certain working capital items offset by a slight decrease in distributions received from operating activities of equity investments. The slight decrease in distributions from operating activities of equity investments was due to the net impact of the following:

•no distributions from Great Lakes during the third quarter as it used the cash it generated during that period to fund a one-time commercial IT system purchase from a TC Energy affiliate on August 1, 2020; and

•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 year's earnings.

Investing Cash Flows

During the twelve months ended December 31, 2020, the Partnership’s cash used in our investing activities increase by $230 million compared to the same period in 2019 primarily due to the net impact of the following:

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

TC PipeLines, LP Annual Report 2020 53

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•$29 million return of capital distribution received from Iroquois, compared to only $8 million in 2019, primarily due to the $24 million extra distribution we received in 2020 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 $186 million in the twelve months ended December 31, 2020 compared to a net debt repayment of $106 million for the same period in the prior year, largely due to financing executed for the capital expenditures on our GTN XPress, PXP and Westbrook XPress expansion projects.

Cash Flow Analysis for the Year Ended December 31, 2019 compared to Same Period in 2018

Operating Cash Flows

In the twelve months ended December 31, 2019, the Partnership's net cash provided by operating activities decreased by $128 million compared to the same period in 2018 primarily due to the net effect of:

● •lower net cash flow from operations of our Consolidated Subsidiaries due to lower revenue from Bison as a result of the contract terminations in 2018 (60 percent of Bison contracts bought out in 2018) and an overall increase in our operating expenses as discussed in more detail in “Results of Operations” above; and

● •increase in distributions received from operating activities of equity investments primarily as a result of:

● ◦lower maintenance capital spending during 2019 on Northern Border; and

● ◦an increase in distributions from Iroquois related to an increase in its cash generated from strong discretionary revenues in prior years.

Investing Cash Flows

During the twelve months ended December 31, 2019, the Partnership’s cash used in our investing activities decreased by $3 million compared to the same period in 2018 primarily due to the net impact of the following:

● •higher maintenance capital expenditures on GTN for major compressor equipment overhauls and pipe integrity projects, initial spending on our GTN XPress ~~project~~Project and continued capital spending on our PXP and Westbrook XPress projects and other growth projects;

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

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

Financing Cash Flows

The Partnership's net cash used for financing activities was $175 million lower in the twelve months ended December 31, 2019 compared to the same period in 2018 primarily due to the net effect of:

● •$191 million decrease in net debt repayments;

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

● •$8 million increase in distributions paid to non-controlling interests during 2019 as a result of increased income generated by PNGTS;

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

● •$40 million decrease in cash from equity issuances in 2019 as the At-the-market Equity Issuance program (ATM program) was suspended during the first quarter of 2018.

Cash Flow Analysis for the Year Ended December 31, 2018 compared to Same Period in 2017

Operating Cash Flows

Net cash provided by operating activities increased by $164 million in the twelve months ended December 31, 2018 compared to the same period in 2017 primarily due to the net effect of:

● higher cash flow from operations at Bison due to the $97 million cash proceeds received from the contract terminations agreement reached with two of its customers as described in the “Results of Operations” and “Critical Accounting Estimates - Impairment of Goodwill, Long-Lived Assets and Equity Investments” sections;

● addition of distributions from Iroquois for the twelve months in 2018 as compared to the period from June 1, 2017 to the end of December in 2017;

● higher distributions received from Great Lakes primarily due to an increase in its revenue as a result of its higher short-term incremental sales during the year and the elimination of Great Lakes’ revenue sharing mechanism that began in 2018 as part of Great Lakes rate settlement in 2017;

● higher cash flow from operations at PNGTS and North Baja primarily resulting from an increase in their revenues; PNGTS’ revenue was higher due to its incremental contracting partially offset by certain expiring

TC PipeLines, LP Annual Report 2019 49

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winter contracts while North Baja’s revenue was higher due to an increase in its short-term firm transportation services; and

● higher interest paid attributable to additional borrowings to finance the 2017 Acquisition.

Investing Cash Flows

Net cash used in investing activities decreased by $726 million in the twelve months ended December 31, 2018 compared to the same period in 2017 due to the net effect of:

● $646 million total cash payments to TC Energy during 2017 for the 2017 Acquisition;

● $83 million equity contribution to Northern Border in 2017 representing our 50 percent share of a requested capital contribution to reduce the outstanding balance of Northern Border’s revolving credit facility;

● $10 million unrestricted cash distribution received from Iroquois during 2018, which was $5 million higher than the amount received in 2017;

● $11 million increase in capital expenditures in 2018 related to ongoing maintenance projects; the increase in 2018 reflected timing of payments as the scope of the maintenance work was relatively comparable in 2018 and 2017; and

● $3 million increase in customer advances for construction related to an interconnect project on GTN.

Financing Cash Flows

During the twelve months ended December 31, 2018, we realized a net cash out-flow in our financing activities compared to a net inflow in 2017 primarily due to $297 million in net debt repayments in 2018 compared to $492 million in net debt issuance in 2017. In 2018, we repaid the entire balance of our $170 million 2015 Term Loan while in 2017, we issued $500 million 3.90% Senior Notes on May 25, 2017 to partially finance the 2017 Acquisition.

In addition to these activities, the change in our financing activities year-over-year was impacted by the net effect of the following:

● $66 million decrease in distributions paid on our common units and to our General Partner in respect of its two percent general partner interest and IDRs as a result of the 35 percent reduction in distributions declared from the fourth quarter 2017 distribution of $1.00 per common unit to $0.65 per common unit that began in the first quarter of 2018;

● $7 million decrease in distributions paid to Class B units in 2018 as compared to 2017 due to the Class B Reduction;

● $136 million decrease in our ATM equity issuances in 2018 as compared to 2017; and

● $9 million increase in distributions paid to non-controlling interests due to higher revenues at PNGTS compared to 2017.

Capital spending

The Partnership’s share in capital spending for maintenance of existing facilities and growth projects was as follows:


Year Ended December 31
(millions of dollars)
(unaudited)	2019	2018	2017
Maintenance	76	60	63
Growth	26	7	3
Total(a)	102	67	66

54 TC PipeLines, LP Annual Report 2020

(a) Total maintenance and growth capital expenditures as reflected in this table include AFUDC and amounts attributable to the Partnership’s proportionate share of maintenance and growth capital expenditures of the Partnership’s equity investments, which are not reflected in our total capital expenditures as presented in our consolidated statement of cash flows. Additionally, our proportionate share includes accrued capital expenditures during the period.

Year Ended December 31, 2019 Compared with the Year Ended December 31, 2018

50 TC PipeLines, LP Annual Report 2019

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Additionally, in 2018, PNGTS incurred costs on upgrading one of its existing meter communication systems to meet current commercial pressure obligations. No such project occurred in 2019.


Year Ended December 31
(millions of dollars)
(unaudited)	2020	2019	2018
Maintenance	156	76	60
Growth	165	26	7
Total(a)	321	102	67

(a)Total maintenance and growth capital expenditures as reflected in this table include AFUDC and amounts attributable to the Partnership’s proportionate share of maintenance and growth capital expenditures of the Partnership’s equity investments, which are not reflected in our total capital expenditures as presented in our consolidated statement of cash flows. Additionally, our proportionate share includes accrued capital expenditures during the period.

Year Ended December 31, 2020 Compared with the Year Ended December 31, 2019

Maintenance capital spending increased by $80 million in 2020 compared to 2019 mainly due to increased normal-course maintenance spending at GTN along with the one-time purchase of a commercial IT system by several of our pipelines. The increased maintenance capex at GTN on its compressor fleet resulted from higher throughput, operating hours and strong demand for natural gas transportation. Additionally, there were also higher normal course compressor overhaul spending on Northern Border. The commercial IT system purchase will reduce future operating costs and overall, these maintenance capital expenditures will increase our pipelines’ respective rate bases and we anticipate will generate a return on and of capital in future rates.

Capital expenditures on growth projects increased by $140 million between 2020 and 2019 due to our continued spending on PXP and initial costs incurred on our GTN XPress, Iroquois’ ExC and Westbrook XPress projects.

Year Ended December 31, 2019 Compared with the Year Ended December 31, 2018

Maintenance capital spending increased by $16 million in 2019 compared to 2018 mainly due to increases in major equipment overhauls and pipe integrity projects on GTN, as a result of higher transportation volumes of natural gas during the year. The higher maintenance projects costs were offset by lower compressor overhaul spending on Northern Border. Additionally, in 2018, PNGTS incurred costs on upgrading one of its existing meter communication systems to meet current commercial pressure obligations. No such project occurred in 2019.

Capital expenditures on growth projects increased by $19 million between 2018 and 2019 due to our continued spending on PXP and initial costs incurred on our GTN XPress, Iroquois’ ExC and Westbrook XPress projects.

Year Ended December 31, 2018 Compared with the Year Ended December 31, 2017

Maintenance capital spending decreased by $3 million in 2018 compared to 2017 mainly due to decreases in pipeline integrity and communication equipment projects on GTN during 2017 in addition to a decrease in expenditures for remediation and automation projects on Northern Border in 2018 compared to 2017, partially offset by an increase in integrity and reliability projects on GTN.

Capital expenditures on growth projects increased by $4 million between 2017 and 2018 due to the PXP capital spending on PNGTS and an interconnect project on Northern Border.

Cash Flow Outlook

Operating Cash Flow Outlook

During the first quarter of ~~2020~~2021, the Partnership received or expects to receive the following distributions from our equity investments:

Northern Border declared its December ~~2019~~2020 distribution of $1816 million on January 1015, ~~2020~~2021, of which the Partnership received its 50 percent share or $98 million on January 3129, ~~2020~~2021.

Northern Border declared its January ~~2020~~2021 distribution of $1918 million on February 1116, ~~2020~~2021, of which the Partnership will receive its 50 percent share or $9 million on February 2826, ~~2020~~2021.

Great Lakes declared its fourth quarter ~~2019~~2020 distribution of $3423 million on January 1013, ~~2020~~2021, of which the Partnership received its 46.45 percent share or $1611 million on January 3129, ~~2020~~2021.

Iroquois declared its fourth quarter ~~2019~~2020 distribution of $2722 million inon February ~~2020~~18, 2021, of which the Partnership will receive its 49.34 percent share or $1411 million on March 3024, ~~2020~~2021.

Investing Cash Flow Outlook

The Partnership expects to make a $1014 million contribution in ~~2020~~2021 to Great Lakes to fund debt repayments which is consistent with prior years. The Partnership expects to make a $4 million contribution in 2021 to Iroquois to fund growth projects.

InThe ~~2020,~~Partnership ~~our~~expects ~~pipeline systems expect~~ to ~~invest~~make ~~approximately~~a $~~152~~4 million contribution in ~~maintenance~~2021 ~~capital~~to ~~for existing facilities~~Iroquois, ofrepresenting ~~which~~our ~~the~~49.34 ~~Partnership’s~~percent share ~~will~~of bea ~~$113~~cash ~~million.~~call ~~The~~from ~~Partnership’s~~Iroquois ~~estimated capital maintenance costs do not include any costs related~~ to ~~our~~cover ~~GTN XPress project (see further discussion below). Maintenance~~ capital ~~expenditures~~costs ~~are~~required ~~added to our pipelines’ respective rate bases and are expected to earn a return~~ on ~~and~~their ofExc ~~capital over time through the regulatory rate-making process~~Project.

~~Our~~In 2021, our pipeline systems ~~also~~ expect to invest approximately $~~242~~145 million in ~~growth~~maintenance ~~projects~~capital infor ~~2020~~existing facilities, of which the Partnership’s share will be $~~187~~109 million. ~~Growth~~The ~~capital~~Partnership’s ~~expenditures~~estimated ~~include~~capital ~~$102~~maintenance ~~million~~costs ofdo ~~Phase~~not Iinclude ~~GTN~~any ~~XPress project~~ costs ~~which~~related ~~are reliability and horsepower replacement expenditures expected~~ to beour ~~fully recoverable in~~ GTN’s ~~recourse~~XPress ~~rates~~Project ~~commencing~~(see infurther ~~2022,~~discussion ~~along with other ongoing growth projects as discussed in Part 1, Item 1~~below). ~~“Business~~Maintenance -capital ~~Recent~~expenditures ~~Business~~are ~~Developments.”~~added ~~GTN XPress is essentially a modernization program designed~~ to ~~replace~~our ~~and~~pipelines’ ~~upgrade~~respective ~~aging~~rate ~~compressor~~bases ~~infrastructure, increase reliability~~ and ~~integrate~~are ~~cutting-edge~~expected ~~technology~~to atearn ~~sites~~a ~~along~~return ~~its~~on ~~route. This~~and ~~will help GTN reduce greenhouse gas emissions while ensuring the integrity~~ of ~~existing~~capital ~~assets. The~~over ~~project~~time ~~will~~through ~~modernize~~ the ~~existing~~regulatory ~~system~~rate-making ~~and also grow capacity and, as such, is a hybrid project which is more like growth capital than maintenance capital~~process.

TC PipeLines, LP Annual Report 2020 55

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Our pipeline systems also expect to invest approximately $306 million in growth projects in 2021, of which the Partnership’s share will be $265 million. 2021 growth capital expenditures will include an estimated $145 million of Phase I GTN XPress Project costs, which are reliability and horsepower replacement expenditures expected to be fully recoverable in GTN’s recourse rates commencing in 2022, along with other ongoing growth projects as discussed in Part 1, Item 1. “Business - Recent Business Developments.” As of December 31, 2020 and 2019, we have incurred approximately $83 million and $5 million, respectively of Phase 1 GTN XPress Project costs, which were included in the tabular summary above.

GTN XPress is essentially a modernization program designed to replace and upgrade aging compressor infrastructure, increase reliability and integrate cutting-edge technology at sites along its route. This will help GTN reduce greenhouse gas emissions while ensuring the integrity of existing assets. The project will modernize the existing system and also grow capacity and, as such, is a hybrid project which is more like growth capital than maintenance capital.

Our maintenance and growth projects are funded from a combination of cash from operations and debt at both the asset and Partnership levels.

Our consolidated entities have commitments of $2186 million as of December 31, ~~2019~~2020 in connection with various maintenance and general plant projects. over the next two years.

Please read Part 1, Item 1. “Business ~~- Recent Business Developments~~” for more details regarding these projects.

Financing Cash Flow Outlook

On January 2119, ~~2020~~2021, the board of directors of our General Partner declared the Partnership’s fourth quarter ~~2019~~2020 cash distribution in the amount of $0.65 per common unit which was paid on February 1412, ~~2020~~2021 to unitholders of record as of January 3129, ~~2020~~2021. The total amount of cash distribution paid to common unitholders and General Partner was $47 million.

On January 2119, ~~2020~~2021, ~~the~~after ~~board~~reviewing ofGTN's ~~directors~~2020 ofdistributable ~~our~~cashflows, ~~General~~the ~~Partner~~TC ~~declared~~PipeLines Board did not declare distributions to Class B unitholders inas ~~the~~certain ~~amount~~thresholds offor $8a ~~million~~distribution ~~which~~to ~~was~~be ~~paid~~made onwere ~~February~~not ~~14, 2020~~exceeded. The Class B distribution represents an amount equal to 30 percent of GTN’s distributable cash flow during the year ended December 31, 2020 less the threshold level of $20 million and other adjustments that would further reduce the amount attributed to Class B unitholders. Beginning in 2021, we expect the impact of the Class B distribution on our cashflows to be significantly lower compared to previous periods.

~~TC PipeLines, LP Annual Report 2019 51~~Debt refinancing:

~~Table~~•The Partnership's $350 million aggregate principal amount 4.65 percent Unsecured Senior Notes mature on June 15, 2021. On February 12, 2021, the Partnership exercised its option to redeem the Unsecured Senior Notes on March 15, 2021 at a redemption price equal to 100% of ~~Contents~~the principal amount of the notes then outstanding, plus unpaid interest accrued to March 15, 2021. Partial funding for the redemption is expected to be provided using cash on hand, and borrowings under the Partnership’s $500 million Senior Credit Facility.

~~percent~~•The ~~of GTN~~Partnership’s ~~distributable~~$500 ~~cash~~million ~~flow~~Senior ~~during~~Credit ~~the~~Facility ~~year~~is ~~ended~~due ~~December~~in ~~31,~~November ~~2019~~2021 ~~less the threshold level of $20 million~~ and ~~the~~we ~~Class~~expect Bany ~~Reduction.~~outstanding ~~For~~balance ~~2020~~will ~~and~~be ~~beyond,~~repaid weif ~~expect~~ the ~~impact~~TC ofEnergy ~~Class~~Merger Bcloses, ~~distribution~~or onrefinanced ~~our~~or ~~cashflows~~extended prior to bematurity ~~significantly~~if ~~lower~~the ~~compared~~TC toEnergy ~~the~~Merger ~~previous~~does ~~periods.~~not close.

We•It ~~currently~~is ~~intend~~expected tothat ~~refinance~~Tuscarora ~~GTN’s~~will ~~$100~~refinance ~~million~~its ~~5.29%~~maturing ~~Unsecured~~unsecured ~~Senior~~term ~~Notes~~loan ~~due~~through ~~June~~an 1,extension ~~2020,~~of ~~and~~the ~~Tuscarora's~~existing ~~$23~~facility ~~million~~including ~~variable~~the ~~rate~~potential ~~Unsecured~~to ~~Term~~increase ~~Loan~~the ~~due~~size ~~August~~of ~~21,~~the ~~2020~~facility into ~~full~~include orthe atfinancing anrequired ~~amount~~for ~~based~~Tuscarora ~~on our preferred capitalization levels~~XPress.

~~Please~~•It ~~read~~is ~~Notes~~expected 8,that ~~11,~~North 14Baja ~~and~~will ~~15,~~refinance ~~Notes~~its maturing term loan facility through an extension of the existing facility including the potential to ~~Consolidated~~increase ~~Financial~~the ~~Statements~~size ~~included~~of inthe ~~Part~~facility ~~IV,~~to ~~Item~~include ~~15.~~the ~~“Exhibits~~financing ~~and~~required ~~Financial~~for ~~Statement~~North ~~Schedules~~Baja XPress Project.”

~~The~~Please ~~majority~~read ofNotes ~~our~~8, ~~growth~~10, ~~projects~~13 asand ~~discussed~~14, inNotes ~~the~~to ~~Investing~~Consolidated ~~Cashflow~~Financial ~~Outlook~~Statements ~~section~~included ~~above~~in isPart ~~being~~IV, ~~financed~~Item ~~through~~15. ~~debt~~“Exhibits and Financial Statement Schedules.”

AsThe majority of the ~~February~~capital ~~20,~~for ~~2020,~~our growth projects as discussed in the ~~available~~"Investing ~~borrowing~~Cash ~~capacity~~Flow onOutlook" ~~our~~section ~~Senior~~above ~~Credit~~is ~~Facility~~expected ~~was~~to ~~$500~~be ~~million~~financed through debt.

As of February 24, 2021, the available borrowing capacity on our Senior Credit Facility was $500 million.

Non-GAAP Financial Measures: EBITDA, Adjusted EBITDA, Distributable Cash Flow, Adjusted Earnings and Adjusted Earnings per Common Unit

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

~~Our~~ Adjusted EBITDA ~~excludes~~is ~~the~~our ~~2018~~EBITDA, ~~impact~~less (1) earnings from our equity investments, plus (2) distributions from our equity investment, and plus or minus (3) certain non-recurring items (as noted further below) that are significant but not reflective of ~~the~~our ~~following:~~underlying operations.

●Our ~~Bison’s~~Adjusted ~~contract~~EBITDA ~~termination~~excludes ~~proceeds~~the ~~amounting~~2018 toimpact ~~$97~~of ~~million recognized as revenue during~~ the ~~fourth~~following ~~quarter~~non-recurring ~~of 2018;~~items:

~~● the $537 million net long-lived asset impairment charge to Bison’s current carrying value; and~~56 TC PipeLines, LP Annual Report 2020

●Table ~~the~~of ~~$59 million impairment charge related to Tuscarora’s goodwill.~~Contents

We•Bison’s ~~believe~~contract ~~these~~termination ~~items~~proceeds ~~are~~amounting ~~significant~~to ~~but~~$97 ~~not~~million ~~reflective~~recognized ofas ~~our~~revenue ~~underlying~~during ~~operations. For~~ the ~~years~~fourth ~~ended~~quarter ~~December~~of ~~31, 2019 and 2017, we do not have any similar adjustments in our Adjusted EBITDA. Accordingly, for the years ended December 31, 2019 and 2017 our EBITDA is the same as Adjusted EBITDA.~~2018;

•the $537 million net long-lived asset impairment charge to Bison’s current carrying value; and

•the $59 million impairment charge related to Tuscarora’s goodwill.

We believe these items are significant but not reflective of our underlying operations. For the years ended December 31, 2020 and 2019, we do not have any non-recurring adjustments in our Adjusted EBITDA.

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 twelve months ended December 31, 2019 and 2018 was recast to conform with the current presentation. The Partnership believes the revised presentation more closely aligns with similar non-GAAP financial 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 amount presented.

Total distributable cash flow does not factor in any growth capital spending. It includes our Adjusted EBITDA ~~plus~~:

● Distributions from our equity investments

less:

~~● Earnings from our equity investments~~•AFUDC,

●•Interest ~~Allowance for funds used during construction (AFUDC)~~expense,

●•Current ~~Interest~~income ~~expense~~taxes,

●•Distributions ~~Current~~to ~~income~~non-controlling ~~taxes~~interests, and

●•Maintenance ~~Distributions~~capital ~~to non-controlling interests,~~expenditures.

●Distributable cash flow is computed net of distributions declared to the General Partner and any distributions allocable to Class B units. Distributions declared to TCthe ~~Energy~~General asPartner ~~former~~are ~~parent~~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 ~~PNGTS~~GTN’s distributable cash flow less $20 million, the residual of which is further multiplied by 43.75 percent. (Class B Distribution) (2019 and 2018 - less $20 million only).

●For ~~Maintenance~~the ~~capital~~year ~~expenditures~~ended December 31, 2020, the Class B Distribution was 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 and will apply to any calendar year during which distributions payable in respect of common units for such calendar year do not equal or exceed $3.94 per common unit.

Distributable cash flow, isEBITDA ~~computed net of distributions declared to the General Partner~~ and ~~distributions~~Adjusted ~~allocable~~EBITDA toare ~~Class~~performance Bmeasures ~~units.~~presented ~~Distributions declared~~ to ~~the~~assist ~~General~~investors ~~Partner~~in ~~are~~evaluating ~~based~~our onbusiness ~~its two percent interest plus an amount equal to incentive distributions~~performance. ~~Distributions~~We ~~allocable~~believe tothese ~~the~~measures ~~Class~~provide Badditional ~~units~~meaningful ~~equal~~information 30in ~~percent~~evaluating ofour ~~GTN’s~~financial ~~distributable~~performance ~~cash flow for the year ended December 31, 2019, less $20 million (Class B Distribution) (2018~~ and ~~2017~~cash –generating ~~less $20 million)~~capacity.

~~For~~The ~~the~~non-GAAP ~~year~~financial ~~ended~~measures ~~December~~described ~~31,~~above ~~2019,~~are ~~the~~provided ~~Class~~as Ba ~~Distribution~~supplement ~~was~~to ~~further~~GAAP ~~reduced~~financial byresults 35and ~~percent,~~are ~~which~~not ismeant ~~equivalent~~ to ~~the~~be ~~percentage~~considered byin ~~which~~isolation ~~distributions~~or ~~payable~~as tosubstitutes ~~the~~for ~~common~~financial ~~units~~results ~~were~~prepared ~~reduced~~ in ~~2018~~accordance ~~(Class~~with ~~B Reduction)~~GAAP. ~~The~~Additionally, ~~Class~~these Bmeasures ~~Reduction~~as ~~was~~presented ~~implemented~~may ~~during~~not ~~the~~be ~~first~~comparable ~~quarter of 2018 following the Partnership’s common unit distribution reduction of 35 percent and will apply~~ to ~~any~~similarly ~~calendar~~titled ~~year~~measures ~~during which distributions payable in respect~~ of ~~common~~other ~~units~~ companies.

52 TC PipeLines, LP Annual Report ~~2019~~2020 57

Table of Contents

for such calendar year do not equal or exceed $3.94 per common unit. The Class B Reduction was not applicable during 2017.

Adjusted earnings and Adjusted earnings per common unit exclude the 2018 impact of the $97 million of Bison contract termination proceeds and $596 million of impairment charges incurred during the year ended December 31, 2018 on our net income on a whole and per common unit basis, respectively.

Distributable cash flow, EBITDA, Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit 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 performance.

The non-GAAP 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 information 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 (Loss) to EBITDA, Adjusted EBITDA and Distributable Cash Flow

The following table presents a reconciliation of the non-GAAP financial measures of EBITDA, Adjusted EBITDA and Distributable Cash Flow, to the GAAP financial measure of net income.


Year Ended December 31(unaudited)(millions of dollars)		2020		2019	2018
Year Ended December 31
Net income (loss)		301		298	(165)
(unaudited)
Add (Less):
(millions of dollars)	2019		2018	2017
Interest expense(a)		83		85	94
Net income (loss)	298		(165)	263
Depreciation and amortization		89		78	97
Add (Less):
Income tax expense (benefit)		6		(1)	1
Interest expense(a)	85		94	84
EBITDA		479		460	27
Depreciation and amortization	78		97	97
Add (less):
Income tax expense (benefit)	(1)		1	1
Non-recurring items
EBITDA	460		27	445
Impairment of goodwill		—		—	59
Add:
Impairment of long‑lived assets		—		—	537
Impairment of goodwill	—		59	—
Bison contract terminations		—		—	(97)
Impairment of long‑lived assets	—		537	—
Less:
Bison contract terminations	—		(97)	—
Equity earnings:
ADJUSTED EBITDA	460		526	445
Northern Border		(76)		(69)	(68)
Add:
Great Lakes		(56)		(51)	(59)
Distributions from equity investments(b)
Iroquois		(38)		(40)	(46)
Northern Border	93		85	82
		(170)		(160)	(173)
Great Lakes	55		66	38
Add:
Iroquois(c)	69		56	41
Distributions from equity investments(b)
	217		207	161
Northern Border		90		93	85
Less:
Great Lakes		43		55	66
Equity earnings:
Iroquois(c)		46		69	56
Northern Border	(69)		(68)	(67)
		179		217	207
Great Lakes	(51)		(59)	(31)
ADJUSTED EBITDA		488		517	560
Iroquois	(40)		(46)	(26)
Less:
	(160)		(173)	(124)
AFUDC		(11)		(2)	(1)
Less:
Interest expense(a)		(83)		(85)	(94)
AFUDC	(2)		(1)	—
Current income taxes (d)		(3)		(1)	(1)
Interest expense(a)	(85)		(94)	(84)
Distributions to non‑controlling interests(e)		(22)		(21)	(20)
Current income taxes (d)	(1)		(1)	(1)
Maintenance capital expenditures(f)		(110)		(56)	(36)
Distributions to non‑controlling interests(e)	(21)		(20)	(14)
		(229)		(165)	(152)
Distributions to TC Energy as PNGTS' former parent(f)	—		—	(2)
Total Distributable Cash Flow		259		352	408
Maintenance capital expenditures(g)	(56)		(36)	(38)
General Partner distributions declared(g)		(4)		(4)	(4)
	(165)		(152)	(139)
Distributions allocable to Class B units(h)		—		(8)	(13)
Total Distributable Cash Flow	352		408	343
Distributable Cash Flow		255		340	391
General Partner distributions declared(h)	(4)		(4)	(18)
Distributions allocable to Class B units(i)	(8)		(13)	(15)
Distributable Cash Flow	340		391	310

(a)Interest expense as presented includes net realized loss related to the interest rates swaps and amortization of realized loss on PNGTS’ derivative instruments and does not include amortization of debt issuance and discount costs (Refer to Notes 12 and 19, Notes to Consolidated Financial Statements included in Part IV, Item 15. “Exhibits and Financial Statement Schedules”).

~~(a) Interest expense as presented includes net realized loss related to the interest rates swaps and amortization of realized loss on PNGTS’ derivative instruments (Refer to Notes 13 and 20~~58 TC PipeLines, ~~Notes to Consolidated Financial Statements included in Part IV, Item 15. “Exhibits and Financial Statement Schedules”).~~ LP Annual Report 2020

TC PipeLines, LP Annual Report 2019 53

Table of Contents

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

(c) This amount represents our proportional 49.34 percent share of the distribution declared by our equity investee, Iroquois, for the current reporting period and excludes any distributions received that are considered return of investment. It also includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $10 million for both years ended December 31, 2019 and December 31, 2018 ~~and~~(2020 $8- ~~million for the year ended December 31, 2017~~none). In 2020 and 2019, we also received an additional distribution of $4 million and $15 million, respectively related to the increase in the cash Iroquois generated from its higher income in 2017 (post acquisition) ~~and~~to ~~2018~~2020. (Refer to Notes 5 and 7, Notes to Consolidated Financial Statements included in Part IV, Item 15. “Exhibits and Financial Statement Schedules”).

(d) Beginning with the year ended December 31, 2019, we reduced our distributable cashflows ~~based~~by oncurrent income tax expense which approximates net cash paid during the current period. The change did not materially impact comparability to prior periods. Additionally, beginning in 2020, the Partnership became subject to a corporate activity tax in Oregon. Current income tax expense includes taxes paid by PNGTS on its New Hampshire state taxes ~~which~~and ~~approximates~~taxes ~~net cash~~ paid ~~during~~by the ~~current~~Partnership ~~period~~on its Oregon corporate activity tax. For ~~The~~the ~~change~~year ~~did~~ended ~~not~~December ~~materially~~31, ~~impact~~2020, ~~comparability~~the toPartnership ~~prior~~recognized ~~periods~~$0.6 million for the Oregon corporate activity tax..

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

(f)The ~~Distributions~~Partnership’s maintenance capital expenditures include expenditures made to TCmaintain, ~~Energy~~over asthe ~~PNGTS~~long term, our assets’ ~~former~~operating ~~parent~~capacity, ~~represent~~system TCintegrity ~~Energy~~and reliability. Accordingly, this amount represents the Partnership’s ~~respective~~and its Consolidated Subsidiaries’ maintenance capital expenditures and does not include the Partnership’s share of ~~PNGTS’~~maintenance capital expenditures on 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. ~~not~~Please ~~owned~~read bythe usCapital ~~during~~spending section for more information regarding the ~~periods~~Partnership’s ~~presented~~total proportionate share of maintenance capital expenditures from our consolidated entities and equity investments.

(g)Distributions ~~The~~declared ~~Partnership’s~~to ~~maintenance~~the ~~capital~~General ~~expenditures~~Partner ~~include~~for ~~expenditures made to maintain, over~~ the ~~long~~year ~~term,~~ended ~~our~~December ~~assets’ operating capacity~~31, ~~system integrity and reliability. Accordingly~~2020, ~~this~~2019 ~~amount represents the Partnership’s~~ and ~~its~~2018 ~~Consolidated~~did ~~Subsidiaries’ maintenance capital expenditures and does~~ not include ~~the~~any ~~Partnership’s~~incentive ~~share of maintenance capital expenditures on our equity investments~~distributions. Such amounts are reflected in “Distributions from equity investments” as those amounts are withheld by those entities from their quarterly distributable cash. Please read the Capital spending section for more information regarding the Partnership’s total proportionate share of maintenance capital expenditures from our consolidated entities and equity investments.

(h) Distributions ~~declared~~allocable to the ~~General~~Class ~~Partner~~B ~~for~~units is based on 30 percent of GTN’s distributable cashflow during the current reporting period but declared and paid in the subsequent reporting period. During the year ended December 31, ~~2019~~2020, ~~did~~no distributions were declared as certain thresholds in the agreement were not ~~include~~met. ~~any~~Beginning ~~incentive~~in ~~distributions~~2021, ~~(2018~~we -expect ~~none;~~the ~~2017~~impact -of ~~$12~~Class ~~million)~~B distribution on our distributable cashflow to be significantly lower compared to previous periods.

~~(i)~~Year ~~Distributions~~Ended ~~allocable~~December to31, ~~the~~2020 ~~Class~~Compared Bwith ~~units is based on 30 percent of GTN’s distributable cashflow during~~ the ~~current~~Year ~~reporting~~Ended ~~period~~December ~~but~~31, ~~declared and paid in the subsequent reporting period.~~2019

Our EBITDA was higher for the year ended December 31, 2020 compared to the same period in 2019. The $19 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.

Our Adjusted EBITDA was lower for the year ended December 31, 2020 compared to the same period in 2019. The $29 million decrease was primarily due to:

•lower operating costs partially offset by lower revenue from consolidated subsidiaries as discussed in more detail under the “Results of Operations” section;

•no distributions from Great Lakes during the third 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 during the year ended December 31, 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 maintenance capital expenditures at GTN as a result of increased spending on major equipment overhauls at several compressor stations and certain system upgrades.

Year Ended December 31, 2019 Compared with the Year Ended December 31, 2018

Our EBITDA was $433 million higher in 2019 compared to 2018 due to the 2018 goodwill impairment of $59 million for Tuscarora and the long-lived asset impairment for Bison of $537 million, partially offset by the additional $97 million in revenue recognized for the Bison contract terminations. ~~Our Adjusted EBITDA was lower by $66 million compared to 2018 as a result of higher equity earnings lower revenues and higher operating expenses Refer to “Results of Operations” for more details.~~

Our ~~distributable~~Adjusted ~~cash~~EBITDA ~~flow~~was ~~decreased~~lower by $5143 million ~~for the year ended December 31, 2019 compared to the same period in 2018~~ due to the net effect of:

● lower Adjusted EBITDA from our Consolidated Subsidiaries primarily due to significantly lower revenues from Bison from being 100 percent fully contracted in 2018 to only approximately 40 percent in 2019 and an overall increase in our operating expenses as discussed in more detail in the Results of Operations Section;TC PipeLines, LP Annual Report 2020 59

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

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

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

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

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

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

Year Ended December 31, 2018 Compared with the Year Ended December 31, 2017

Our EBITDA was $418 million lower in 2018 compared to 2017 due to the goodwill impairment of $59 million for Tuscarora and the long-lived asset impairment for Bison of $537 million, partially offset by the additional $97 million in revenue recognized for the Bison contract terminations. Our Adjusted EBITDA was higher by $81 million compared to 2017 as a result of higher equity earnings and an overall increase in revenues in 2018. Refer to “Results of Operations” for more details.

54 TC PipeLines, LP Annual Report 2019

Table of Contents

~~Our~~•significantly ~~distributable~~lower ~~cash~~revenues ~~flow~~from ~~for~~Bison ~~the~~from ~~twelve~~being ~~months~~100 ~~ended~~percent ~~December~~fully ~~31,~~contracted in 2018 ~~was~~to ~~$81~~only ~~million~~approximately ~~higher~~40 ~~compared~~percent toin ~~the~~2019 ~~twelve~~and ~~months~~an ~~ended~~overall ~~December~~increase ~~31,~~in ~~2017~~our ~~due~~operating toexpenses ~~the~~from ~~net~~our ~~effect~~consolidated subsidiaries as discussed in more detail in the Results of: Operations Section;

● •higher ~~Adjusted~~distributions ~~EBITDA~~ from ~~GTN,~~our ~~PNGTS~~equity ~~and~~investment ~~North Baja due to an increase~~ in ~~their~~Northern ~~revenues~~Border ~~generated~~primarily ~~during~~due ~~the~~to ~~twelve~~lower ~~months~~capital ~~ended~~spending ~~December~~related ~~31,~~to ~~2018~~compressor asstation ~~described~~maintenance ~~in the “Results of Operations” section~~costs;

●•lower ~~four quarters of~~ distributions ~~received~~ from ~~Iroquois~~Great ~~during~~Lakes ~~the~~resulting ~~twelve~~from ~~months~~decreased ~~ended~~earnings ~~December~~and ~~31,~~increased ~~2018~~maintenance ~~compared~~capital ~~to three quarters of distributions received during the previous period (ownership of 49.34 percent was effective June 1, 2017)~~spending;

●•additional ~~higher~~distribution ~~financing~~received ~~costs~~from asIroquois adue ~~result~~to ofthe ~~additional~~surplus ~~debt~~cash ~~incurred~~accumulated tofrom ~~partially~~previous ~~finance~~years' ~~the~~higher ~~2017~~net ~~Acquisition~~income;

●Our ~~higher~~distributable ~~distributions~~cash ~~from~~flow ~~Great~~decreased ~~Lakes~~by ~~due~~$51 tomillion ~~the~~for ~~increase in its revenue generated during~~ the ~~twelve~~year ~~months~~ ended December 31, ~~2018~~2019 ~~from~~compared ~~higher~~to ~~short-term services sold during~~ the ~~year~~same ~~and~~period ~~the elimination of Great Lakes’ revenue sharing mechanism that began~~ in 2018 asdue ~~part~~to ofthe ~~Great~~net ~~Lakes~~effect ~~rate settlement in 2017;~~of:

●•lower ~~higher~~Adjusted ~~distributable~~EBITDA ~~cash~~as ~~flow~~a ~~from~~result ~~Northern~~of lower ~~Border~~revenues ~~primarily~~and ~~due~~higher tooperating anexpenses ~~overall~~from ~~decrease~~consolidated insubsidiaries ~~its~~offset ~~system~~by ~~integrity~~higher ~~maintenance~~distributions ~~capital~~from ~~expenditures~~our inequity ~~2018;~~investments as discussed above

●•higher ~~reduction~~maintenance incapital ~~declared~~expenditures ~~distributions~~related ~~which~~to ~~did~~major ~~not~~compression ~~result~~equipment inoverhauls ~~any~~and ~~IDR~~pipe ~~allocation~~integrity tocosts ~~our~~on ~~General~~GTN ~~Partner~~as ~~during~~a ~~the~~result ~~current~~of ~~period;~~higher ~~and~~transportation volumes of natural gas;

● •lower ~~distributions~~interest ~~allocated~~expense due to the ~~Class~~full Brepayment ~~units~~of asthe a$170 ~~result~~million ofTerm Loan during the ~~Class~~fourth Bquarter ~~Reduction,~~of ~~which~~2018 ~~was~~and ~~directly~~the ~~related~~partial torepayment ~~the~~of ~~reduction~~borrowings inunder ~~distributions~~our ~~declared~~Senior ~~for~~Credit Facility in the ~~common~~first ~~units.~~quarter of 2019; and

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

The Partnership’s Contractual Obligations

The Partnership’s contractual obligations as of December 31, ~~2019~~2020 included the following:


				Payments Due by Period
			Payments Due by Period
(unaudited)(millions of dollars)		Total		Less than1 Year		1‑3 Years		4‑5 Years		More than5 Years	Weighted Average Interest Rate for the Year Ended December 31,2020
								Weighted
TC PipeLines, LP
								Average
Senior Credit Facility due 2021		—		—		—		—		—	—
								Interest
2013 Term Loan Facility due 2022		450		—		450		—		—	1.87	%
								Rate for the
4.65% Senior Notes due 2021		350		350		—		—		—	4.65	%	(a)
								Year Ended
4.375% Senior Notes due 2025		350		—		—		350		—	4.375	%	(a)
(unaudited)			Less than	1‑3	4‑5		More than	December 31,
3.90% Senior Notes due 2027		500		—		—		—		500	3.90	%	(a)
(millions of dollars)	Total		1 Year	Years	Years		5 Years	2019
GTN
TC PipeLines, LP
5.69% Unsecured Senior Notes due 2035		150		—		—		—		150	5.69	%	(a)
Senior Credit Facility due 2021	—		—	—	—		—	—
3.12% Unsecured Senior Notes due 2030		175		—		—		—		175	3.12	%	(a)
2013 Term Loan Facility due 2022	450		—	450	—		—	3.52	%
PNGTS
4.65% Senior Notes due 2021	350		—	350	—		—	4.65	%(a)
Revolving Credit Facility due 2023		25		—		25		—		—	1.88	%
4.375% Senior Notes due 2025	350		—	—	—		350	4.375	%(a)
2.84% Unsecured Senior Notes due 2030		125		—		—		—		125	2.84	%	(a)
3.90% Senior Notes due 2027	500		—	—	—		500	3.90	%(a)
Tuscarora		—		—		—		—		—
GTN
Unsecured Term Loan due 2021		23		23		—		—		—	2.13	%
5.29% Unsecured Senior Notes due 2020	100		100	—	—		—	5.29	%(a)
North Baja
5.69% Unsecured Senior Notes due 2035	150		—	—	—		150	5.69	%(a)
Unsecured Term Loan due 2021		50		50		—		—		—	1.70	%
PNGTS
Partnership (TC PipeLines, LP and its subsidiaries)
Revolving Credit Facility due 2023	39		—	—	39		—	3.47	%
Interest on debt obligations(b)		428		71		112		93		152
Transportation by others	1		1	—	—		—
Operating leases		1		1		—		—		—
Tuscarora
		2,627		495		587		443		1,102
Unsecured Term Loan due 2020	23		23	—	—		—	3.39	%
North Baja
Unsecured Term Loan due 2021	50		—	50	—		—	3.34	%
Partnership (TC PipeLines, LP and its subsidiaries)
Interest on debt obligations(b)	430		78	123	87		142
Operating leases	3		1	1	—		1
	2,446		203	974	126		1,143

60 TC PipeLines, LP Annual Report 2020

(a) Fixed Rate debt

(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 December 31, 2019 and are therefore subject to change beyond 2019. Future interest payments on floating rate debt do not include potential obligation related to our interest rate swaps.

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~~Additional~~(a)Fixed ~~information regarding the Partnership’s debt and interest~~ rate swaps can be found under Note 9 - Debt and Credit Facilities and Note 20- Fair Value measurements, respectively within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.debt

(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 December 31, 2020 and are therefore subject to change beyond 2020. Future interest payments on floating rate debt do not include potential obligation related to our interest rate swaps.

Additional information regarding the Partnership’s debt and interest rate swaps can be found under Note 8 - Debt and Credit Facilities and Note 19 - Fair Value measurements, respectively within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

Summary of Northern Border’s Contractual Obligations

Northern Border’s contractual obligations as of December 31, ~~2019~~2020 included the following:


				Payments Due by Period(a)
			Payments Due by Period(a)
(unaudited)(millions of dollars)		Total		Less than1 Year		1‑3Years		4‑5Years	More than5 Years
(unaudited)			Less than	1‑3	4‑5		More than
$200 million Credit Agreement due 2024		130		—		—		130	—
(millions of dollars)	Total		1 Year	Years	Years		5 Years
7.50% Senior Notes due 2021 (b)		250		250		—		—	—
$200 million Credit Agreement due 2024	115		—	—	115		—
Interest payments on debt (c)		20		15		4		1	—
7.50% Senior Notes due 2021	250		—	250	—		—
Other commitments(d)		47		3		6		6	32
Interest payments on debt	50		22	21	7		—
		447		268		10		137	32
Other commitments(b)	48		3	5	5		35
	463		25	276	127		35

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

(ab)Expected ~~Represents~~to ~~100~~have ~~percent~~the offinancing ~~Northern~~arranged ~~Border’s~~to ~~contractual~~repay ~~obligations~~this debt at maturity.

(bc)Future interest payments on our fixed rate debt are based on scheduled maturities. Future ~~minimum~~interest payments ~~for~~on ~~office~~floating ~~space~~rate debt are estimated using debt levels and ~~rights-of-way~~interest ~~commitments~~rates at December 31, 2020 and are therefore subject to change.

~~Northern~~(d)Future ~~Border~~minimum ~~has~~payments ~~commitments~~for ofoffice ~~$9 million~~space asand rights-of-way ~~December 31, 2019 in connection with various pipeline, metering and overhaul projects~~commitments.

Northern Border has commitments of $15 million as of December 31, 2020 in connection with various pipeline, metering and overhaul projects.

Senior Notes

Northern Border’s outstanding debt securities are senior unsecured notes. The indentures for the notes do not limit the amount of unsecured debt Northern Border may incur but do restrict secured indebtedness. At December 31, ~~2019~~2020, Northern Border was in compliance with all of its financial covenants.

Credit Agreement

Northern Border’s credit agreement consists of a $200 million revolving credit facility. On October 1, 2019, the credit agreement was extended to mature on October 1, 2024. At December 31, ~~2019~~2020, $~~115~~130 million was outstanding on this facility. At Northern Border’s option, the interest rate on the outstanding borrowings may be the lenders' base rate or LIBOR plus, in either case, an applicable margin that is based on Northern Border’s long-term unsecured credit ratings. The interest rate on Northern Border’s credit agreement at December 31, ~~2019~~2020 was 21.8228 percent (~~2018~~2019 – 32.4882 percent). At December 31, ~~2019~~2020, Northern Border was in compliance with all of its financial covenants. Please read Part II Item 7A- "Quantitative and Qualitative Disclosures About Market Risk." for information about LIBOR phase-out.

Summary of Great Lakes’ Contractual Obligations

Great Lakes’ contractual obligations as of December 31, ~~2019~~2020 included the following:


				Payments Due by Period(a)
			Payments Due by Period(a)
(unaudited)(millions of dollars)		Total		Less than1 Year		1‑3Years		4‑5Years	More than5 Years
(unaudited)			Less than	1‑3	4‑5		More than
9.09% series Senior Notes due 2021		10		10		—		—	—
(millions of dollars)	Total		1 Year	Years	Years		5 Years
6.95% series Senior Notes due 2021 to 2028		88		11		22		22	33
9.09% series Senior Notes due 2016 to 2021	20		10	10	—		—
8.08% series Senior Notes due 2021 to 2030		100		10		20		20	50
6.95% series Senior Notes due 2020 to 2028	99		11	22	22		44
Interest payments on debt (b)		66		14		22		16	14
8.08% series Senior Notes due 2021 to 2030	100		—	20	20		60
Right-of-way commitments		1		—		—		—	1
Interest payments on debt	82		16	26	19		21
		265		45		64		58	98
Right-of-way commitments	1		—	—	—		1
	302		37	78	61		126

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

(ab)Future ~~Represents~~interest ~~100~~payments ~~percent~~on ofour ~~Great~~fixed ~~Lakes’~~rate ~~contractual~~debt ~~obligations.~~are based on scheduled maturities

Great Lakes has commitments of $46 million as of December 31, ~~2019~~2020 in connection with compressor overhaul projects.

Long-Term Financing

~~All of Great Lakes’ outstanding debt securities are senior unsecured notes with similar terms except for interest rates~~TC PipeLines, ~~maturity dates and prepayment premiums.~~ LP Annual Report 2020 61

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

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All of Great Lakes’ outstanding debt securities are senior unsecured notes with similar terms except for interest rates, maturity dates and prepayment premiums.

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately $107 million of Great Lakes’ partners’ capital was restricted as to distributions as of December 31, 2020 (2019 - $118 million). Great Lakes was in compliance with all of its financial covenants at December 31, 2020.

Summary of Iroquois’ Contractual Obligations

Iroquois’ contractual obligations as of December 31, ~~2019~~2020 included the following:


				Payments Due by Period(a)
			Payments Due by Period(a)
(unaudited)(millions of dollars)		Total		Less than 1 Year		1‑3Years		4‑5Years	More than5 Years
(unaudited)			Less than	1‑3	4‑5		More than
4.12% series Senior Notes due 2034		140		—		—		—	140
(millions of dollars)	Total		1 Year	Years	Years		5 Years
4.07% series Senior Notes due 2030		150		—		—		—	150
4.12% series Senior Notes due 2034	140		—	—	—		140
6.10% series Senior Notes due 2027		26		5		7		8	6
4.07% series Senior Notes due 2030	150		—	—	—		150
Interest payments on debt (b)		141		13		26		25	77
6.10% series Senior Notes due 2027	29		3	8	8		10
Transportation by others(c)		6		3		3		—	—
Interest payments on debt	95		11	14	14		56
Operating leases		10		1		2		2	5
Transportation by others(b)	9		3	6	—		—
Pension contributions(d)		1		1		—		—	—
Operating leases	4		1	1	—		2
		474		23		38		35	378
Pension contributions(c)	1		1	—	—		—
	428		19	29	22		358

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

(ab)Future ~~Represents~~interest ~~100~~payments ~~percent~~on ofour ~~Iroquois’~~debt ~~contractual~~are ~~obligations~~based on scheduled maturities.

(bc) Rates are based on known 2020 levels. Beyond ~~2020~~2021, demand rates are subject to change.

(cd) Pension contributions cannot be reasonably estimated by Iroquois beyond ~~2020~~ 2021.

Iroquois has no commitments ~~of $2.5 million~~ as of December 31, ~~2019~~2020 relative to capital expenditures.

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/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 December 31, ~~2019~~2020, the debt/capitalization ratio was 5257.17 percent and the debt service coverage ratio was 57.3808 times, therefore, Iroquois was not restricted from making cash distributions.

Cash Distribution Policy of the Partnership

The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and our General Partner after providing for Class B distributions based on the specified target distribution levels. The percentage interests set forth below for our General Partner include its IDRs and two percent general partner interest and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The percentage interest distributions to the General Partner illustrated below that are in excess of its two percent general partner interest represent the IDRs.


							Marginal PercentageInterest in Distribution
			Marginal Percentage
				Total Quarterly DistributionPer Unit Target Amount			CommonUnitholders		GeneralPartner
			Interest in Distribution
Minimum Quarterly Distribution		$		0.45			98	%	2	%
		Total Quarterly Distribution	Common		General
First Target Distribution				above $0.45 up to $0.81			98	%	2	%
		Per Unit Target Amount	Unitholders		Partner
Second Target Distribution				above $0.81 up to $0.88			85	%	15	%
Minimum Quarterly Distribution	$	0.45	98	%	2	%
Thereafter				above $0.88			75	%	25	%
First Target Distribution		above $0.45 up to $0.81	98	%	2	%
Second Target Distribution		above $0.81 up to $0.88	85	%	15	%
Thereafter		above $0.88	75	%	25	%

Our quarterly declared cash distributions in 2020 remained the same as in 2019, which was $0.65 per common unit or $2.60 per common unit in total for the year. Incentive distributions (IDRs) are paid to our General Partner if quarterly cash distributions on the common units exceed levels specified in the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership (as amended, the Partnership Agreement). The distributions declared during 2020 did not reach the specified levels for any period and, therefore, the General Partner did not receive any distributions in respect of its IDRs in 2020. To date, there has been no annual Class B distribution for 2021. In 2020, the Class B distribution paid was $8 million. For more information, please see Note 14 - Cash Distributions within Part IV, Item 15. “Exhibits and Financial Statement Schedules.”

Further information regarding our distributions can be found under Note 15 - Cash Distributions within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

Distribution Policies of Our Pipeline Systems

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Distributions of available cash are made to partners on a pro rata basis according to each partner’s ownership percentage, approximately one month following the end of a quarter. Our pipeline systems’ respective management committees determine the amounts and timing of cash distributions, where the amounts of such distributions are based on distributable cash flow as determined by a prescribed formula. Any changes to, or suspension of our pipeline systems’ cash distribution policies requires the unanimous approval of their respective management committees.

GTN, Bison, PNGTS and North Baja’s distribution policies require the pipelines to distribute 100 percent of distributable cash flow based on earnings before depreciation and amortization less AFUDC and maintenance capital expenditures. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

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Tuscarora’s distribution policy requires the distribution of 100 percent of distributable cash flow based on earnings before depreciation and amortization less debt repayment, AFUDC and maintenance capital expenditures. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

Iroquois and PNGTS distribute their available cash less any required reserves that are necessary to comply with debt covenants and/or appropriately conduct their respective businesses, as determined and approved by their management committees. While PNGTS’ and Iroquois’ debt repayments are not funded with capital calls to their owners, PNGTS and Iroquois have historically funded scheduled debt repayments by adjusting cash available for distribution, which effectively reduces the amount of cash available for distributions.

Northern Border’s distribution policy requires Northern Border to distribute on a monthly basis, 100 percent of the distributable cash flow based on earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. Northern Border adopted certain changes related to equity contributions that defined minimum equity to total capitalization ratios to be used by the Northern Border management committee to determine the amount of required equity contributions, timing of the required contributions and for any shortfall due to the inability to refinance maturing debt to be funded by equity contributions.

Great Lakes’ distribution policy requires the distribution of 100 percent of distributable cash flow based on earnings before income taxes, depreciation, AFUDC less capital expenditures and debt repayments not funded with cash calls to its partners. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ.

We believe our critical accounting estimates discussed in the following paragraphs require us to make the most significant assumptions when preparing our financial statements and changes in these assumptions could have a material impact on the financial statements. These critical accounting estimates should be read in conjunction with our accounting policies summarized on Notes 2 and 3, Notes to Consolidated Financial Statements included in Part IV within Item 15. “Exhibits and Financial Statement Schedules."

Regulation

Our pipeline systems’ accounting policies conform to Accounting Standards Codification (ASC) 980 – Regulated Operations. As a result, our pipeline systems record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. Our pipeline systems consider several factors to evaluate their continued application of the provisions of ASC 980 such as potential deregulation of their pipelines; anticipated changes from cost-based rate-making to another form of regulation; increasing competition that limits their ability to recover costs; and regulatory actions that limit rate relief to a level insufficient to recover costs.

Certain assets that result from the rate-making process are reflected on the balance sheets of our pipeline systems. If it is determined that future recovery of these assets is no longer probable as a result of discontinuing application of ASC 980 or other regulatory actions, our pipeline systems would be required to write off the regulatory assets at that time. Due to the impairment recognized on Bison during the fourth quarter of 2018 (discussed in more detail below under “Long -Lived Assets”), ASC 980 on Bison was discontinued as the future recovery of costs is no longer probable. The impact of ASC 980 discontinuance on Bison was immaterial to the consolidated results of the Partnership.

At December 31, ~~2019~~2020, the Partnership had no regulatory assets or regulatory liabilities reported as part of other current assets or accounts payable and accrued liabilities on the balance sheet, respectively.

~~As of December 31~~TC PipeLines, ~~2019, our equity investees have regulatory assets amounting to $13 million (2018 - $14 million).~~ LP Annual Report 2020 63

As of December 31, 2019, our equity investees have regulatory liabilities amounting to $39 million (2018 - $34 million).

At December 31, 2018, the Partnership had $2 million of regulatory assets reported as part of other current assets on the balance sheet and $2 million of regulatory liabilities reported on the balance sheet as part of accounts payable and

58 TC PipeLines, LP Annual Report 2019

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~~accrued~~As ~~liabilities~~of ~~both~~December ~~representing~~31, ~~volumetric~~2020, ~~fuel~~our ~~tracker~~equity ~~assets~~investees ~~that~~have ~~are~~regulatory ~~settled~~assets ~~with~~amounting ~~in-kind~~to ~~exchanges~~$14 ~~with~~million ~~customers~~(2019 on- a$13 ~~continued basis~~million).

As of December 31, ~~2019~~2020, ~~the~~our ~~Partnership~~equity ~~had~~investees have regulatory liabilities ofamounting to $2945 million ~~largely related to estimated costs associated with future removal of transmission and gathering facilities or allowed by FERC to be collected in depreciation rates~~ (~~also~~2019 ~~known as “negative salvage”) (2018~~ - $2739 million).

As of December 31, 2020, the Partnership had regulatory liabilities of $38 million largely related to estimated costs associated with future removal of transmission and gathering facilities or allowed by FERC to be collected in depreciation rates (also known as “negative salvage”) (2019 - $29 million).

Impairment of Goodwill, Long-Lived Assets and Equity Investments

Goodwill

We test goodwill for impairment annually based on ASC 350 – Intangibles – Goodwill and Other, or more frequently if events or changes in circumstances lead us to believe it might be impaired. We can initially assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired and, if we conclude that there is not a greater than 50 percent likelihood that the fair value of the reporting unit is greater than its carrying value, will then perform the quantitative goodwill impairment test. We can also elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Partnership compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value.

We base these valuations on our projection of future cash flows which involves making estimates and assumptions about:

● •discount rates and multiples;

● •commodity and capacity prices;

● •market supply and demand assumptions;

● •growth opportunities;

● •output levels;

● •competition from other companies;

● •regulatory changes; and

● •regulatory rate action or settlement.

If our assumptions are not appropriate, or future events indicate that our goodwill is impaired, our net income would be impacted by the amount by which the carrying value exceeds the fair value of reporting unit, to the extent of the balance of goodwill.

~~2018~~Under ~~Impairment~~U.S. ofGAAP, ~~Goodwill~~we evaluate our goodwill related to Tuscarora and North Baja for impairment at least annually and if any indicators of impairment are evident.

In ~~the fourth quarter of~~ 2018, ~~Tuscarora~~our ~~initiated~~analysis ~~its~~resulted ~~regulatory approach~~ in ~~response to~~ the ~~2018~~estimated ~~FERC~~fair ~~Actions,~~value ~~resulting~~of inTuscarora anot ~~reduction~~exceeding in its ~~maximum~~carrying ~~rates.~~value, Inincluding ~~connection~~goodwill ~~with~~that ~~our~~primarily ~~annual~~resulted ~~goodwill~~from ~~impairment~~the ~~analysis,~~2019 ~~we evaluated~~ Tuscarora’s ~~future~~Settlement ~~revenues~~ as ~~well~~part as changes to other valuation assumptions responsive to Tuscarora’s commercial environment, which included estimates related to discount rates and earnings multiples. In doing so, we incorporated the expected impact of ~~Tuscarora’s regulatory approach in response to~~ the 2018 FERC Actions,. inAs ~~which~~a itresult, ~~elected~~we torecorded ~~make~~ a ~~limited~~goodwill ~~NGA~~impairment ~~Section~~charge 4amounting ~~filing~~ to ~~reduce~~$59 million ~~its~~against ~~maximum~~Tuscarora’s ~~rates~~goodwill ~~and~~balance ~~eliminate its deferred income tax balances previously used for rate setting. Additionally, for the year ended December 31, 2018, we considered the outcome~~ of ~~the 2019 Tuscarora Settlement with its customers in our overall conclusion~~$82 million.

~~Our~~In ~~analysis~~2019, ~~resulted~~based inon ~~the~~our ~~estimated~~analysis ~~fair value~~ of Tuscarora ~~not~~and ~~exceeding~~North ~~its~~Baja’s ~~carrying~~current ~~value~~market conditions, ~~including~~we ~~goodwill.~~believed ~~The~~there was a greater than 50 percent likelihood that Tuscarora and North Baja’s estimated fair value ~~was~~exceeded ~~measured~~their ~~using~~carrying value. As a ~~discounted~~result, ~~cash~~at ~~flow~~December ~~approach~~31, ~~whereby~~2019, ~~the~~we ~~expected~~did ~~cashflows~~not ~~were~~identify ~~discounted~~an ~~using~~impairment aon ~~risk~~the ~~adjusted~~$71 ~~discount~~million ~~rate~~of goodwill related to ~~determine~~the ~~fair value~~Tuscarora ($23 million) and North Baja ($48 million) reporting units.

AsDuring aour ~~result,~~interim process we ~~recorded~~evaluated changes within our business and the external environment to assess whether a ~~goodwill~~triggering ~~impairment~~event ~~charge~~had ~~amounting~~occurred. This analysis included the interim assessment of the impact of COVID-19 to ~~$59 million~~our ~~against~~reporting units. Through this interim analysis, no triggering events were identified. Additionally, our annual impairment analysis on goodwill, resulted in a conclusion that there was a greater than 50 percent likelihood that both Tuscarora’s ~~goodwill~~and ~~balance~~North ofBaja’s ~~$82 million~~estimated fair values would continue to exceed their carrying values. ~~The~~Therefore, ~~non-cash~~no impairment ~~charge~~exists ~~was~~on ~~recorded~~our goodwill. Adverse changes to our key considerations could, however, result in ~~the~~future ~~Impairment~~impairments ofon our goodwill. ~~line~~See onItem ~~the~~1. ~~Consolidated~~"Business ~~statement~~– ofRecent ~~operations~~Business ~~and~~Developments ~~reduced~~– ~~our~~COVID-19" ~~total~~and ~~consolidated~~Note ~~goodwill~~4- ~~balance~~Goodwill ~~from~~within ~~$130 million~~Part toIV, ~~$71 million~~Item 15. “Exhibits and Financial Statement Schedules” which information is incorporated herein by reference

2019 Update

In 2019, based on our qualitative analysis of Tuscarora and North Baja’s current market conditions, which includes consideration of the potential qualitative impact of current year changes in the multiples and discount rate assumptions compared to multiples and discount rate assumptions used in the prior quantitative model, we believe there is 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 have not identified an impairment on the $71 million of goodwill related to Tuscarora ($23 million) and North Baja ($48 million) acquisitions.

TC PipeLines, LP Annual Report 2019 59

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There is a risk that adverse changes in our key assumptions could result in an additional future impairment on Tuscarora’s remaining goodwill of $23 million.

Long-Lived Assets

We assess our long-lived assets for impairment based on ASC 360-10-35 Property, Plant and Equipment – Overall – Subsequent Measurement when events or changes in circumstances indicate that the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows expected to be generated by that asset or asset group is less than the carrying value of the assets, an impairment charge is recognized for the excess of the carrying value over the fair value of the assets. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals as considered necessary.

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Our management evaluates changes in our business and economic conditions and their implications for recoverability of our long-lived assets’ carrying values when assessing these assets for impairments. The development of fair value estimates requires significant judgement in estimating future cash flows. In order to determine the estimated future cash flows, management must make certain estimates and assumptions, which include the same factors we consider in our annual impairment test of goodwill such as:

● •discount rates and multiples;

● •commodity and capacity prices;

● •market supply and demand assumptions;

● •growth opportunities;

● •output levels;

● •competition from other companies;

● •regulatory changes; and

● •regulatory rate action or settlement.

Any changes we make to these estimates and assumptions could materially affect future cash flows, which could result to the recognition of an impairment loss in our Consolidated statement of operations.

As of December 31, ~~2019~~2020, there were no indicators of impairment on our long-lived assets.

2018 Impairment on Bison’s long-lived assets

During the fourth quarter of 2018, Bison received an unsolicited offer from a customer regarding the termination of its contract, which represented approximately 60 percent of Bison’s contracted revenues. Bison and the customer mutually agreed to terms which included a cash payment to Bison of $95.4 million in December 2018 in exchange for the termination of all its contract obligations with Bison. Following the amendment of its tariff to enable this transaction, another customer executed a similar agreement to terminate its contract on Bison in exchange for a ~~lumpsum~~lump sum payment to Bison of approximately $2.0 million in December 2018. At the termination of the contracts, Bison was released from performing any future services with the two customers and as such, the amounts received were recorded in revenue in 2018 and the cash payments were used by the Partnership, together with other cash to pay in full its 2015 Term Loan Facility.

As disclosed under Part 1, Item 1. Business - Customers, Contracting and Demand section, natural gas is currently not flowing on Bison as a result of the relative cost advantage of WCSB and Bakken sourced gas versus Rockies production. Since its inception in January 2011, Bison has not experienced a decrease in its revenue as its original ten-year contracts included ship-or-pay terms that resulted in payment to Bison regardless of gas flows. In 2018, the Partnership expected a significant erosion on the cash flows Bison will generate in the future as a result of the advanced payments to Bison and related cancellation of the above contracts. The customer contract cancellations coupled with the persistence of unfavorable market conditions which have inhibited system flows prompted management to re-evaluate the carrying value of Bison’s long-lived assets.

Although the Partnership continues to explore alternative transportation-related options for Bison, management is currently unable to quantify the future cash flows of a viable operating plan beyond the remaining customer contracts’ expiry in January 2021, and accordingly the Partnership evaluated for impairment the carrying value of its property, plant and equipment on Bison at December 31, 2018. The Partnership will continue to maintain Bison to stand ready for redevelopment and has concluded that the remaining obligations of Bison, primarily in the form of property tax obligations and operating and maintenance costs, exceed the net cash inflows that management currently considers probable and estimable.

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Based on these factors, during the fourth quarter of 2018, the Partnership recognized a non-cash impairment charge of $537 million relating to the remaining carrying value of Bison’s property, plant and equipment after determining that it was no longer recoverable. The non-cash charge was recorded under the Impairment of long-lived assets line on the Consolidated statement of operations.

Equity Investments

We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows which are determined using the same factors we consider in our annual impairment test of goodwill such as:

● •discount rates and multiples;

● •commodity and capacity prices;

● •market supply and demand assumptions;

● •growth opportunities;

~~● output levels;~~TC PipeLines, LP Annual Report 2020 65

●Table ~~competition~~of ~~from other companies;~~Contents

●•output ~~regulatory changes~~levels; ~~and~~

●•competition ~~regulatory~~from ~~rate~~other ~~action or settlement.~~companies;

•regulatory changes; and

•regulatory rate action or settlement.

Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered impairment.

If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.

As of December 31, ~~2019~~2020, no impairment charge has been recorded related to our equity investments. See also Item 1. "Business – Recent Business Developments – COVID-19" and Note 5- Equity Investments within Part IV, Item 15. “Exhibits and Financial Statement Schedules” which information is incorporated herein by reference.

2018 Quantitative Assessment of Great Lakes’ Fair Value

At December 31, 2018, the equity method goodwill balance related to Great Lakes amounted to $260 million (December 31, 2017- $260 million). The equity method goodwill relates to the Partnership’s February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes and is the difference between the carrying value of our investment in Great Lakes and the underlying equity in Great Lakes’ net assets.

During the fourth quarter of 2018, Great Lakes finalized its regulatory approach in response to the 2018 FERC Actions and elected to make a limited NGA section 4 filing with FERC to reduce its maximum rates and eliminate its tax allowance and deferred income tax balances previously used for rate setting. As a result of this action, and because the estimated fair value of our investment in Great Lakes exceeded its carrying value by less than ten percent in its 2017 valuation, we performed a quantitative test to determine if there was an other than temporary decline in Great Lakes’ fair value. The assumptions we used in our analysis related to the estimated fair value of our equity investment in Great Lakes included expected results from its limited NGA Section 4 filing with FERC, revenue opportunities on the system as well as changes to other valuation assumptions responsive to Great Lakes’ commercial environment, which includes estimates related to discount rates and earnings multiples. At December 31, 2018, we concluded the estimated fair value of our investment in Great Lakes exceeded its carrying value by more than ten percent.

2019 update

During the year ended December 31, 2019, Great Lakes’ current market conditions and other factors relevant to Great Lakes’ long-term financial performance have remained relatively stable. There is a risk that reductions in future cash flow forecasts or adverse changes in other key assumptions could result in an additional future impairment of the carrying value of our investment in Great Lakes.

TC PipeLines, LP Annual Report 2019 61

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Contingencies

Our pipeline systems’ accounting for contingencies covers a variety of business activities, including contingencies that could arise from legal and environmental liabilities. Our pipeline systems accrue for these contingencies when their assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with ASC 450 – Contingencies. Our pipeline systems base their estimates on currently available facts and their estimates of the ultimate outcome or resolution. Actual results may differ from our estimates or additional facts and circumstances cause us to revise our estimates resulting in an impact, positive or negative, on earnings and cash flow.

AtAs of December 31, ~~2019~~2020, ~~the~~our ~~Partnership~~equity isinvestees are not aware of any contingent liabilities that would have a material adverse effect on ~~the~~their ~~Partnership’s~~ financial condition, results ofor operations or cash flows.

At December 31, 2020, the Partnership is not aware of any contingent liabilities that would have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

RELATED PARTY TRANSACTIONS

Please read Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence” and Note 17 within Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more information regarding related party transactions.

Item 7A. 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 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 rate66 TC ~~risk.~~PipeLines, LP Annual Report 2020

LIBOR, which is set to be phased out at the end of 2021, is used as a reference rate for certain of our financial instruments, including the Partnership's term loans, revolving credit facilities and the interest rate swap agreements that we use to manage our interest rate exposure. We are reviewing how the LIBOR phase-out will affect the Partnership, but we currently do not expect the impact to be material.

As of December 31, 2019, 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 $112 million, or 6 percent, of our outstanding debt was subject to variability in LIBOR interest rates (December 31, 2018 - $168 million or 8 percent).

As of December 31, 2019, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 3.26 percent. If interest rates hypothetically increased (decreased) on these facilities by one percent (100 basis points), compared with rates in effect at December 31, 2019, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $1 million.

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AsMarket ofrisk ~~December~~is ~~31,~~the ~~2019,~~risk ~~$115~~that ~~million,~~changes in market interest rates may result in fluctuations in the fair values or 32cash ~~percent,~~flows of ~~Northern~~financial ~~Border’s~~instruments. ~~outstanding~~We ~~debt~~regularly ~~was~~assess atthe ~~floating~~impact ~~rates.~~of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

IfCertain ~~interest~~of ~~rates~~our ~~hypothetically~~financial ~~increased~~instruments ~~(decreased)~~and bycontractual ~~one~~obligations ~~percent~~with ~~(100~~variable ~~basis~~rate ~~points)~~components, ~~compared~~including ~~with~~the ~~rates~~Partnership’s interm ~~effect~~loans, atrevolving ~~December~~credit 31facilities and the interest rate swap agreements that we use to manage our interest rate exposure, ~~2019~~reference LIBOR, ~~Northern~~certain ~~Border’s~~terms ~~annual~~of ~~interest~~which ~~expense~~may ~~would~~cease ~~increase~~to ~~(decrease)~~be ~~and~~published ~~its~~at ~~net~~the ~~income~~end ~~would~~of ~~decrease~~2021 ~~(increase)~~with full cessation expected by ~~approximately~~mid-2023. $1We ~~million~~continue to monitor developments and are preparing to address any necessary system and contractual changes while assessing the adoption of the standard market-proposed reference rates. We currently do not expect the impact to be material.

~~GTN’s~~As ~~Unsecured~~of ~~Senior~~December ~~Notes~~31, ~~Northern~~2020, ~~Border~~the Partnership’s ~~and~~interest ~~Iroquois~~rate exposure resulted from our floating rate on North Baja’s ~~Senior~~unsecured ~~Notes~~term loan facility, ~~and~~PNGTS’ ~~all~~revolving ofcredit ~~Great~~facility ~~Lakes~~and Tuscarora’s ~~Notes~~unsecured ~~represent~~term ~~fixed-rate~~loan ~~debt; therefore~~facility, ~~they~~under ~~are~~which ~~not~~$98 ~~exposed~~million, toor ~~market~~4 ~~risk~~percent, ~~due~~of toour ~~floating~~outstanding ~~interest~~debt ~~rates.~~was ~~Interest~~subject ~~rate~~to ~~risk~~variability ~~does~~in ~~not~~LIBOR ~~apply~~interest torates ~~Bison~~(December 31, as2019 it- ~~currently~~$112 ~~does~~million ~~not~~or ~~have~~6 ~~any debt~~percent).

~~The~~As ~~Partnership~~of ~~and~~December ~~our~~31, ~~pipeline~~2020, ~~systems~~the ~~use~~variable ~~derivatives~~interest asrate ~~part~~exposure ofrelated to our ~~overall~~2013 ~~risk~~Term ~~management~~Loan ~~policy~~Facility towas ~~assist~~hedged inby ~~managing~~fixed ~~exposures~~interest torate ~~market~~swap ~~risk~~arrangements ~~resulting~~and ~~from~~our effective interest rate was 3.26 percent. If interest rates hypothetically increased (decreased) on these ~~activities~~facilities ~~within~~by ~~established~~one ~~policies~~percent ~~and~~(100 ~~procedures.~~basis ~~Derivative~~points), ~~contracts~~compared ~~used~~with torates ~~manage~~in ~~market~~effect ~~risk~~at ~~generally~~December ~~consist~~31, of2020, ~~the following:~~our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $1 million.

●As ~~Swaps~~of –December ~~contractual~~31, ~~agreements~~2020, ~~between~~$130 ~~two~~million, ~~parties~~or to34 ~~exchange~~percent, ~~streams~~ of ~~payments~~Northern ~~over~~Border’s ~~time~~outstanding ~~according~~debt towas ~~specified~~at ~~terms~~floating rates. If interest rates hypothetically increased (decreased) by one percent (100 basis points), compared with rates in effect at December 31, 2020, Northern Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately $1 million.

●Northern ~~Options~~Border’s –and ~~contractual~~Iroquois’ ~~agreements~~Senior toNotes, ~~convey~~all ~~the~~of ~~right,~~Great ~~but~~Lakes’ ~~not~~and ~~the~~GTN' ~~obligation~~s Notes, ~~for~~and the ~~purchaser~~PNGTS' toSeries ~~buy~~A orNotes, ~~sell~~represent afixed-rate ~~specific~~debt, ~~amount~~and ofare atherefore ~~financial~~not ~~instrument~~exposed atto amarket ~~fixed~~risk ~~price,~~due ~~either~~to atfloating ainterest ~~fixed~~rates. ~~date~~Interest orrate atrisk ~~any~~does ~~time~~not ~~within~~apply ato ~~specified~~Bison, ~~period~~as Bison does not have any debt.

The Partnership and our pipeline systems ~~enter~~use ~~into~~derivatives ~~interest~~as ~~rate~~part ~~swaps~~of ~~and~~our ~~option~~overall ~~agreements~~risk tomanagement ~~mitigate~~policy ~~the~~to ~~impact~~assist ~~of changes~~ in ~~interest~~managing ~~rates.~~exposures ~~For~~to ~~details~~market ~~regarding~~risk ~~our~~resulting ~~current~~from ~~interest~~these ~~swaps~~activities ~~and~~within ~~other~~established ~~agreements~~policies ~~related~~and toprocedures. ~~mitigation~~We ofdo ~~impact~~not onenter ~~changes~~into inderivatives ~~interest~~for ~~rates,~~speculative ~~see Note 20- Fair Value Measurements within Part IV, Item 15~~purposes. ~~“Exhibits~~Derivative ~~and~~contracts ~~Financial~~used ~~Statement~~to ~~Schedules,"~~manage ~~which~~market ~~information~~risk isgenerally ~~incorporated~~consist ~~herein~~of ~~by reference.~~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 19- Fair Value Measurements within Part IV, Item 15. “Exhibits and Financial Statement Schedules," 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 AND LIQUIDITY RISK

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

The Partnership has exposure to counterparty credit risk in ~~the~~a ~~following~~number of areas including:

● •cash and cash equivalents;

● •accounts receivable and other receivables; and

● •the fair value of derivative assets.

At December 31, ~~2019~~2020, we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired. Additionally, during year ended December 31, ~~2019~~2020 and at December 31, ~~2019~~2020, no customer accounted for more than 10 percent of our consolidated revenue and accounts receivable, respectively.

The Partnership and our pipeline systems have significant credit exposure to financial institutions as they hold cash deposits and provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy customers. The Partnership closely monitors the creditworthiness of our counterparties, including financial institutions, reviews accounts receivable regularly and, if needed, records allowances for doubtful accounts using the specific identification method. However, we cannot predict to what extent our business would be impacted by uncertainty in energy commodity prices, including possible declines in our customers' creditworthiness. Refer to Note 17 - Transactions with major customers within Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more information. See also Part I, Item 1. "Business Customers, Contracting and Demand” section for more information on certain customers.

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 balancesTC PipeLines, cash flow from operations and credit facilities to meet our operating, financing and capital expenditure obligations when due, under both normal and stressed conditions. Refer to "Liquidity and Capital Resources" section for more information about our liquidity. LP Annual Report 2020 67

TC PipeLines, LP Annual Report 2019 63

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AtThe ~~December~~Partnership ~~31,~~closely ~~2019,~~monitors the ~~Partnership~~creditworthiness ~~had~~of aour ~~Senior~~counterparties, ~~Credit~~including ~~Facility~~financial ofinstitutions, ~~$500~~reviews ~~million~~accounts ~~maturing~~receivable inregularly ~~2021~~and, ~~with~~if noneeded, ~~outstanding~~records ~~balance.~~allowances Atfor ~~December~~doubtful ~~31,~~accounts ~~2019,~~using ~~PNGTS~~the ~~has~~specific aidentification ~~$125~~method. ~~million~~However, ~~Revolving~~we ~~Credit~~are ~~Facility~~not ~~maturing~~able into ~~2023~~predict ~~and~~with ~~has~~certainty anthe ~~outstanding~~extent ~~balance~~to ofwhich ~~$39~~our ~~million~~business ~~and~~could ~~finally,~~be atimpacted ~~December~~by ~~31,~~the ~~2019,~~uncertainty ~~Northern~~surrounding ~~Border~~the ~~had~~COVID-19 apandemic ~~committed~~or ~~revolving~~the ~~bank~~prolonged ~~line~~impact of ~~$200~~low ~~million~~commodity ~~maturing~~prices, inincluding ~~2024~~possible ~~and~~declines ~~$115~~in ~~million~~our ~~was~~counterparties' ~~drawn~~creditworthiness. ~~The~~Refer ~~Partnership’s~~to ~~Senior~~Note ~~Credit~~16 ~~Facility,~~- ~~PNGTS’~~Transactions ~~Revolving~~with ~~Credit~~major ~~Facility~~customers ~~and~~within ~~the~~Part ~~Northern~~IV, ~~Border’s~~Item ~~Credit~~15. ~~Facility~~“Exhibits ~~have~~and ~~accordion~~Financial ~~features~~Statement Schedules” for ~~additional~~more ~~capacity~~information. ofSee ~~$500~~also ~~million~~Part I, ~~$50~~Item ~~million~~1. "Business Customers, Contracting and ~~$200~~Demand” ~~million~~section ~~respectively,~~for ~~subject~~more toinformation ~~lender~~on ~~consent~~certain customers.

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 - Accounting pronouncements within Part IV, Item 15. “Exhibits and Financial Statement Schedules”. The Partnership believes the factors as described above are considered to have a negligible impact considering the portfolio of counterparties in connection with our pipeline assets.

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they become due. We manage our liquidity risk by continuously forecasting our cash flow on a regular basis to ensure we have adequate cash balances, cash flow from operations and credit facilities to meet our operating, financing and capital expenditure obligations when due, under both normal and stressed conditions. Refer to "Liquidity and Capital Resources" section for more information about our liquidity.

At December 31, 2020, the Partnership had a Senior Credit Facility of $500 million maturing in 2021 with no outstanding balance. At December 31, 2020, PNGTS has a $125 million Revolving Credit Facility maturing in 2023 and has outstanding balance of $25 million and, finally, at December 31, 2020, Northern Border had a committed revolving bank line of $200 million maturing in 2024 and $130 million was drawn. The Partnership’s Senior Credit Facility, PNGTS' revolving credit facility and the Northern Border’s credit facility have accordion features for additional capacity of $500 million, $50 million and $200 million respectively, subject to lender consent.

Item 8. Financial Statements and Supplementary Data

The financial statements required by this item are included in Part IV, Item 15 of this report on page F-1 and are incorporated herein by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(e) under the 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 year covered by this annual 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 ~~Securities~~ Exchange Act ~~of 1934~~, ~~as amended (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 year ended December 31, ~~2019~~2020, there was no change in the Partnership’s internal control over financial reporting that materially impacted or is reasonably likely to materially impact our internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange Act. Internal control over financial reporting, no matter how well designed, has inherent limitations and can only provide reasonable assurance with respect to the preparation and fair presentation of published financial statements. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission.

~~Based on our assessment according to the above framework~~68 TC PipeLines, management has concluded that our internal control over financial reporting was effective as of December 31, 2019 at providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. No material weaknesses were identified. LP Annual Report 2020

Our independent registered public accounting firm, KPMG LLP (KPMG), independently assessed the effectiveness of the Partnership’s internal control over financial reporting. KPMG has issued an attestation report concurring with management’s assessment, which is included starting on page F-2 of the financial statements included in this Form 10-K.

64 TC PipeLines, LP Annual Report 2019

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our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on our assessment according to the above framework, management has concluded that our internal control over financial reporting was effective as of December 31, 2020 at providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. No material weaknesses were identified.

Item 9B. Other Information

None.

~~Part~~PART III

Item 10. Directors, Executive Officers and Corporate Governance

The Partnership is a limited partnership and as such has no officers, directors or employees. Set forth below is certain information concerning the directors and officers of the General Partner who manage the operations of the Partnership as of February 2024, ~~2020~~2021. Directors are appointed by the General Partner’s sole stockholder to serve one-year terms or until their successors are appointed. All officers of the General Partner serve at the discretion of the board of directors of the General Partner which is an indirect wholly-owned subsidiary of TC Energy.

Name	~~Age~~	~~Position with General Partner~~	Age	Position with General Partner
Stanley G. Chapman, III	54	~~Chair and Director~~	55	Chair and Director
Jack F. Stark	69	~~Independent Director~~	70	Independent Director
Malyn K. Malquist	67	~~Independent Director~~	68	Independent Director
Walentin (Val) Mirosh	74	Independent Director
Peggy A. Heeg			61	Independent Director
Nathaniel A. Brown	43	~~President, Principal Executive Officer and Director~~	44	President, Principal Executive Officer and Director
Nadine E. Berge	47	~~Director~~	48	Director
Sean M. Brett	54	Director
Gloria L. Hartl			48	Director
Janine M. Watson	50	~~Vice-President and General Manager~~	51	Vice-President and General Manager
Alisa Williams	36	~~Vice-President, Taxation~~	37	Vice-President, Taxation
Jon A. Dobson	53	~~Secretary~~	54	Secretary
Burton D. Cole	45	~~Controller~~	46	Controller
William C. Morris	57	~~Principal Financial Officer, Vice-President and Treasurer~~	58	Principal Financial Officer, Vice-President and Treasurer

Mr. Chapman has served as a director and Chair of the Board of Directors of the General Partner since January 1, 2019. Mr. Chapman’s principal occupation is Executive Vice-President and President, U.S. and Mexico Natural Gas Pipelines of TC Energy, where he has led the U.S. natural gas business since April 2017 and the Mexico natural gas business since September 2020. He is responsible for all pipeline operations and commercial activities across TC Energy's FERC-regulated transmission and storage assets as well as certain unregulated businesses. Mr. Chapman joined TC Energy as part of its acquisition of the Columbia Pipeline Group (Columbia) in July 2016 and served as Senior Vice President and General Manager of TC Energy’s FERC-regulated US natural gas pipeline business from July 2016 to April 2017. Prior to joining TC Energy, Mr. Chapman held several positions at Columbia from December 2011 to July 2016, most recently as Executive Vice-President and Chief Commercial Officer. Before joining Columbia, Mr. Chapman held various positions of increasing responsibility with El Paso Corp and Tenneco Energy and was responsible for various marketing and commercial operations, as well as supply, regulatory, business development and optimization activities. His industry knowledge, management experience and leadership skills are highly valuable in developing and implementing our business strategies and assessing accompanying risks.

Mr. Stark ~~Chapman~~ has served as a director and ~~Chair~~member of the ~~Board~~audit ofand ~~Directors~~conflicts committee of the ~~General~~board ~~Partner~~of ~~since~~directors ~~January 1, 2019. Mr. Chapman’s principal occupation is Executive Vice-President and President, U.S. Natural Gas Pipelines~~ of TCthe ~~Energy,~~General aPartner ~~position he has held~~ since ~~April 2017~~July 1999. ~~He is responsible for all pipeline operations and commercial activities across TC Energy's FERC-regulated transmission and storage assets.~~ Mr. Stark ~~Chapman~~currently ~~joined~~serves ~~TC Energy~~ as ~~part~~the ofChief ~~its~~Financial ~~acquisition~~Officer of ~~the~~Generate ~~Columbia~~Capital ~~Pipeline~~Inc., ~~Group~~a ~~(Columbia)~~clean inenergy ~~July~~financing ~~2016~~company. ~~and~~He previously served as ~~Senior~~Chief ~~Vice~~Financial ~~President~~Officer ~~and General Manager~~ of TCImergy ~~Energy’s~~Power ~~FERC-regulated~~Systems, USformerly ~~natural~~Deeya ~~gas pipeline business from July 2016 to April 2017. Prior to joining TC~~ Energy, ~~Mr.~~an ~~Chapman~~energy ~~held~~storage ~~several~~systems ~~positions~~company, ~~at Columbia~~ from December 2013 ~~2011~~ to July 2016,. ~~most~~Mr. Stark ~~recently~~was asthe ~~Executive Vice-President and~~ Chief ~~Commercial~~Financial Officer. ~~Before~~of ~~joining~~BrightSource ~~Columbia~~Energy Inc., ~~Mr.~~a ~~Chapman~~provider ~~held various positions~~ of ~~increasing~~technology ~~responsibility~~for ~~with~~use Elin ~~Paso~~large-scale ~~Corp~~solar ~~and~~thermal ~~Tenneco~~power ~~Energy~~plants, ~~and~~from ~~was~~May 2007 ~~responsible~~to ~~for~~November 2013 ~~various marketing~~ and ~~commercial~~Chief ~~operations,~~Financial asOfficer ~~well~~of asSilicon ~~supply,~~Valley ~~regulatory~~Bancshares, ~~business~~a ~~development~~diversified ~~and~~financial ~~optimization~~services ~~activities. His industry knowledge~~provider, ~~management~~from ~~experience~~April 2004 ~~and~~to ~~leadership~~May 2007. ~~skills~~Prior ~~are highly valuable in developing and implementing our business strategies and assessing accompanying risks.~~

~~Mr.~~TC Stark has served as a director and member of the audit and conflicts committee of the board of directors of the General Partner since July 1999. Mr. Stark currently serves as the Chief Financial Officer of Generate Capital Inc.PipeLines, ~~a clean energy financing company. He previously served as Chief Financial Officer of Imergy Power Systems, formerly Deeya Energy, an energy storage systems company, from December~~ ~~2013 to July~~LP ~~2016. Mr.~~Annual ~~Stark was the Chief Financial Officer of BrightSource Energy~~Report Inc., a provider of technology for use in large-scale solar thermal power plants, from May 2007 to November 2013 and Chief Financial Officer of Silicon Valley Bancshares, a diversified financial services provider, from April 2004 to May 2007. Prior to May 2007, Mr. Stark held chief financial officer positions at Itron Inc., Silicon Energy Corporation and GATX Capital as well as senior management roles at PG&E Corporation for more than 20 years. Mr. Stark previously served as a director, Chairman of the Board and member of the audit committee of the board of directors of Washington Gas Light Company, a regulated natural gas utility. He also serves on the board of directors of AltaGas Services (U.S.) Inc. (ASUS), a wholly-owned subsidiary of AltaGas Ltd., and AltaGas Utility Holdings (U.S.) Inc., a wholly owned subsidiary of ASUS. From November 2015 to October 2017, he served as a director of TerraForm Power, Inc. and TerraForm Global, Inc., where he also served on the compensation and audit committees of both companies. Through his roles as chief financial officer of numerous companies, Mr. Stark brings valuable financial expertise and management experience, including extensive knowledge regarding financial operations, investor relations, finance, energy risk management, regulatory affairs and knowledge of the natural gas industry. Mr. Stark’s prior audit committee experience further enhances his qualifications to serve as a member of our Board and our Audit Committee.2020 69

Mr. Malquist has served as a director, Chair of the audit committee and member of the conflicts committees of the board of directors of the General Partner since April 2011. Mr. Malquist is an executive with more than 30 years of experience

TC PipeLines, LP Annual Report 2019 65

Table of Contents

~~serving~~to inMay 2007, aMr. Stark ~~variety~~held ofchief ~~business,~~financial ~~operations~~officer ~~and~~positions ~~financial~~at ~~roles~~Itron Inc., ~~Mr.~~Silicon ~~Malquist~~Energy ~~served~~Corporation ~~on the board of directors~~ and ~~audit~~GATX ~~committee~~Capital ofas ~~Headwaters~~well ~~Incorporated~~as ~~(Headwaters),~~senior anmanagement ~~NYSE-listed~~roles ~~company~~at ~~that~~PG&E ~~provides~~Corporation ~~products,~~for ~~technologies~~more ~~and~~than ~~services~~20 years. inMr. Stark ~~the~~previously ~~light~~served ~~building~~as ~~products~~a director, ~~heavy~~Chairman ~~construction~~of ~~materials~~the Board and ~~energy~~member ~~industries,~~of ~~from~~the ~~January~~audit ~~2003~~committee toof ~~May~~the ~~2017,~~board ~~when~~of ~~Headwaters~~directors ~~was~~of ~~acquired~~Washington byGas ~~Boral~~Light Company, ~~Ltd.~~a ~~From~~regulated ~~September~~natural ~~2002~~gas toutility. ~~March~~He ~~2009,~~also ~~Mr.~~serves ~~Malquist~~on ~~held~~the ~~various~~board ~~senior~~of ~~executive~~directors ~~positions~~of ~~with~~AltaGas ~~Avista~~Services ~~Corporation~~(U.S.) Inc. (~~Avista~~ASUS), ana ~~energy~~wholly ~~production,~~owned ~~transmission~~subsidiary ~~and~~of ~~distribution company~~AltaGas Ltd., ~~including~~and ~~Senior~~AltaGas ~~Vice~~Utility ~~President~~Holdings ~~from September 2002 to May 2006~~(U.S.) Inc., ~~Executive~~a ~~Vice~~wholly ~~President~~owned ~~from~~subsidiary ~~May~~of ~~2006~~ASUS. toFrom ~~March 2009, Chief Financial Officer from~~ November 2015 ~~2002~~ to ~~September~~October 2017, ~~2008~~he ~~and~~served ~~Treasurer~~as ~~from~~a ~~February~~director ~~2004~~of ~~to January 2006~~TerraForm Power, Inc. ~~Prior~~and ~~to his employment at Avista~~TerraForm Global, Mr Inc. ~~Malquist held various positions at Sierra Pacific Resources~~, ~~(electricity~~where ~~provider),~~he ~~including~~also ~~President,~~served ~~Chief~~on ~~Executive~~the ~~Officer~~compensation and ~~Chief~~audit ~~Operating~~committees ~~Officer~~of ~~from~~both ~~January 1998 to April 2000 and various Senior Vice-President positions from 1994 to 1998~~companies. Through his ~~extensive~~roles ~~prior management experience, including serving~~ as chief financial officer ~~and chief executive officer~~ of ~~various~~numerous ~~energy~~ companies, Mr. Stark ~~Malquist~~ brings ~~extensive~~valuable ~~knowledge regarding~~ financial ~~operations,~~expertise ~~energy~~and ~~risk~~ management ~~and~~experience, ~~knowledge~~including ofextensive ~~the~~knowledge ~~energy~~regarding ~~industry~~financial tooperations, ~~the~~investor ~~Board~~relations, offinance, ~~Directors~~energy ~~and~~risk ~~the~~management, ~~Audit~~regulatory ~~Committee.~~affairs ~~His valuable management~~ and ~~financial~~knowledge ~~expertise include an understanding~~ of the ~~accounting~~natural ~~and~~gas ~~financial matters that the Partnership and~~ industry ~~address on a regular basis~~. ~~In addition,~~ Mr. ~~Malquist~~ Stark’s ~~experience~~prior inaudit ~~the~~committee ~~energy~~experience ~~industry~~further isenhances ~~beneficial~~his qualifications to ~~the~~serve ~~service~~as hea ~~provides~~member toof ~~the~~our Board ofand ~~Directors.~~our Audit Committee.

Mr. ~~Mirosh~~Malquist has served as a director, ~~and~~Chair ~~member~~ of the audit committee and member of the conflicts committees of the board of directors of the General Partner since ~~September~~April ~~2004~~2011. Mr. ~~Mirosh’s~~Malquist ~~principal~~is ~~occupation~~an isexecutive ~~President~~with ofmore ~~Mircan~~than ~~Resources~~30 ~~Ltd.,~~years ~~(private~~of ~~consulting~~experience ~~company),~~serving in a ~~position~~variety heof ~~has~~business, ~~held~~operations ~~since~~and ~~2009~~financial roles. ~~From~~Mr. ~~April~~Malquist ~~2008~~served toon ~~December~~the ~~2009,~~board heof ~~was~~directors ~~Vice~~and audit committee of Headwaters Incorporated (Headwaters), an NYSE-~~President~~listed ~~and~~company ~~Special~~that ~~Advisor~~provides toproducts, technologies and services in the ~~President~~light building products, heavy construction materials and ~~Chief~~energy ~~Operating~~industries, ~~Officer~~from ofJanuary ~~NOVA~~2003 ~~Chemicals~~to ~~Corporation~~May ~~(NOVA)~~2017, awhen ~~commodity~~Headwaters ~~chemicals~~was ~~and~~acquired ~~plastics~~by ~~company~~Boral, Ltd. From ~~July~~September ~~2003~~2002 to ~~April~~March ~~2008~~2009, Mr. ~~Mirosh~~Malquist ~~was~~held ~~President~~various ofsenior ~~Olefins~~executive positions with Avista Corporation (Avista), an energy production, transmission and ~~Feedstocks~~distribution company, aincluding ~~division~~Senior ofVice ~~NOVA.~~President ~~Prior~~from September 2002 to ~~joining~~May ~~NOVA~~2006, ~~Mr.~~Executive ~~Mirosh~~Vice ~~was~~President afrom ~~partner~~May at2006 ~~Macleod~~to ~~Dixon~~March ~~law~~2009, ~~firm. Mr.~~Chief ~~Mirosh~~Financial isOfficer ~~also~~from aNovember ~~director~~2002 ofto ~~Murphy~~September ~~Oil~~2008 ~~Corporation~~and ~~(an~~Treasurer ~~international~~from ~~oil~~February ~~and~~2004 ~~gas~~to ~~company)~~January 2006. Prior to his employment at Avista, Mr. ~~Mirosh’s~~Malquist ~~extensive~~held ~~experience~~various inpositions ~~the~~at ~~natural~~Sierra ~~gas~~Pacific ~~transmission~~Resources, ~~sector~~(electricity ~~enhances~~provider), ~~the~~including ~~knowledge~~President, ofChief ~~the~~Executive ~~Board~~Officer inand ~~this~~Chief ~~area~~Operating ofOfficer ~~the~~from ~~industry.~~January As1998 ato ~~current~~April 2000 and ~~former~~various ~~executive~~Senior ~~and~~Vice-President ~~director~~positions offrom ~~various~~1994 ~~companies,~~to 1998. Through his ~~breadth~~extensive ofprior management experience, isincluding ~~applicable~~serving toas ~~many~~chief offinancial ~~the~~officer ~~matters~~and ~~routinely~~chief ~~facing~~executive ~~the~~officer ~~Partnership.~~of ~~Moreover~~various energy companies, Mr. ~~Mirosh’s~~Malquist ~~experience~~brings ~~and~~extensive ~~industry~~ knowledge ~~are~~regarding ~~complemented~~financial byoperations, anenergy ~~engineering~~risk ~~educational~~management ~~background~~ and ~~legal~~knowledge ~~experience,~~of ~~are~~the ~~beneficial~~energy industry to the Board of Directors and the Audit Committee. onHis avaluable ~~full~~management ~~range~~and financial expertise include an understanding of ~~business,~~the accounting and financial, ~~technical~~matters that the Partnership and ~~professional~~industry ~~matters~~address on a regular basis. In addition, Mr. Malquist’s experience in the energy industry is beneficial to the service he provides to the Board of Directors.

MrMs. ~~Brown~~Heeg ~~has~~was ~~served~~appointed as ~~President,~~a ~~Principal~~director ~~Executive~~and ~~Officer~~member of the audit and aconflicts ~~director~~committee of the board of directors of the General Partner ~~since~~on ~~May~~September 115, ~~2018. He~~2020 ~~previously~~to ~~served~~fill asthe ~~Controller~~vacancy ~~and~~created ~~Principal~~by ~~Financial~~the ~~Officer~~retirement of Walentin Mirosh from the ~~General~~TC ~~Partner~~PipeLines ~~from~~Board ~~May~~in ~~2014~~August to2020. ~~May~~Ms. ~~2018~~Heeg has over 30 years of experience in the energy and legal industries and government service. ~~His~~From ~~principal~~November ~~occupation~~2017 isto ~~Vice-President~~January 2021, UMs.S. ~~Natural~~Heeg ~~Gas~~was ~~Pipelines~~a ~~Financial~~partner ~~Services~~with, and member of ~~TransCanada~~the ~~USA~~Executive ~~Services~~Committee ~~Inc.~~of, Reed Smith LLP, an ~~indirect~~international ~~wholly~~law ~~owned~~firm ~~subsidiary~~with approximately 2,000 lawyers, providing strategic advice on a broad range of TCenergy, ~~Energy~~complex ~~(“TC~~governance, ~~USA”)~~regulatory and business matters. From January 2004 to October 2017, she was a ~~position~~partner hewith ~~has~~Norton ~~held~~Rose ~~since~~Fulbright ~~February~~US ~~2018.~~LLP, Ina ~~this~~3,800-attorney ~~position~~international law firm, hepracticing isenergy ~~responsible~~and ~~for~~corporate governance law and serving on the ~~accounting~~firm’s Executive Committee. Before joining Norton Rose, ~~financial~~Ms. ~~reporting~~Heeg held several leadership roles at El Paso Corporation, ~~planning~~most recently as Executive Vice President and ~~budgeting~~General ofCounsel TCas well as a legal advisor to the Federal Energy’s URegulatory Commission.S Ms. Heeg currently serves on the Board of WhiteWater Midstream, LLC, a private natural gas ~~pipelines.~~transmission Mrcompany. ~~Brown~~She ~~also~~previously served as ~~Director~~an independent director on the Boards of ~~Financial~~Directors ~~Services~~of ~~for~~Eagle TCRock Energy’s ~~U.S.~~Partners, ~~Pipelines~~where ~~from~~she ~~May~~chaired ~~2014~~the toNomination ~~February~~and ~~2018~~Governance Committee and ~~Manager~~served ofon ~~Accounting~~the ~~for~~Audit TCand ~~Energy’s~~Conflicts UCommittees, and Columbia Pipeline Partners LP, where she served on the Audit and Conflicts Committees.S Ms. ~~Pipelines~~Heeg ~~West~~also ~~from~~previously ~~November~~served ~~2009~~as toa ~~May~~director ~~2014.~~of ~~Prior~~El toPaso ~~joining~~Tennessee TCPipeline ~~Energy~~Company and as a commissioner on the Texas Lottery Commission, Mrwhere she provided strategic, financial, risk and regulatory oversight of the agency. ~~Brown~~Ms. ~~spent~~Heeg ~~eight~~obtained ~~years~~a inBachelor ~~public~~of ~~accounting,~~Arts ~~most~~degree ~~recently~~and asJuris anDoctorate ~~audit~~from ~~manager~~the ~~for~~University ~~Grant~~of ~~Thornton~~Louisville. ~~LLP~~She is a member of the State Bar of Texas, the American Bar Association and ~~Ernst~~the &Energy ~~Young~~Bar Association.

Mr. Brown has served as President, Principal Executive Officer and a director of the General Partner since May 1, 2018. He previously served as Controller and Principal Financial Officer of the General Partner from May 2014 to May 2018. His principal occupation is Vice-President, U.S. Natural Gas Pipelines Financial Services of TransCanada USA Services Inc., an indirect wholly owned subsidiary of TC Energy (TC USA), a position he has held since February 2018. In this position, he is responsible for the accounting, financial reporting, planning and budgeting of TC Energy’s U.S. natural gas pipelines. Mr. Brown also served as Director of Financial Services for TC Energy’s U.S. Pipelines from May 2014 to February 2018 and Manager of Accounting for TC Energy’s U.S. Pipelines West from November 2009 to May 2014. Prior to joining TC Energy, Mr. Brown spent eight years in public accounting, most recently as an audit manager for Grant Thornton LLP and Ernst & Young.

Ms. Berge has been a director of the General Partner since May 2018. Ms. Berge's principal occupation is Director, Corporate Compliance and Legal Operations with TC Energy, a position she has held since December 2014. Ms. Berge has served in several positions of increasing responsibility in the legal department since joining TC Energy in May 2005. Ms. Berge is responsible for directing the corporate compliance area across Canada, the US and Mexico, as well as leadership of operational matters for the TC Energy legal department in all three jurisdictions. Prior to joining TC Energy, Ms. Berge spent five years practicing law in the area of energy regulation. Ms. Berge brings valuable legal skills and experience to the Board of Directors.

MrMs. ~~Brett~~Hartl, ~~has~~was ~~served~~appointed asto ~~a director of~~ the ~~General~~TC ~~Partner~~PipeLines ~~since~~Board ~~May~~on ~~2018.~~November ~~Mr.~~9, ~~Brett's principal occupation is Senior Vice-President~~2020, ~~Power~~to ~~and~~fill ~~Storage~~the ~~with~~vacancy TCcreated ~~Energy,~~by athe ~~role~~retirement heof ~~has~~Sean ~~held~~Brett ~~since~~from ~~January~~the ~~2019~~Board ~~and~~ in ~~which~~August he2020. isMs. ~~responsible for all aspects of TC Energy’~~Hartl's ~~Power~~principal ~~and~~occupation ~~Storage~~is ~~business~~Vice-President, ~~including~~Risk ~~strategy,~~Management ~~commercial,~~of ~~business development, projects and operations. Mr. Brett joined~~ TC Energy, ina ~~March~~position ~~1997~~she ~~and~~has held ~~several~~since ~~positions~~February of2019. ~~increasing~~In ~~responsibility~~her ~~prior to his~~ current ~~role~~position, ~~including~~Ms. ~~Vice-President,~~Hartl ~~Power~~is ~~and~~responsible ~~Storage~~for ~~from~~oversight ~~June~~of ~~2018~~risk ~~to January 2019~~management, ~~Vice-President,~~

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