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sCanadaCorporationAndSubsidiariesExcludingGeneralPartnerSubsidiariesMembertcp:TransportationContractsRelatedPartyMembertcp:GreatLakesGasTransmissionLimitedPartnershipMember2020-01-012020-12-310001075607tcp:TransCanadaCorporationAndSubsidiariesExcludingGeneralPartnerSubsidiariesMembertcp:TransportationContractsRelatedPartyMembertcp:GreatLakesGasTransmissionLimitedPartnershipMember2019-01-012019-12-310001075607tcp:TransCanadaCorporationAndSubsidiariesExcludingGeneralPartnerSubsidiariesMembertcp:TransportationContractsRelatedPartyMembertcp:GreatLakesGasTransmissionLimitedPartnershipMember2018-01-012018-12-310001075607tcp:AnrPipelineCompanyMembertcp:TransportationContractsRelatedPartyMembertcp:GreatLakesGasTransmissionLimitedPartnershipMember2018-12-310001075607tcp:AnrPipelineCompanyMembertcp:TransportationContractsRelatedPartyMembertcp:GreatLakesGasTransmissionLimitedPartnershipMember2018-01-012018-12-310001075607tcp:AnrPipelineCompanyMembertcp:TransportationContractsRelatedPartyMembertcp:GreatLakesGasTransmissionLimitedPartnershipMember2020-03-31utr:MMBTUutr:D0001075607tcp:AnrPipelineCompanyMembertcp:TransportationContractsRelatedPartyMembertcp:GreatLakesGasTransmissionLimitedPartnershipMember2020-12-310001075607tcp:AnrPipelineCompanyMembertcp:TransportationContractsRelatedPartyMembertcp:GreatLakesGasTransmissionLimitedPartnershipMember2020-01-012020-12-310001075607tcp:NorthernBorderPipelineCompanyMembertcp:TransportationContractsRelatedPartyMembersrt:AffiliatedEntityMember2020-01-012020-12-310001075607tcp:NorthernBorderPipelineCompanyMembertcp:TransportationContractsRelatedPartyMembersrt:AffiliatedEntityMember2018-01-012018-12-310001075607tcp:NorthernBorderPipelineCompanyMembertcp:TransportationContractsRelatedPartyMembersrt:AffiliatedEntityMember2019-01-012019-12-310001075607tcp:NorthernBorderPipelineCompanyMembertcp:TransportationContractsRelatedPartyMembersrt:AffiliatedEntityMember2019-12-310001075607tcp:NorthernBorderPipelineCompanyMembertcp:TransportationContractsRelatedPartyMembersrt:AffiliatedEntityMember2020-12-310001075607tcp:TransCanadaCorporationSubsidiariesMembertcp:PortlandNaturalGasTransmissionSystemMembertcp:TransportationContractsRelatedPartyMember2019-01-012019-12-310001075607tcp:TransCanadaCorporationSubsidiariesMembertcp:PortlandNaturalGasTransmissionSystemMembertcp:TransportationContractsRelatedPartyMember2018-01-012018-12-310001075607tcp:TransCanadaCorporationSubsidiariesMembertcp:PortlandNaturalGasTransmissionSystemMembertcp:TransportationContractsRelatedPartyMember2019-12-310001075607tcp:TransCanadaCorporationSubsidiariesMembertcp:PortlandNaturalGasTransmissionSystemMembertcp:TransportationContractsRelatedPartyMember2020-12-310001075607tcp:PortlandXpressExpansionProjectPhaseThreeMembertcp:PortlandNaturalGasTransmissionSystemMembersrt:AffiliatedEntityMember2020-01-012020-12-310001075607tcp:AnrPipelineCompanyMemberus-gaap:TechnologyBasedIntangibleAssetsMember2020-08-012020-08-010001075607tcp:AnrPipelineCompanyMembertcp:TCPipelinesLpMemberus-gaap:TechnologyBasedIntangibleAssetsMember2020-08-012020-08-0100010756072020-01-012020-03-3100010756072020-04-012020-06-3000010756072020-07-012020-09-3000010756072020-10-012020-12-310001075607tcp:LimitedPartnerCommonUnitMember2020-01-012020-03-310001075607tcp:LimitedPartnerCommonUnitMember2020-04-012020-06-300001075607tcp:LimitedPartnerCommonUnitMember2020-07-012020-09-300001075607tcp:LimitedPartnerCommonUnitMember2020-10-012020-12-310001075607tcp:LimitedPartnerClassBUnitMember2020-01-012020-03-310001075607tcp:LimitedPartnerClassBUnitMember2020-04-012020-06-300001075607tcp:LimitedPartnerClassBUnitMember2020-07-012020-09-300001075607tcp:LimitedPartnerClassBUnitMember2020-10-012020-12-3100010756072019-01-012019-03-3100010756072019-04-012019-06-3000010756072019-07-012019-09-3000010756072019-10-012019-12-310001075607tcp:LimitedPartnerCommonUnitMember2019-01-012019-03-310001075607tcp:LimitedPartnerCommonUnitMember2019-04-012019-06-300001075607tcp:LimitedPartnerCommonUnitMember2019-07-012019-09-300001075607tcp:LimitedPartnerCommonUnitMember2019-10-012019-12-310001075607tcp:LimitedPartnerClassBUnitMember2019-01-012019-03-310001075607tcp:LimitedPartnerClassBUnitMember2019-04-012019-06-300001075607tcp:LimitedPartnerClassBUnitMember2019-07-012019-09-300001075607tcp:LimitedPartnerClassBUnitMember2019-10-012019-12-310001075607tcp:TCPipelinesLpMember2020-01-012020-12-310001075607us-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel2Member2020-12-310001075607us-gaap:EstimateOfFairValueFairValueDisclosureMemberus-gaap:FairValueInputsLevel2Member2019-12-310001075607us-gaap:InterestRateSwapMembertcp:TermLoanDueOctober2022Memberus-gaap:NotesPayableToBanksMember2020-12-310001075607us-gaap:InterestRateSwapMemberus-gaap:FairValueInputsLevel2Memberus-gaap:CashFlowHedgingMemberus-gaap:FairValueMeasurementsRecurringMember2020-12-310001075607us-gaap:InterestRateSwapMemberus-gaap:FairValueInputsLevel2Memberus-gaap:CashFlowHedgingMemberus-gaap:FairVal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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
For the fiscal year ended December 31, 2020
or
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)
Delaware52-2135448
State or other jurisdiction
of incorporation or organization
(I.R.S. Employer
Identification No.)
700 Louisiana StreetSuite 70077002-2761
Houston,Texas(Zip code)
(Address of principal executive offices)
877-290-2772
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each ClassTrading SymbolName of each exchange on which registered
Common units representing limited partner interestsTCPNYSE
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
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 x 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 FilerxAccelerated 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. ¨

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the 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, 2020 was approximately $ 2.2 billion.
As of February 19, 2021, there were 71,306,396 common units of the registrant outstanding.


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DOCUMENTS INCORPORATED BY REFERENCE
None


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TC PIPELINES, LP
TABLE OF CONTENTS
Page No.
All amounts are stated in United States dollars unless otherwise indicated.
TC PipeLines, LP Annual Report 2020     3

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DEFINITIONS
The abbreviations, acronyms, and industry terminology used in this annual report are defined as follows:
2013 Term Loan FacilityTC PipeLines, LP’s $500 million term loan credit facility under a term loan agreement as amended on September 29, 2017
2015 Term Loan FacilityTC PipeLines, LP’s $170 million term loan credit facility under a term loan agreement as amended on September 29, 2017
2017 AcquisitionPartnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017
2017 Great Lakes SettlementStipulation and Agreement of Settlement for Great Lakes regarding its rates and terms and conditions of service approved by FERC on February 22, 2018
2017 Northern Border SettlementStipulation 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 ActPublic Law No. 115-97, commonly known as the Tax Cuts and Jobs Act, enacted on December 22, 2017
2018 FERC ActionsFERC’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 SettlementStipulation and Agreement of Settlement for GTN regarding its rates and terms and conditions of service approved by FERC on November 30, 2018
2019 Iroquois SettlementAn 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 SettlementAn 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
ADITAccumulated 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
AFUDCAllowance for funds used during construction
ANRANR Pipeline Company
ASCAccounting Standards Codification
ATM programAt-the-market Equity Issuance Program
BIABureau of Indian Affairs
BisonBison Pipeline LLC
C2C ContractsPNGTS’ Continent-to-Coast Contracts with several shippers for a term of 15 years for approximately 82,000 Dth/day
Canadian MainlineTC Energy’s Mainline, a natural gas transmission system extending from the Alberta/Saskatchewan border east to Quebec
Certificate Policy Statement NOIFERC Notice of Inquiry issued on April 19, 2018
Class B DistributionAnnual distribution to TC Energy based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter
Class B ReductionApproximately 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 SubsidiariesGTN, Bison, North Baja, Tuscarora and PNGTS
4     TC PipeLines, LP Annual Report 2020

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COVID-19Coronavirus 2019
Delaware ActDelaware Revised Uniform Limited Partnership Act
DOTU.S. Department of Transportation
DSUsDeferred Share Units
Dth/dayDekatherms per day
EBITDAEarnings Before Interest, Tax, Depreciation and Amortization
EPAU.S. Environmental Protection Agency
ExC ProjectIroquois 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
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
GAAPU.S. generally accepted accounting principles
General PartnerTC PipeLines GP, Inc.
GHGGreenhouse Gas
Great LakesGreat Lakes Gas Transmission Limited Partnership
GTNGas Transmission Northwest LLC
GTN XPressGTN'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.
HCAsHigh consequence areas
IDRsIncentive Distribution Rights
IroquoisIroquois Gas Transmission System, L.P.
IRSInternal Revenue Service
Joint FacilitiesPipeline facilities jointly owned with MNE on PNGTS
KPMGKPMG LLP
LDCsLocal Distribution Companies
LIBORLondon Interbank Offered Rate
LNGLiquefied Natural Gas
MLPsMaster limited partnerships
MNEMaritimes and Northeast Pipeline LLC, a subsidiary of Enbridge Inc.
MNOCM&N Operating Company, LLC, a wholly owned subsidiary of MNE
Moody's Moody's Investors Service
NGANatural Gas Act of 1938
North BajaNorth Baja Pipeline, LLC
North Baja XPressNorth Baja project to transport additional volumes of natural gas of approximately 495,000 Dth/day between Ehrenberg, Arizona and Ogilby, California
Northern BorderNorthern Border Pipeline Company
NYSENew York Stock Exchange
Our pipeline systemsOur ownership interests in GTN, Northern Border, Bison, Great Lakes, North Baja, Tuscarora, PNGTS and Iroquois
PartnershipTC PipeLines, LP, including its subsidiaries, as applicable
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Partnership AgreementFourth Amended and Restated Agreement of Limited Partnership of the Partnership
PHMSAU.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration
PNGTSPortland Natural Gas Transmission System
PXPPortland 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 StatementFERC's Revised Policy Statement on Treatment of Income Taxes
ROEReturn on equity
SECSecurities and Exchange Commission
Securities ActSecurities Act of 1933, as amended
Senior Credit FacilityTC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated September 29, 2017
S&PStandard & Poor's
TC EnergyTC Energy Corporation, formerly known as TransCanada Corporation
TC Energy Merger AgreementTC 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.
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.
TQMTransQuebec and Maritimes Pipeline
TuscaroraTuscarora Gas Transmission Company
Tuscarora XPressTuscarora'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
Unaffiliated TCP UnitholdersHolders of the outstanding Partnership common units, other than TC Energy and its affiliates
U.S.United States of America
WCSBWestern Canadian Sedimentary Basin
Westbrook XPressWestbrook XPress Project of PNGTS that is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility
Wholly owned subsidiariesGTN, Bison, North Baja, and Tuscarora
WHOWorld Health Organization
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).
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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, 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 refusal or inability of our customers, shippers or counterparties to perform their contractual obligations with us, whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors;
the outcome and frequency of rate proceedings or settlement negotiations on our pipeline systems;
other potential changes in the taxation of master limited partnership (MLP) investments by state or federal governments such as 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 conflicts of interest between TC PipeLines GP, Inc., our general partner (General Partner), TC Energy Corporation (TC Energy) and us;
failure of the Partnership or our pipeline systems to comply with debt covenants, some of which are beyond our control;
the ability to maintain secure operation of our information technology including management of cybersecurity threats, acts of terrorism and related distractions;
the implementation of future accounting changes and ultimate outcome of commitments and contingent liabilities (if any);
the impact of any impairment charges;
changes in the political environment;
operating hazards, casualty losses and other matters beyond our control;
the overall increase in the allocated management and operational expenses to our pipeline systems for services performed by TC Energy; 
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ability of our pipeline systems to renew rights-of-way at a reasonable cost;
the level of our indebtedness (including the indebtedness of our pipeline systems), increases in interest rates, our level of operating cash flows and the availability of capital;
the impact of a potential slowdown in construction activities or a delay in the completion of our capital projects including increases in costs and availability of labor, equipment and materials;
the impact of 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, 2020, subsidiaries of TC Energy 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:
PNGTS’ Portland XPress 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 incremental compression within PNGTS’ existing footprint in Maine. PXP was designed to be phased in over a three-year time period. Phases I and II were placed into service 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 generate approximately $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.
Additionally, in connection with PXP, PNGTS entered into an arrangement with TC Energy regarding the construction of certain facilities on the TC Energy system (TransQuebec and Maritimes Pipeline (TQM) and TC Energy’s Canadian Mainline natural gas transmission system (Canadian Mainline)) that were required to fulfill PXP contracts on the PNGTS system. In the event the Canadian system expansions had terminated prior to their in-service dates, PNGTS could have been required to reimburse TC Energy for an amount up to the total outstanding costs incurred to the date of the termination. As a result of placing the TC Energy facilities associated with the Phases I, II and III volumes in service, PNGTS' reimbursement obligation to TC Energy relating to this project has been extinguished.
PNGTS' Westbrook XPress Project (Westbrook XPress) - Westbrook XPress is an estimated $125 million multi-phase expansion project that is expected to generate approximately $35 million in revenue for PNGTS on an annualized basis when fully in service. It is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin (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. On June 18, 2020, FERC issued a certificate of public convenience and necessity for Phases II and III for this project. On January 9, 2021, construction crews and equipment were mobilized to the existing Westbrook Compressor Station following the authorization received from FERC by PNGTS on January 6, 2021. Phases II and III have estimated in-service dates of November 2021 and 2022, respectively. These three Phases will add incremental capacity of approximately 43,000 Dth/day, 69,000 Dth/day, and 18,000 Dth/day, respectively. Westbrook XPress, together with PXP, will increase PNGTS’ capacity by 90 percent from 210,000 Dth/day to approximately 400,000 Dth/day. The Westbrook XPress contracts expire between 2036 and 2042.
Iroquois Gas Transmission ExC Project - In 2019, 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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project’s total design capacity is approximately 125,000 Dth/day with an estimated cost of $250 million and in-service date of November 2023. This project will be 100 percent underpinned with 20-year contracts.

North Baja XPress Project (North Baja XPress) - North Baja XPress is an estimated $90 million project to transport additional volumes of natural gas along North Baja’s mainline system. The project was initiated in response to market demand to provide firm transportation service of 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. On September 8, 2020, FERC issued its Environmental Assessment (EA) for the North Baja 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. North Baja XPress was subject to a Final Investment Decision (FID) by Sempra LNG International, LLC, (Sempra LNG) regarding the development, construction and operation of a Liquified Natural Gas (LNG) terminal in Baja California, Mexico and on November 17, 2020, Sempra LNG reached a positive FID on the project. North Baja XPress has an estimated in-service date of February 2023 and is still subject to regulatory approvals and other requirements of the project.

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

GTN XPress Project – In March 2020, GTN filed applications with FERC to authorize the replacement of certain facilities on the GTN system. Once in service, the replacements will increase the reliability of existing transportation service including 100,000 Dth/day of existing, long-term, full-haul system capacity. In 2021, GTN will file an application with FERC for the installation of an additional compressor at a brownfield compressor site and other related work. Once in service, this work will increase GTN's long-term system capacity by an incremental 150,000 Dth/day. The estimated total project cost of this integrated reliability and expansion project is $335 million. The project’s reliability work is anticipated to be in service by the end of 2021 and will account for more than three quarters of the total project cost. These costs are expected to be recovered in recourse rates. The project’s expansion work is anticipated to be commercially phased into service through November 2023. GTN XPress’ expansion work is 100 percent underpinned by fixed rate negotiated contracts with an average term in excess of 30 years. The incremental capacity is expected to generate approximately $25 million in revenue annually when fully in service.
Laws and 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 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 July 16, 2020, the Council on Environmental Quality (CEQ), under former President Trump's administration, published a final rule modifying the National Environmental Policy Act (NEPA). The modified final rule establishes a time limit of two years for preparation of environmental impact statements and one year for the preparation of environmental assessments. The modified rule also eliminates the responsibility to consider cumulative effects of a project. The final rule is being widely criticized by environmental and conservation groups and is facing court challenges. The Partnership sees these updates as positive for the industry, as CEQ streamlines the review process. However, the updated rules may be delayed due to congressional review or litigation or President Biden's Administration may direct CEQ to reconsider or withdraw the rule.
FERC's Instant Final Rule – The Natural Gas Act (NGA) allows intervening parties to file requests for rehearing with FERC within thirty days after FERC issues an order granting a certificate of public convenience and necessity and 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
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time. This prevented the requester from being able to appeal the certificate to the courts, while FERC continued to grant notices to proceed with construction (NTPs) with the requests for rehearing still pending.

Intervening parties recently challenged the tolling order practice in court. Prior to the court’s decision, on June 9, 2020, FERC issued an Instant Final Rule (IFR) prohibiting it from issuing NTPs while rehearing requests are pending. On June 30, 2020, the D.C. Circuit Court of Appeals issued an opinion prohibiting FERC from utilizing tolling orders without any substantive ruling.
The IFR and the D.C. Circuit Opinion together cause concern that potential delays may occur in the certification process given that FERC will need to issue decisions on rehearing requests in a much shorter timeframe.

The Partnership believes that under the current framework, these issuances will likely have a small impact on our pending and future projects, if any at all. Many of our projects in execution are largely compression-based and involve little-to-no greenfield construction, which have tended to be less likely to draw a rehearing request. However, certain avenues still exist for FERC to extend the time period longer, FERC continues to retain discretion over when to issue a notice to proceed, and the current framework may be modified by legislation (some of which has already been proposed) or a potential further appeal to the United States Supreme Court, therefore we cannot know the impact of FERC's IFR with certainty at this time.

Environmental (Water) 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.

Additionally, the CWA Section 404 NWP Program has been under increased national scrutiny since April 15, 2020, when a Montana federal District Court ruled against TC Energy’s use of an allegedly invalid NWP 12 for the performance of construction activities affecting WOTUS in Montana for its Keystone XL oil pipeline project (the Presidential Permit for which was revoked on January 20, 2021 by executive order of President 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, the ensuing appeal of the ruling to higher courts, and subsequent lawsuits against other pipeline projects’ use of NWP 12 on similar grounds, have created a great deal of uncertainty around the continued use of NWP 12 for projects. Additionally, 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 uncertainty surrounding the use of NWP 12. The final rule, which reissued 12 existing NWPs, 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. 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 USACE may materially affect the Partnership’s business, particularly with the arrival of 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
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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

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

The prearranged contracts range in volume from 40,000 to 269,732 Dth/day for terms ranging from 10 months to 10 years, two of which began on June 1, 2020. Northern Border filed a motion to consolidate the two complaint dockets and filed its response to the complaints on May 1, 2020. On June 1,2020, updated tariff sheets reflecting the contract price were filed by Northern Border with FERC for the two contracts set to begin June 1, 2020. On July 1, 2020, FERC issued an order and accepted the tariff sheets, subject to the outcome of complaint proceedings.

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On October 15, 2020, FERC issued an order on the complaints and directed Northern Border to (1) refrain from making similar, discriminatory awards of capacity in the future, (2) rescind the pre-arranged deals with ONEOK Midstream, effective October 15, 2020, and (3) hold a new open season without a pre-arranged shipper. In addition, FERC directed Northern Border to file revisions to its tariff requiring it to post capacity on its website before entering a pre-arranged deal. FERC did not order Northern Border to refund any of the revenue earned from the pre-arranged transactions with ONEOK Midstream.

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

Great Lakes 501-G Proceeding - On May 11, 2020, FERC terminated Great Lakes’ 501-G proceeding and ruled that Great Lakes 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.

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

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

Great Lakes' Contract with TC Energy's Canadian Mainline - As noted in our 2019 Annual Report 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 upgradeOn 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.
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.

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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.
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 11.3 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 Maritimes and Northeast Pipeline LLC (MNE) on PNGTS (Joint Facilities), are operated 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:
PipelineLengthDescriptionOwnership
GTN1,377 milesExtends 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
Bison303 milesExtends 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
North Baja86 milesExtends 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
Tuscarora305 milesExtends 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 Border1,412 milesExtends 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
PNGTS295 milesConnects 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 Lakes2,115 milesConnects 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
Iroquois416 milesExtends 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
The map below shows the location of our pipeline systems.
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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
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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, including natural gas producers, LDCs, marketers and end users, to ensure our pipelines are offering attractive services and competitive rates. Approximately 74 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 Part I, Item 1A. “Risk Factors.”
Transactions with our major customers that are at least 10 percent of our consolidated revenues can be found under Note 16-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 17-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 portion of GTN's 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.
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 of natural gas per day on the Great Lakes system. This contract 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.

In early 2020, TC Energy approved the Alberta XPress Project, an expansion project on its ANR Pipeline system with an estimated in-service date of 2022. This project utilizes existing aggregate capacity on Great Lakes System of approximately 168,000 Dth/day for a term of 20 years at maximum rates for a total contract value of $182 million starting in 2022.
This contract, which has a full quantity reduction option at any time before October 1, 2022, is dependent on ANR's ability to secure the required regulatory approvals and other requirements of the project associated with these volumes. See Part I, Item 1. “Business- Recent Business Developments- Growth Projects Update” for more information.

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PNGTS – PNGTS’ revenues are primarily generated from transportation agreements with LDCs throughout New England and Canada’s Atlantic provinces. The majority of PNGTS’ current revenue stream is supported by long-term contracts entered into via a series of open seasons for long-term capacity held by PNGTS in recent years. Long-term contracts with several shippers involving commitments of approximately 82,000 Dth/day from PNGTS’ Continent-to-Coast Contracts for a term of 15 years (the C2C Contracts) began December 1, 2017, necessitating an increase in PNGTS’ certificated capacity up to approximately 210,000 Dth/day. The C2C Contracts mature in 2032.
In addition to the C2C Contracts, 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, II and III were placed into service during the fourth quarter of 2018, 2019 and 2020, respectively. 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.
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 an independent project that is designed to be phased in over a four-year period beginning November 1, 2019 with Phase I. Phases II and III have estimated in-service dates of November 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 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 February 2023, subject to regulatory approvals and other requirements of the 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 and $49 million, respectively, in comparison to 2018 revenues when Bison was fully contracted. Its remaining contracts in the system expire in January 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 allow natural gas transported on Bison to flow in both directions, with the southwest direction involving deliveries onto third party pipelines and ultimately connecting into the Cheyenne hub. In any event, Bison will continue to incur costs related to property tax and operating and maintenance costs of approximately $6 million per year. See also Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Estimates” for more information.
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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.
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, 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 approximately 58,000 miles of natural gas pipelines, approximately 3,000 miles of liquids pipelines and 535 billion cubic feet of natural gas storage capacity. TC Energy also owns or has interests in approximately 4,200 megawatts of power generation. TC Energy operates most of our pipeline systems and, in some cases, contracts for pipeline capacity.

On December 14, 2020 the Partnership, the General Partner, TC Energy, TC Northern, TC PipeLine USA, and Merger Sub, entered into the TC Energy 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,
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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 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;
terms of service and service contracts with customers, including counterparty credit support requirements;
certification and construction of new facilities;
extension or abandonment of service and facilities;
accounts and records;
depreciation and amortization policies;
acquisition and disposition of facilities;
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 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).
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:
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2018 FERC Actions Impact on Maximum RatesMoratorium, Mandatory
Filing Requirements and
Other Considerations
Great Lakes2.0% rate reduction effective February 1, 2019No moratorium in effect; comeback provision with new rates to be effective by October 1, 2022
GTNA 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 2015Moratorium 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 Border2.0% rate reduction effective February 1, 2019 to December 31, 2019 extended until July 1, 2024 unless superseded by a subsequent rate case or settlementNo moratorium in effect; comeback provision with new rates to be effective by July 1, 2024
BisonNo rate changes proposedNo moratorium or comeback provisions
Iroquois3.25% rate reduction effective March 1, 2019; additional 3.25% rate reduction effective April 1, 2020Moratorium on rate changes until September 1, 2020; comeback provision with new rates to be effective by March 1, 2023
PNGTSNo rate changesNo moratorium or comeback provisions
North Baja10.8% rate reduction effective December 1, 2018No moratorium or comeback provisions; approximately 90 percent of North Baja’s contracts are negotiated; 10.8% reduction is on maximum rate contracts only
Tuscarora1.7% rate reduction effective February 1, 2019; additional rate reduction of 10.8% effective August 1, 2019Moratorium 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.
Existing rate settlements:
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 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.
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Iroquois – On February 28, 2019, Iroquois filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (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.
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.
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. No further action has occurred since the Certificate Policy Statement NOI was 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,
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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
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 exist 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 gas pipeline companies, including the Partnership, in the 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
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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.

Moreover, 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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Act also established a new three-year program for advancing pipeline safety technologies, testing, and operational practices and increasing the number of PHMSA inspection and enforcement personnel by 20%.

Other proposed rules:

Valve Installation and Minimum Rupture Detection Standards- On February 6, 2020 PHMSA published a Notice of Proposed Rulemaking (NPRM) entitled Pipeline Safety: Valve Installation and Minimum Rupture Detection Standards. The NPRM proposes to revise existing regulation for gas transmission pipelines to address congressional mandates, incorporate recommendations from the National Transportation Safety Board, and to reduce the consequences of large-volume, uncontrolled releases of natural gas pipeline ruptures. Specifically, the NPRM seeks to set requirements for the placement, function, and maintenance of automatic shut off and/or remote-control mainline valves to mitigate the effects of a pipeline rupture. The NPRM also seeks to set time requirements for the identification of, and response to, pipeline ruptures.

Class Location Change Requirements - On October 14, 2020, PHMSA, published an NPRM entitled Class Location Change Requirements. PHMSA is proposing to revise the Federal Pipeline Safety Regulations to amend the requirements for gas transmission pipeline segments that experience a change in class location. Under the existing regulations, pipeline segments located in areas where the population density has significantly increased must perform one of the following actions: reduce the pressure of the pipeline segment, pressure test the pipeline segment to higher standards, or replace the pipeline segment. This proposed rule would add an alternative set of requirements operators could use, based on implementing integrity management principles and pipe eligibility criteria, to manage certain pipeline segments where the class location has changed from a Class 1 location to a Class 3 location. Through required periodic assessments, repair criteria, and other extra preventive and mitigative measures, PHMSA expects this alternative approach would provide long-term safety benefits consistent with the current natural gas pipeline safety rules while also providing cost savings for pipeline operators.

While the above rulemaking process is expected to be lengthy, efforts to modernize the existing PHMSA regulations could have a material effect on our costs.

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. The promulgation of new laws and rulemaking regarding pipeline safety are likely and, despite compliance with applicable 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 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.
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
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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.
The amount of cash we generate from our operations, fluctuates based on, among other 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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transportation and storage capacity caused the New York Mercantile Exchange (NYMEX) West Texas Intermediate oil futures price to go as low as approximately negative $37. This negative pricing resulted from the holders of expiring front month oil purchase contracts being unable or unwilling to take physical delivery of crude oil and accordingly forced to make payments to purchasers of such contracts in order to transfer the corresponding purchase obligations.

Although oil prices have partially recovered from what was experienced in April, the COVID-19 pandemic and economic downturn could further negatively impact domestic and international demand for crude oil and natural gas and a prolonged period of low crude oil and natural gas prices would negatively impact exploration and development of new crude oil and natural gas supplies. In response to the sharp decline in oil and natural gas prices, many producers have announced cuts or suspension of exploration and production activities and some state regulators are considering mandating the proration of production of hydrocarbons. A drilling reduction could impact the availability of natural gas to be transported by our pipelines. Sustained low oil and natural gas prices could also impact counterparties’ creditworthiness and their ability to meet their transportation service cost obligations. Such developments could have an adverse effect on our assets, liabilities, business, financial condition, results of operations and cash flow.
Capital projects or future acquisitions that appear to be accretive may fail to materialize as anticipated or nevertheless reduce our cash available for 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 or grow our distributions. 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;
credit rating agencies may view our debt level negatively;
covenants contained 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 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.
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.
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.
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
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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’ 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 cash flow and necessitate a distribution reduction from the current quarterly level of $0.65 per common unit.
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.
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 pipeline systems may experience significant costs and liabilities related to 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 the Natural Gas Policy Act of 1978 to impose penalties for violations of up to approximately $1.31 million per day for each violation, to revoke existing certificate authority and to order disgorgement of profits associated with any violation.
Additionally, our pipeline systems are 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 and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to 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 aspects of our operations, which could cause us to incur increased operating and capital costs and result in operational delays.

Our compliance with these applicable PHMSA pipeline safety requirements 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
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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.

Owing to the nature of our pipeline operations, we are subject to stringent environmental laws and regulations that compel compliance with numerous obligations that are applicable to our operations including acquisition of permits or other approvals before conducting regulated activities, restrictions on the types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmentally sensitive areas such as wetlands, urban areas, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control requirements, and imposition of substantial liabilities for pollution resulting 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 imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting or performance of projects, and the issuance of orders enjoining or conditioning performance of some or all of our operations in a particular area. Environmental 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. For example, an accidental release from one 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 and fines or penalties for related violations of environmental laws or regulations. Moreover, the adoption and implementation of new environmental laws, regulations, judicial decisions, and enforcement policies could potentially increase our compliance-related costs, particularly in the realm of climate change and GHG regulation. Some high-profile federal environmental 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, specifically NWP 12, for utility 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 “incidental 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 “Once 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 in the United States and internationally. 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 various 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
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to the establishment of the social 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 Keystone 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 GHG emissions and limiting GHGs directly from certain sources. The general trend towards increased regulation of GHG emissions in the oil and 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 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 result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce 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 Combat Climate Change and Restrict Greenhouse Gas (GHG) Emissions”.

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 working collaboratively with customers, producers, vendors, federal and state regulators, trade associations, and other stakeholders to address the matter. GTN has also taken steps, incurred costs and made capital expenditures to address the matter. Between 2018 and 2020, GTN has spent capital expenditures of approximately $20 million and has incurred operating costs of approximately $3 million. Unless the issue is resolved, GTN expects to spend approximately $3 million in capital expenditures and $1 million in operating costs in 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.

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 Du 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, Great Lakes executed a Memorandum of Agreement with Fond Du Lac relating to the negotiation of a new right-of-way. Great Lakes continues to negotiate with Fond Du Lac and are in advanced discussions with Bad River. In late 2020, Great Lakes has reached an agreement with Leech Lake subject to further approval from the BIA.

While Great Lakes has progressed on the renewal process, 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.
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.
Additionally, 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, 2020, 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:
the Partnership had been conducting business in any state without compliance with the applicable limited partnership statute; or
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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, 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.
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, 2020, we paid fees and reimbursements to our General Partner in the amount of $4 million (2019 and 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
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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. 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 proposals that would eliminate our ability to qualify for partnership tax 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.
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.
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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.
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. 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. 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. While the determination of a partner’s amount realized generally includes any decrease of a partner’s share of the partnership’s liabilities, recently issued Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022. For a transfer of interests in a publicly traded partnership that is effected through a broker on or after January 1, 2022, the obligation to withhold is imposed on the transferor’s broker. Prospective foreign unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common 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, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

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.
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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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.

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.
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.
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 2 – 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, 2021, there were approximately 26 holders of record of our common units. Our common units trade on the NYSE under the symbol “TCP.”
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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)
20202019201820172016
(a)
Income Data (for the year ended December 31)
Transmission revenues
399 403 549 
(d)
422 426 
Equity earnings(b)
170 160 173 124 97 
Impairment of goodwill(c)
  59 — — 
Impairment of long‑lived assets(d)
  537 — — 
Net income (loss)
301 297 (165)263 263 
Net income (loss) attributable to controlling interests
284 280 (182)252 248 
Basic and diluted net (loss) income per common unit
$3.90 $3.74 $(2.68)$3.16 $3.21 
(e)
Cash Flow Data (for the year ended December 31)
Cash distribution declared per common unit
$2.60 $2.60 $2.60 $3.94 $3.71 
Balance Sheet Data (at December 31)
Total assets
3,145 2,853 2,899 3,559 3,354 
Long‑term debt, net1,768 1,880 2,072 2,352 1,859 
Partners’ equity
833 760 699 1,068 1,272 
(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”.
(b)Equity earnings represent our share in investee’s earnings and do not include any impairment charge on our equity investments.
(c)Please read Note 4 – Goodwill and Regulatory, Notes to the Consolidated Financial Statements included in Part IV Item 15. “Exhibits and Financial Statement Schedules” for more information.
(d)Please read Note 7 – Property, plant and Equipment, Notes to the Consolidated Financial Statements included in Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more information.
(e)Represents basic and diluted net income per common unit prior to recast


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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. This MD&A should be read in conjunction together with Part I Item 1. “Business” and the accompanying December 31, 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 2020 highlights are summarized as follows:
Generated net income attributable to controlling interests of $284 million or $3.90 per common unit compared to $280 million or $3.74 per common unit in 2019
Generated adjusted earnings of $284 million or $3.90 per common unit compared to $280 million or $3.74 per common unit in 2019
Generated EBITDA and Adjusted EBITDA of $479 million and $488 million in 2020, respectively compared to $460 million and $517 million in 2019, respectively
Declared and paid cash distributions totaling $2.60 per common unit, or $0.65 per quarter, for both 2020 and 2019
Generated Distributable Cash Flow of $255 million compared to $340 million in 2019
S&P and Moody's affirmed the Partnership's credit rating of BBB/Stable and Baa2/Stable, respectively

Please see the “How We Evaluate Our Operations" section for more information on our non-GAAP financial measures: EBITDA, Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit and Distributable Cash Flows.
Planned Merger with TC Energy
On December 14, 2020, the Partnership entered into the TC Energy Merger Agreement pursuant to which TC Energy will acquire all the outstanding common units of the Partnership not beneficially owned by TC Energy or its affiliates, in exchange for 0.70 TC Energy common share for each outstanding Partnership common unit.

The transaction is expected to close late in the first quarter of 2021 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.

(Please see also “Item 1. Business- Recent Business Developments” for more information.)
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 2020 and 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.
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)
20202019
Change(b)
Change(b)
Transmission revenues
399 403 (4)(1)
Equity earnings
170 160 10 
Operating, maintenance and administrative
(100)(105)
Depreciation
(89)(78)(11)(14)
Financial charges and other
(73)(83)10 12 
Net income (loss) before taxes
307 297 10 
Income taxes
(6)(7)*
Net income (loss)
301 298 
Net income attributable to non‑controlling interests
17 18 (1)(6)
Net income (loss) attributable to controlling interests
284 280 
Adjusted earnings (a)
284 280 
Net income (loss) per common unit
3.90 3.74 0.16 
Adjusted earnings per common unit (a)
3.90 3.74 0.16 
(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
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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)
20192018
$
Change(b)
%
Change(b)
Transmission revenues
403 549 (146)(27)
Equity earnings
160 173 (13)(8)
Impairment of long-lived assets
 (537)537 100 
Impairment of goodwill
 (59)59 100 
Operating, maintenance and administrative
(105)(101)(4)(4)
Depreciation
(78)(97)19 20 
Financial charges and other
(83)(92)10 
Net income (loss) before taxes
297 (164)461 *
Income taxes
1 (1)*
Net income (loss)
298 (165)463 *
Net income attributable to non‑controlling interests
18 17 
Net income (loss) attributable to controlling interests
280 (182)462 *
Adjusted earnings(a)
280 317 (37)(12)

Net income (loss) per common unit3.74 (2.68)6.42 *
Adjusted earnings per common unit(a)
3.74 4.18 (0.44)(11)
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(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, 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.
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.
Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per common unit
Reconciliation of Net income (loss) attributable to controlling interests to Adjusted earnings
(millions of dollars)
Year ended December 31
202020192018
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 
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Reconciliation of Net income (loss) per common unit to Adjusted earnings per common unit
Year ended December 31
202020192018
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 
(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.
(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 and our credit facilities. The Partnership funds its operating expenses, debt service and cash distributions (including those distributions made to TC Energy through our General Partner and as holder of all our Class B units) primarily from operating cash flow.
Overall Current Financial Condition
Cash and Debt position - Our overall long-term debt balance increased by approximately $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.
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Our pipeline systems’ principal sources of liquidity are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from owners. Except as noted below, our pipeline systems expect to fund their respective expansion projects primarily with debt. Except as noted below, our pipeline systems' normal recurring operating expenses, maintenance capital expenditures, debt service and cash distributions are primarily funded with their operating cash flows.

Since the fourth quarter of 2010, however, Great Lakes has funded its debt repayments with cash calls to its owners and we have contributed approximately $10 million each for 2020 and 2019 and $9 million for 2018.
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.
Bison’s remaining contracts continued in effect until January of 2021. In 2019 and 2020, Bison generated revenues of $32 million and $31 million, respectively. We continue to explore alternative transportation-related options for Bison and we believe commercial potential exists to allow for the flow of natural gas on Bison in both directions, with the southwest direction involving deliveries onto third party pipelines and ultimately connecting into the Cheyenne hub. In any event, Bison will continue to incur costs related to property tax and operating and maintenance costs of approximately $6 million per year.

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

The Partnership’s pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs which, although governed by FERC, allow them to request a certain amount of credit support as circumstances dictate.
Summarized Cash Flow
Year Ended December 31,
(millions of dollars)
202020192018
Net cash provided by (used in):
Operating activities
413 412 540 
Investing activities
(262)(32)(35)
Financing activities
(34)(330)(505)
Net increase in cash and cash equivalents
117 50 — 
Cash and cash equivalents at beginning of the period
83 33 33 
Cash and cash equivalents at end of the period
200 83 33 
Cash Flow Analysis for the Year Ended December 31, 2020 compared to Same Period in 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;
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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 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.
Capital spending
The Partnership’s share in capital spending for maintenance of existing facilities and growth projects was as follows:
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Year Ended December 31
(millions of dollars)
(unaudited)
202020192018
Maintenance
156 76 60 
Growth
165 26 
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.
Cash Flow Outlook
Operating Cash Flow Outlook
During the first quarter of 2021, the Partnership received or expects to receive the following distributions from our equity investments:
Northern Border declared its December 2020 distribution of $16 million on January 15, 2021, of which the Partnership received its 50 percent share or $8 million on January 29, 2021.
Northern Border declared its January 2021 distribution of $18 million on February 16, 2021, of which the Partnership will receive its 50 percent share or $9 million on February 26, 2021.
Great Lakes declared its fourth quarter 2020 distribution of $23 million on January 13, 2021, of which the Partnership received its 46.45 percent share or $11 million on January 29, 2021.
Iroquois declared its fourth quarter 2020 distribution of $22 million on February 18, 2021, of which the Partnership will receive its 49.34 percent share or $11 million on March 24, 2021.
Investing Cash Flow Outlook
The Partnership expects to make a $14 million contribution in 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.
The Partnership expects to make a $4 million contribution in 2021 to Iroquois, representing our 49.34 percent share of a cash call from Iroquois to cover capital costs required on their Exc Project.
In 2021, our pipeline systems expect to invest approximately $145 million in maintenance capital for existing facilities, of which the Partnership’s share will be $109 million. The Partnership’s estimated capital maintenance costs do not include any costs related to our GTN XPress Project (see further discussion below). Maintenance capital expenditures are added to our pipelines’ respective rate bases and are expected to earn a return on and of capital over time through the regulatory rate-making process.
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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 $86 million as of December 31, 2020 in connection with various maintenance and general plant projects over the next two years.
Please read Part 1, Item 1. “Business” for more details regarding these projects.
Financing Cash Flow Outlook
On January 19, 2021, the board of directors of our General Partner declared the Partnership’s fourth quarter 2020 cash distribution in the amount of $0.65 per common unit which was paid on February 12, 2021 to unitholders of record as of January 29, 2021. The total amount of cash distribution paid to common unitholders and General Partner was $47 million.
On January 19, 2021, after reviewing GTN's 2020 distributable cashflows, the TC PipeLines Board did not declare distributions to Class B unitholders as certain thresholds for a distribution to be made were not 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.

Debt refinancing:

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 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.

The Partnership’s $500 million Senior Credit Facility is due in November 2021 and we expect any outstanding balance will be repaid if the TC Energy Merger closes, or refinanced or extended prior to maturity if the TC Energy Merger does not close.

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

It is expected that North Baja will refinance its maturing term loan facility through an extension of the existing facility including the potential to increase the size of the facility to include the financing required for North Baja XPress Project.
Please read Notes 8, 10, 13 and 14, Notes to Consolidated Financial Statements included in Part IV, Item 15. “Exhibits and Financial Statement Schedules.”
The majority of the capital for our growth projects as discussed in the "Investing Cash Flow Outlook" section above is expected to be 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 cash flow during the current earnings period and reconciles directly to the most comparable measure of net income, which includes net income attributable to non-controlling interests, and earnings from our equity investments. It measures our net income before deducting interest, depreciation and amortization and taxes.

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

Our Adjusted EBITDA excludes the 2018 impact of the following non-recurring items:
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Bison’s contract termination proceeds amounting to $97 million recognized as revenue during the fourth quarter of 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:
less:
AFUDC,
Interest expense,
Current income taxes,
Distributions to non-controlling interests, and
Maintenance capital 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 the General Partner are based on its two percent interest plus, if applicable, an amount equal to incentive distributions. Distributions allocable to the Class B units in 2020 equal 30 percent of GTN’s distributable cash flow less $20 million, the residual of which is further multiplied by 43.75 percent. (Class B Distribution) (2019 and 2018 - less $20 million only).

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

The non-GAAP financial measures described above are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.
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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)
202020192018
Net income (loss)
301 298 (165)
Add (Less):
Interest expense(a)
83 85 94 
Depreciation and amortization
89 78 97 
Income tax expense (benefit)
6 (1)
EBITDA
479 460 27 
Add (less):
Non-recurring items
Impairment of goodwill — 59 
Impairment of long‑lived assets — 537 
Bison contract terminations — (97)
Less:
Equity earnings:
Northern Border
(76)(69)(68)
Great Lakes
(56)(51)(59)
Iroquois
(38)(40)(46)
(170)(160)(173)
Add:
Distributions from equity investments(b)
Northern Border
90 93 85 
Great Lakes
43 55 66 
Iroquois(c)
46 69 56 
179 217 207 
ADJUSTED EBITDA
488 517 560 
Less:
AFUDC
(11)(2)(1)
Interest expense(a)
(83)(85)(94)
Current income taxes (d)
(3)(1)(1)
Distributions to non‑controlling interests(e)
(22)(21)