10-K

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, 2019

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)

Delaware State or other jurisdiction of incorporation or organization	52-2135448 (I.R.S. Employer Identification No.)
700 Louisiana Street, Suite 700 Houston, Texas (Address of principal executive offices)	77002-2761 (Zip code)

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

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

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

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 ⌧ 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 ⌧

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ⌧ No ◻

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ⌧ No ◻

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

Large accelerated filer ⌧ Accelerated filer ◻ Non-accelerated filer ◻
​ Smaller Reporting Company ☐
Emerging Growth Company ☐

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

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

The aggregate market value of the common units of the registrant held by non-affiliates as of June 30, 2019 was approximately $ 2.7 billion.

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

DOCUMENTS INCORPORATED BY REFERENCE

None

TC PIPELINES, LP

TABLE OF CONTENTS

		Page No.
PART I
Item 1.	Business	9
Item 1A.	Risk Factors	26
Item 1B.	Unresolved Staff Comments	40
Item 2.	Properties	40
Item 3.	Legal Proceedings	41
Item 4.	Mine Safety Disclosures	41
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41
Item 6.	Selected Financial Data	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 8.	Financial Statements and Supplementary Data	64
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	64
Item 9A.	Controls and Procedures	64
Item 9B.	Other Information	65
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	65
Item 11.	Executive Compensation	68
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	70
Item 13.	Certain Relationships and Related Transactions, and Director Independence	72
Item 14.	Principal Accountant Fees and Services	75
PART IV
Item 15.	Exhibits and Financial Statement Schedules	75
Signatures		79

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

TC PipeLines, LP Annual Report 2019    3

DEFINITIONS

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

2013 Term Loan Facility	TC PipeLines, LP’s $500 million term loan credit facility under a term loan agreement as amended on September 29, 2017
2015 Term Loan Facility	TC PipeLines, LP’s $170 million term loan credit facility under a term loan agreement as amended on September 29, 2017
2017 Acquisition	Partnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017
2017 Great Lakes Settlement	Stipulation and Agreement of Settlement for Great Lakes regarding its rates and terms and conditions of service approved by FERC on February 22, 2018
2017 Northern Border Settlement	Stipulation and Agreement of Settlement for Northern Border regarding its rates and terms and conditions of service approved by FERC on February 23, 2018
2017 Tax Act	Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act, enacted on December 22, 2017
2018 FERC Actions	FERC’s 2018 issuance of Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC regulated pipelines and the impact of the Revised Policy Statement on pipelines held by an MLP
2018 GTN Settlement	Stipulation and Agreement of Settlement for GTN regarding its rates and terms and conditions of service approved by FERC on November 30, 2018
2019 Iroquois Settlement	An uncontested settlement filed by Iroquois with FERC to address the issues contemplated by the 2017 Tax Act and the 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
2019 Tuscarora Settlement	An uncontested settlement filed by Tuscarora with FERC to address the issues contemplated by the 2017 Tax Act and the 2018 FERC Actions via an amendment to its prior 2016 settlement approved by FERC on May 2, 2019
ADIT	Accumulated Deferred Income Tax
AFUDC	Allowance for funds used during construction
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
ATM program	At-the-market Equity Issuance Program
BIA	Bureau of Indian Affairs
Bison	Bison Pipeline LLC

C2C Contracts	PNGTS’ Continent-to-Coast Contracts with several shippers for a term of 15 years for approximately 82,000 Dth/day
Canadian Mainline	TC Energy’s Mainline, a natural gas transmission system extending from the Alberta/Saskatchewan border east to Quebec
Certificate Policy Statement NOI	FERC Notice of Inquiry issued on April 19, 2018

4    TC PipeLines, LP Annual Report 2019

Class B Distribution	Annual distribution to TC Energy based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter
Class B Reduction	Approximately 35 percent reduction applied to the estimated annual Class B Distribution beginning in 2018, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit
Consolidated Subsidiaries	GTN, Bison, North Baja, Tuscarora and PNGTS
Delaware Act	Delaware Revised Uniform Limited Partnership Act
DOT	U.S. Department of Transportation
Dth/day	Dekatherms per day
DSUs	Deferred Share Units
EBITDA	Earnings Before Interest, Tax, Depreciation and Amortization
EPA	U.S. Environmental Protection Agency
ExC Project	Iroquois Enhancement by Compression project that involves upgrading its compressor stations along the pipeline and provide approximately 125,000 Dth/day of additional firm transportation service to meet current and future gas supply needs of utility customers
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	U.S. generally accepted accounting principles
General Partner	TC PipeLines GP, Inc.
GHG	Greenhouse Gas
Great Lakes	Great Lakes Gas Transmission Limited Partnership
GTN	Gas Transmission Northwest LLC
GTN XPress	GTN project that will both increase the reliability of GTN's existing transportation service and provide up to 250,000 Dth/day of additional firm transportation service on the full path of the GTN system from Kingsgate, British Columbia, Canada to Malin, Oregon
HCAs	High consequence areas
IDRs	Incentive Distribution Rights
ILP Contribution	On December 31, 2018, General Partner contributed its 1.0101 percent general partner interest in each of the Partnership ILPs to the Intermediate GP and received a 1 percent general partner interest in the Partnership in return
ILPs	Intermediate Limited Partnerships
Intermediate GP	TC PipeLines Intermediate GP, LLC
IRS	Internal Revenue Service

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

TC PipeLines, LP Annual Report 2019    5

KPMG	KPMG LLP
LDCs	Local Distribution Companies
LIBOR	London Interbank Offered Rate
LNG	Liquefied Natural Gas
MLPs	Master limited partnerships
MNE	Maritimes and Northeast Pipeline LLC, a subsidiary of Enbridge Inc.
MNOC	M&N Operating Company, LLC, a wholly owned subsidiary of MNE
NGA	Natural Gas Act of 1938
North Baja	North Baja Pipeline, LLC
North Baja XPress	North Baja potential project to transport additional volumes of natural gas of approximately 495,000 Dth/day between Ehrenberg, Arizona and Ogilby, California
Northern Border	Northern Border Pipeline Company
NYSE	New York Stock Exchange
Our pipeline systems	Our ownership interests in GTN, Northern Border, Bison, Great Lakes, North Baja, Tuscarora, PNGTS and Iroquois
Partnership	TC PipeLines, LP including its subsidiaries, as applicable
Partnership Agreement	Fourth Amended and Restated Agreement of Limited Partnership of the Partnership
Partnership ILPs	TC PipeLines Intermediate Limited Partnership, TC Tuscarora Intermediate Limited Partnership and TC GL Intermediate Limited Partnership
PHMSA	U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration
PNGTS	Portland Natural Gas Transmission System
PXP	Portland XPress Project of PNGTS to re-contract certain system capacity set to expire in 2019 as well as construct incremental compression facilities within PNGTS’ existing footprint in Maine
Revised Policy Statement	FERC's Revised Policy Statement on Treatment of Income Taxes
ROE	Return on equity
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
Senior Credit Facility	TC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated September 29, 2017
TC Energy	TC Energy Corporation, formerly known as TransCanada Corporation
TQM	TransQuebec and Maritimes Pipeline

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

6    TC PipeLines, LP Annual Report 2019

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

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

TC PipeLines, LP Annual Report 2019    7

PART I

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

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

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

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

● demand for natural gas;

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

● natural gas prices and regional differences;

● weather conditions;

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

● competition from other pipeline systems;

● natural gas storage levels; and

● rates and terms of service;

● the performance by the shippers of their contractual obligations on our pipeline systems;

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

● 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;

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

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

● failure to comply with debt covenants, some of which are beyond our control;

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

● the implementation of future accounting changes and ultimate outcome of commitments and contingent liabilities (if any);

● the impact of any impairment charges;

● changes in the political environment;

8    TC PipeLines, LP Annual Report 2019

● 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; and

● the level of our indebtedness, including the indebtedness of our pipeline systems, changes in interest rates, and the availability of capital.

These and other risks are described in greater detail in Part I, Item 1A. “Risk Factors.” Given these uncertainties, you should not place undue reliance on these forward-looking statements. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. All forward-looking statements are made only as of the date made and except as required by applicable law, we undertake no obligation to update any forward-looking statements to reflect new information, subsequent events or other changes.

Item 1. Business

NARRATIVE DESCRIPTION OF BUSINESS

GENERAL

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

We are managed by our General Partner, which is an indirect, wholly-owned subsidiary of TC Energy. At December 31, 2019, subsidiaries of TC Energy own 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

Growth Projects Update:

Below is a summary of our growth projects announced in 2019 and updates to previously announced projects:

PNGTS’ Portland XPress Project - Our estimated $85 million Portland XPress Project or “PXP” was initiated in 2017 in order to expand deliverability on the PNGTS system to Dracut, Massachusetts through re-contracting and construction of incremental compression within PNGTS’ existing footprint in Maine. PXP was designed to be phased in over a three-year time period. Phases I and II were placed into service on November 1, 2018 and November 1, 2019, respectively. Phase III of the project is expected to be in service on November 1, 2020. Beginning in 2021, PXP is expected to generate approximately $50 million in annual revenue for PNGTS. PNGTS filed the required applications with FERC for all three phases of the project in 2018, which included an amendment to its Presidential Permit and an increase in its certificated capacity through the addition of a compressor unit at its jointly owned facility with Maritimes and Northeast Pipeline LLC to bring additional natural gas supply to New England. The total final volume of the project is approximately 183,000 Dth/ day; 40,000 Dth/day from Phase I, 118,400 Dth/day from Phase II, which includes re-contracting and renewal of expiring contracts, and 24,600 Dth/day from Phase III. We continue to advance this project and have received all approvals on filings to date. We expect to file with FERC for approval to proceed with construction of Phase III of the project in early 2020. PXP is secured by long-term agreements and when all phases of the project are in service, PNGTS will be effectively fully contracted until 2032.

Additionally, 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 will be required to fulfill future PXP contracts on the PNGTS system. In the event the Canadian system expansions terminate prior to their in-service dates, PNGTS could be required to reimburse TC Energy for an amount up to the total outstanding costs incurred to the date of the termination. As a result of TC Energy’s system expansions being commercially in service on November 1, 2019, and PNGTS’ commitments on TC Energy’s upstream pipelines being assigned to the PXP Phase II shippers, PNGTS’ obligation to reimburse the costs for Phase I and II terminated, which was approximately $143 million at the time of termination. Going forward, in the event the Phase III expansion terminates prior to its in-service date, PNGTS will only be obligated to reimburse costs incurred by TC Energy in relation to Phase III, which was $0.6 million at December 31, 2019 and is estimated to be approximately $8.0 million by November 1, 2020, when TC Energy’s facilities associated with the Phase III volumes go into service.

TC PipeLines, LP Annual Report 2019    9

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. 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.

GTN XPress Project (GTN XPress) - On November 1, 2019, we announced that GTN will move forward with the GTN XPress project which will transport approximately 250,000 Dth/day of additional volumes of natural gas enabled by TC Energy’s system expansion upstream. 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.

Tuscarora XPress Project (Tuscarora XPress) - Tuscarora XPress 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.

Iroquois Gas Transmission ExC Project (Iroquois ExC Project) - During the second quarter of 2019, Iroquois initiated the “Enhancement by Compression” project (ExC Project) which will optimize the Iroquois system to meet current and future gas supply needs of utility customers while minimizing the environmental impact through enhancements at existing compressor stations along the pipeline. In February 2020, Iroquois filed an application with FERC to authorize the construction of the project. The project’s total design capacity is approximately 125,000 Dth/day with an estimated cost of $250 million and in-service date of November 2023. This project will be 100 percent underpinned with 20-year contracts.

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

PHMSA Compliance Regulation

On October 1, 2019, the federal Pipeline and Hazardous Materials Safety Administration (PHMSA) released the first of three anticipated final rulemakings following its issuances in 2016 of an expansive proposed rulemaking (known as the "gas mega rule") revising the regulation of gas transmission and gathering lines. The October 1, 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 1, 2019 final rule also requires operators to review maximum allowable operating pressure records and perform specific remediation activities where records are not available. We are currently assessing the operational and financial impact related to this ruling which will become effective on July 1, 2020 with a 15-year implementation deadline. The remaining rulemakings comprising the gas mega rule are expected to be issued in 2020. See also Part I, Item 1. “Business- Government Regulation-Pipeline Safety Matters” for more information relating to PHSMA regulation of gas pipelines.

Cash Distributions to Common Units and our General Partner

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

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

10    TC PipeLines, LP Annual Report 2019

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

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

On January 21, 2020, the board of directors of the General Partner declared the Partnership’s fourth quarter 2019 cash distribution in the amount of $0.65 per common unit, which was paid on February 14, 2020 to unitholders of record as of January 31, 2020. The declared distribution totaled $47 million and was paid in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder 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 2019 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 2019. 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.

Class B Distributions

On January 21, 2020, the board of directors of our General Partner declared its annual Class B distribution in the amount of $8 million, which was paid on February 14, 2020. In 2019, the Class B distribution paid was $13 million. Please read Notes 11, 14 and 15 within Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more detailed disclosures on the Class B units.

Other Business Developments

Partnership structure - On December 31, 2018, the General Partner contributed its 1.0101 percent general partner interest in each of TC PipeLines Intermediate Limited Partnership, TC Tuscarora Intermediate Limited Partnership and TC GL Intermediate Limited Partnership (together, the Partnership ILPs) to TC PipeLines Intermediate GP, LLC (the Intermediate GP), a wholly-owned subsidiary of the Partnership, and received a one percent general partner interest in the Partnership in return (the ILP Contribution). This resulted in a simplification of the General Partner’s effective two percent general interest in the Partnership previously held through its directly-held one percent and indirectly-held 1.0101 percent general partner interests in the Partnership and Partnership ILPs, respectively, to a directly-held two percent general partner interest in the Partnership. The Partnership subsequently held 100 percent of the Partnership ILPs’ limited and general partner interests, with the general partner interest being held through the Intermediate GP.

During the fourth quarter of 2019, the Partnership initiated the dissolution of the Partnership ILPs and Intermediate GP. Effective October 31, 2019, the Intermediate GP and Partnership ILPs transferred 100 percent of the ownership of their pipeline assets to the Partnership, and the process of dissolving and unwinding the entities was completed in January 2020. Accordingly, the Partnership now owns its pipeline assets directly, which creates a more efficient partnership structure and aligns more closely with other MLP structures existing today, with no economic impact to the general and limited partners of the Partnership.

Financing

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

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

TC PipeLines, LP Annual Report 2019    11

Facility; (c) the repayment of $35 million due upon the maturity of GTN's $75 million Unsecured Term Loan Facility; and (d) $1 million scheduled payment on Tuscarora's Unsecured Term Loan offset by $20 million of additional borrowings on PNGTS' revolving credit facility. See Part II, Item 7. "Management’s Discussion and Analysis of Financial Condition and Result of Operations-Liquidity and Capital Resources" for more information.

Credit Rating Upgrade - On July 23, 2019, Standard & Poor's (S&P) upgraded the Partnership’s credit rating to BBB/Stable from BBB-/Stable primarily due to the improvement in our financial risk profile resulting from our ongoing deleveraging efforts.

Financing – Unconsolidated Subsidiaries

Northern Border - In June 2019, Northern Border borrowed an additional $100 million under its $200 million revolving credit facility to finance a $100 million cash distribution, of which $50 million was received by the Partnership. Northern Border's outstanding balance under this facility amounted to $115 million at December 31, 2019.

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

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).

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

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

Business environment

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

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

Supply

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

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

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

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

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

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

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

Demand

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

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

● natural gas-fired power generation;

● petrochemical and industrial facilities;

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

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

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

Commodity Prices

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

Competition

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

Our Natural Gas Infrastructure

We have ownership interests in eight natural gas interstate pipeline systems that are collectively designed to transport approximately 10.9 billion cubic feet per day of natural gas from producing regions and import facilities to market hubs and consuming markets primarily in the Western, Midwestern and Eastern U.S. All our pipeline systems, except Iroquois and the pipeline facilities jointly owned with MNE on PNGTS (Joint Facilities), are operated by subsidiaries of TC Energy. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Joint Facilities are operated by M&N Operating Company, LLC (MNOC), a subsidiary of Maritimes and Northeast Pipeline LLC (MNE). MNE is a subsidiary of Enbridge Inc.

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Our pipeline systems include:

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

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The map below shows the location of our pipeline systems.

Customers, Contracting and Demand

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

Our pipeline systems actively market their available capacity and work closely with customers, including natural gas producers, LDCs, marketers and end users, to ensure our pipelines are offering attractive services and competitive rates. Approximately 70 percent of our long-term contract revenues are with customers who have an investment grade rating or who have provided guarantees from investment grade parties. We have obtained financial assurances as permitted by FERC and our tariffs for the remaining long-term contracts. See 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 17-Transactions with major customers within Part IV, Item 15. “Exhibits and Financial Statement Schedules," which information is incorporated herein by reference. Additionally, our equity investee Great Lakes earns a significant portion of its revenue from TC Energy and its affiliates as disclosed under Note 18-Related party transactions within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

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

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

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remaining quantity is expected to begin to flow in mid-2020. The majority of these contracts have terms of at least 15 years.

On January 29, 2019, GTN’s largest customer, Pacific Gas and Electric Company (Pacific Gas), filed for Chapter 11 bankruptcy protection. Pacific Gas accounted for approximately seven percent of the Partnership’s consolidated revenues in 2019 (2018 - six 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 in 2019 and we do not expect the bankruptcy of Pacific Gas to have a material impact on our future cash flows and results of operations.

During the fourth quarter of 2019, we announced the GTN XPress project, our largest organic opportunity in TCP’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” for more information.

Northern Border – Northern Border is a highly competitive pipeline system with a weighted average remaining contract length of approximately 4 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 0.711 billion cubic feet (equivalent to about 722,000 Dth/day) of natural gas per day on the Great Lakes system. This contract, which contains volume reduction options up to full contract quantity until November 1, 2020, was a direct benefit from TC Energy’s long-term fixed price service on its Canadian Mainline that was launched in 2017. TC Energy’s long-term fixed price service provides long-term capacity to TC Energy’s shippers for the transportation of WCSB natural gas to markets in Eastern Canada and the U.S.

During the second quarter of 2018, Great Lakes reached an agreement on the terms of new long-term transportation capacity contracts with its affiliate, ANR Pipeline Company. The contracts are for a term of 15 years from November 2021 to October 31, 2036 with a total contract value of approximately $1.3 billion on 0.9 billion of cubic feet (equivalent to about 913,000 Dth/day) capacity. The contracts contain reduction options (i) at any time on or before April 1, 2020 for any reason and (ii) any time before April 2021, if TC Energy is not able to secure the required regulatory approval related to anticipated expansion projects. During the first quarter of 2019, Great Lakes reached an agreement to amend a volume reduction “for any reason” option by extending the period “on or before” April 1, 2019 to “on or before” April 1, 2020. All the other terms remained the same.

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 contract commitments of approximately 82,000 Dth/day from PNGTS’ Continent-to-Coast Contracts with several shippers for a term of 15 years (the C2C Contracts) open season began December 1, 2017, necessitating an increase in PNGTS’ certificated capacity up to approximately 210,000 Dth/day. 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 and II were placed into service on November 1, 2018 and November 1, 2019, respectively. Phase III of the project is expected to be in service on November 1, 2020. 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

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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 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. PNGTS signed precedent agreements for Phases II and III of Westbrook XPress, pending receipt of various regulatory and corporate approvals. The Westbrook XPress contracts expire between 2036 and 2042. See Part I, Item 1. “Business- Recent Business Developments-Growth Projects” for more information about PXP and Westbrook XPress.

Iroquois – Iroquois transports natural gas under long-term contracts that expire between 2019 and 2026 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 2019, 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 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” 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 additional volumes of natural gas along North Baja’s mainline system between Arizona and California. The estimated in-service date of the project is November 2022, subject to the satisfaction or waiver of certain conditions precedent including positive FID from Sempra LNG International, LLC. See Part I, Item 1. “Business- Recent Business Developments-Growth Projects” 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 and accordingly, in 2019, Bison’s revenue was reduced by approximately $47 million. Its remaining contracts in the system expire in January 2021. Bison will therefore be approximately 40 percent contracted on a ship-or-pay basis in 2020 and is expected to generate approximately $30 million in revenue, similar to 2019.

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

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

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

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Competition

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

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

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

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

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

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

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

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

Relationship with TC Energy

TC Energy is the indirect parent of our General Partner and at December 31, 2019, 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 57,900 miles of natural gas pipelines, approximately 3,000 miles of liquids pipelines and 653 billion cubic feet of natural gas storage capacity. TC Energy also owns or has interests in approximately 6,000 megawatts of power generation. TC Energy operates most of our pipeline systems and, in some cases, contracts for pipeline capacity.

See also Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence” for more information on our relationship with TC Energy.

Government Regulation

Federal Energy Regulatory Commission

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

● transportation of natural gas in interstate commerce;

● rates and charges;

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● 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 Tax Cuts and Jobs Act (2017 Tax Act) and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by MLPs (collectively, the 2018 FERC Actions).

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

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

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

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

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

Impact of the 2018 FERC Actions to the Partnership:

The 2018 FERC Actions directly addressed two components of our pipeline systems’ cost-of-service based rates: the allowance for income taxes and the inclusion of ADIT in their rate base. The 2018 FERC Actions also noted that precise treatment of entities with more ambiguous ownership structures must be separately resolved on a case-by-case basis, such as those partially owned by corporations including Great Lakes, Northern Border, Iroquois and PNGTS. Additionally, any FERC-mandated rate reduction did not affect negotiated rate contracts.

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

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

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

In 2019, 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.

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

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

Iroquois

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

Existing Settlements with subsequent limited section 4 rate reductions

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

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

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

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

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

NOI on Certificate Policy Statement

FERC issued a Notice of Inquiry on April 19, 2018 (Certificate Policy Statement NOI), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Certificate Policy Statement NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Any proposed changes to the current policy will be prospective only and it is expected that FERC will take many months to determine whether there will be any changes to proposed natural gas pipeline projects. We do not expect changes in this policy to affect us in a materially different manner than other similarly sized natural gas pipeline companies operating in the United States.

Environmental Matters

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

Federal Environmental Laws and Regulations

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

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

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

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

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

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

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

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

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

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

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

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

Total Financial Impact of Compliance with Environmental Laws and Regulations

At this time, 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

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not have a material adverse effect on our business, financial condition or results of operations. See Risk Factors under Part I, Item 1A of this Form 10-K for further discussion on pipeline safety matters.

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

On July 31, 2018, PHMSA published an advance notice of proposed rulemaking (ANPRM) requesting public comment on the additional safety measures pipelines facilities are required to take in response to class location changes due to population growth. The class location concept predates the extension of Integrity Management (IM) principles and it has been argued that public safety can be improved if IM measures are implemented as an alternative to pressure reductions, pipe replacements, or hydrostatic pressure testing. While this rulemaking process is expected to be lengthy, efforts to modernize the existing PHMSA regulations may have a material effect on costs.

On October 31, 2019, PHMSA released its “Enhanced Emergency Order Procedures” final rule, which replaces an interim final rule issued by PHMSA in 2016,and allows PHMSA to respond to imminent threats during natural disasters, and when serious flaws are discovered in pipes or in equipment manufacturing processes, or when an accident reveals an industry practice is unsafe. The final rule addressed comments made in response to the 2016 interim final rule, which resulted in several changes in the final rule. The Partnership is currently reviewing the final rule but does not expect any material issues in complying with the final rule, which took effect on December 2, 2019.

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

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

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

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

Historically, worker safety and health compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operational results. While pipeline operators may increase expenditures in the future to comply with higher industry and regulatory safety standards, such increases in

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

Cyber security

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

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

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

EMPLOYEES

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

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 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 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.

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Our ability to make cash distributions is dependent primarily on our cash flow, financial reserves and working capital borrowings.

The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate 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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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● 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.

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

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

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

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

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

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

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

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

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

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

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

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

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

RISKS RELATED TO OUR PIPELINE SYSTEMS

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

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

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

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

● competition from alternative sources of supply;

● competition from other existing or proposed pipelines;

● contract expirations and capacity on competing pipelines;

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

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

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

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

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

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

We are dependent on the continued availability of and demand for natural gas in relation to our pipeline systems.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our pipelines could be subject to penalties and fines if they fail to comply with FERC regulations.

Our pipelines are subject to substantial penalties and fines in the event that our pipeline systems have failed to comply with all applicable FERC-administered statutes, rules, regulations and orders, or the terms of their tariffs on file with FERC. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for violations of up to approximately $1.29 million per day for each violation, to revoke existing certificate authority and to order disgorgement of profits associated with any violation.

Our pipeline systems may experience significant costs and liabilities related to compliance with pipeline safety laws and regulations.

Our pipeline systems are subject to pipeline safety statutes and regulations administered by PHMSA, which require pipeline operators to develop integrity management programs.

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

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

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

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

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

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become effective and the United States will be covered under a single regulatory scheme as it relates to federal jurisdictional reach over Waters of the U.S. However, there remains the expectation that the January 23, 2020 final rule will be legally challenged in federal district court. To the extent that any challenge to the January 23, 2020 final rule is successful and the 2015 rule or a revised rule expands the scope of the Clean Water Act’s jurisdiction in areas where we conduct operations, pipeline companies such as us may become subject to more burdensome federal regulation and CWA permitting requirements. Although there is insufficient information at this time to assess the extent of the impact, an increase in operating costs and capital expenditures is expected.

Additionally, in 2019 the EPA published a proposed rule to implement CWA Section 401, which requires states and/or authorized tribes to grant, deny, or waive a water quality certification for major federal licenses and permits. The proposed rule clarifies various aspects of the current Section 401 regulations, including the actions triggering a Section 401 review, as well as the timeliness and scope of state and tribal review. Notably, the EPA narrows the scope of state and tribal review to preclude them from considering issues other than water quality in their certifications and curtails delays in decision-making by defining the amount of time states and tribes have to consider permit applications.

Furthermore, under certain environmental laws and regulations we may be exposed to substantial liabilities for pre-existing contamination connected to past or current operations. 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 the course of 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. For further discussion on environmental matters, see Part I, Item 1 “Government Regulation” – “Environmental Matters”.

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

Climate change continues to attract considerable public, governmental, and scientific attention both domestically in the U.S. and internationally. Considered to be the leading driver of climate change, GHG emissions remain at the forefront of the climate change debate. The Partnership, along with the greater oil and gas industry, has a vested interest in the debate since increased scrutiny on the cause of climate change subjects our operations to a number of regulatory, political, litigation, and financial risks. These risks may lead to material adverse effects on our business, financial condition, and results of operations.

Regulatory Risk

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

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

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reauthorization of the PSA allows for the continued funding of PHMSA and its pipeline safety program. Methane emissions provisions are now being considered for inclusion in a final bill, which would essentially authorize PHMSA to be another federal regulator of GHG emissions.

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

Political Risk

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

Litigation Risk

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

Financial Risk

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

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

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

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

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

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

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

GTN and TC Energy are gathering information and working collaboratively with customers, producers, vendors, and other stakeholders in an effort to develop and implement a joint plan to address each stakeholders’ respective issues, and have informed federal and state regulators, trade associations and other stakeholders of the issue. GTN has also taken steps, incurred costs and made capital expenditures to address the matter. Between 2018 and 2019, GTN has spent capital expenditures of approximately $13 million and has incurred operating costs of approximately $2 million. Unless the issue is resolved, GTN expects to spend approximately $6 million in capital expenditures and $1 million in operating costs between 2020 and 2021 to further resolve the matter. There is no assurance that significant additional costs will not be incurred in the future or that dithiazine or other substances will not be identified on our other pipeline systems.

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

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

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

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

During the second quarter of 2018, rights-of-way expired for approximately 7.6 miles of our Great Lakes pipeline on tribal land located within the Fond du Lac Reservation and Leech Lake Reservation in Minnesota and the Bad River Reservation 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, we executed a Memorandum of Agreement with the Fond du Lac tribal authorities relating to the negotiation of a new right-of-way and are negotiating or in discussions to obtain new rights-of-way with the tribal authorities for the three reservations. We cannot predict the 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,

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

RISKS RELATED TO OUR PARTNERSHIP STRUCTURE

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.

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

Common unitholders cannot remove our General Partner without its consent.

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

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

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

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

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

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

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

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

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

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

A general partner generally has unlimited liability for the obligations of a limited partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. We are organized under Delaware law and conduct business in a number of other states. The limitations on the liability of holders of limited partner

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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

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

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

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

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

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

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

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

● whether to exercise its limited call right;

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

● whether to elect to reset target distribution levels;

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

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

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

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

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

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

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

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

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

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

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

TAX RISKS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

In general, our unitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, 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 purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization or depletion is not capitalized into cost of goods sold with respect to inventory. The interest limitation does not apply to regulated pipeline businesses and, therefore, we believe that our interest expense is fully deductible. If the IRS contests this position or if further guidance is issued contrary to the positions taken, the unitholder’s ability to deduct this interest expense could be limited.

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

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

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

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

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferees but were not withheld. Because the “amount realized” includes a partner’s share of the partnership’s liabilities, 10% of the amount realized could exceed the total cash purchase price for the units. However, pending the issuance of final regulations, the IRS has suspended the application of this withholding rule to transfers of publicly traded interests in publicly traded partnerships. If recently promulgated regulations are finalized as proposed, such regulations would provide, with respect to transfers of publicly traded interests in publicly traded partnerships effected through a broker, that the obligation to withhold is imposed on the transferor’s broker and that a partner’s “amount realized” does not include a partner’s share of a publicly traded partnership’s liabilities for purposes of determining the amount subject to withholding. However, it is not clear when such regulations will be finalized and if they will be finalized in their current form.

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

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

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

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

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

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

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.

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

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

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

Item 3. Legal Proceedings

We may be involved in various legal proceedings from time to time that arise in the ordinary course of business. Information regarding our pipeline systems’ rate proceedings is described in Item 1. "Business – Government Regulation – Regulatory and Rate Proceedings" is incorporated herein by reference. Information on our legal proceedings can be found under Note 22 – Contingencies within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

Item 4. Mine Safety Disclosures

None.

PART II

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

As of February 19, 2020, there were approximately 27 holders of record of our common units. Our common units trade on the NYSE under the symbol “TCP.”

As of February 19, 2020, the Partnership had 71,306,396 common units outstanding, of which 54,221,565 were held by non-affiliates and 17,084,831 common units were held by subsidiaries of 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 15-Cash Distributions within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

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

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

(b) Equity earnings represent our share in investee’s earnings and do not include any impairment charge on our equity investments.

(c) Represents the impairment charge on our investment in Great Lakes. The equity earnings as presented in 2015 did not include this impairment charge.

(d) 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.

(e) 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.

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

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

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

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

● EXECUTIVE OVERVIEW;

● HOW WE EVALUATE OUR OPERATIONS;

● RESULTS OF OPERATIONS;

● LIQUIDITY AND CAPITAL RESOURCES;

● CRITICAL ACCOUNTING ESTIMATES;

● CONTINGENCIES; and

● RELATED PARTY TRANSACTIONS.

EXECUTIVE OVERVIEW

Financial Performance Highlights

Our 2019 highlights are summarized as follows:

● Generated net income attributable to controlling interests of $280 million or $3.74 per common unit compared to a net loss of $182 million or $2.68 per common unit in 2018

● Generated adjusted earnings of $280 million or $3.74 per common unit compared to $317 million or $4.18 per common unit in 2018

● Generated both EBITDA and Adjusted EBITDA of $460 million in 2019 compared to $27 million and $526 million in 2018, respectively

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

● Generated Distributable Cash flow of $340 million compared to $391 million in 2018

● Reduced debt balance by $106 million during 2019

● Received approval from FERC for both Iroquois and Tuscarora rate settlements on May 2, 2019

● S&P upgraded credit rating to BBB/Stable from BBB-/Stable

Please see “How We Evaluate Our Operations Section” for more information on our Non-GAAP Financial Measures: EBITDA, Adjusted earnings and Adjusted earnings per common unit and Distributable Cash Flows.

Outlook of Our Business

With the return to a stable regulatory environment in 2019 and our financial metrics solidly in line with a self-funding business model, we believe our pipeline systems, which are largely backed by long-term, ship-or-pay contracts, will deliver consistent financial performance going forward and support our current quarterly distribution level of $0.65 per common unit for the foreseeable future.

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

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

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

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

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

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

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

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

HOW WE EVALUATE OUR OPERATIONS

We use certain non-GAAP financial measures that do not have any standardized meaning under GAAP as we believe they each enhance the understanding of our operating performance. We use the following non-GAAP 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 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 measures that exclude the 2018 impacts of the $596 million non-cash impairment charges and the one-time $97 million revenue item relating to Bison’s contract terminations. We had no similar adjustments in the 2019 and 2017 periods.

Distributable Cash Flows

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

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

44    TC PipeLines, LP Annual Report 2019

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, 2019 Compared with the Year Ended December 31, 2018

(unaudited)			$	%
(millions of dollars, except per common unit amounts)	2019	2018	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)	9	10
Net income (loss) before taxes	297	(164)	461	*
Income taxes	1	(1)	2	*
Net income (loss)	298	(165)	463	*
Net income attributable to non‑controlling interests	18	17	1	6
Net income (loss) attributable to controlling interests	280	(182)	462	*
Adjusted earnings (a)	280	317	(37)	(12)
Net income (loss) per common unit	3.74	(2.68)	6.42	*
Adjusted earnings per common unit (a)	3.74	4.18	(0.44)	(11)

(a) Adjusted earnings and Adjusted earnings per common unit are non-GAAP 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 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

TC PipeLines, LP Annual Report 2019    45

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

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

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

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

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

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

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

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

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

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

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

*       Change is greater than 100 percent.

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

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

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

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

46    TC PipeLines, LP Annual Report 2019

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

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

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

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

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

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

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

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

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

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

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

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

(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

Our principal sources of liquidity and cash flows include distributions received from our equity investments, operating cash flows from our subsidiaries, public offerings of debt and equity, term loans and our Senior Credit Facility. The Partnership funds operating expenses, debt service and cash distributions (including those distributions made to TC Energy through our General Partner and as holder of all our Class B units) primarily with operating cash flow.

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

TC PipeLines, LP Annual Report 2019    47

We believe our cash position, remaining borrowing capacity on our Senior Credit Facility (see table below), and our operating cash flows are sufficient to fund our short-term liquidity requirements, including distributions to our unitholders, ongoing capital expenditures and required debt repayments.

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

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

Our pipeline systems’ principal sources of liquidity are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from their owners. Except as noted below, our pipeline systems have historically funded operating expenses, debt service and cash distributions to their owners primarily with operating cash flow.

● 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 in 2019 and $9 million each for 2018 and 2017.

● In August 2019, the Partnership made an equity contribution to Iroquois of approximately $4 million. This amount represented the Partnership’s 49.34 percent share of a $7 million capital call from Iroquois to cover 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. In 2017, we made an equity contribution to Northern Border amounting to $83 million, which was used by Northern Border to reduce the outstanding balance on its revolver. The $50 million and $83 million amounts represent our 50 percent share of Northern Border’s distribution and contribution, respectively.

● Bison’s remaining contracts will continue until January of 2021. In 2019, Bison generated revenues of $32 million and is expected to produce comparable results in 2020. We continue to explore alternative transportation-related options for Bison and we believe commercial potential exists to reverse the direction of natural gas flow on Bison for deliveries onto third party pipelines and ultimately connect into the Cheyenne hub. Notwithstanding the results of these commercial activities, Bison will continue to incur costs related to property tax and operating and maintenance costs of approximately $6 million per year.

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

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

Summarized Cash Flow

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

48    TC PipeLines, LP Annual Report 2019

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.

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

Operating Cash Flows

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

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

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

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

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

TC PipeLines, LP Annual Report 2019    49

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

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

Investing Cash Flows

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

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

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

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

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

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

Financing Cash Flows

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

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

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

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

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

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

Capital spending

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

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

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

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

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.

50    TC PipeLines, LP Annual Report 2019

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

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

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

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

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

Cash Flow Outlook

Operating Cash Flow Outlook

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

Northern Border declared its December 2019 distribution of $18 million on January 10, 2020, of which the Partnership received its 50 percent share or $9 million on January 31, 2020.

Northern Border declared its January 2020 distribution of $19 million on February 11, 2020, of which the Partnership will receive its 50 percent share or $9 million on February 28, 2020.

Great Lakes declared its fourth quarter 2019 distribution of $34 million on January 10, 2020, of which the Partnership received its 46.45 percent share or $16 million on January 31, 2020.

Iroquois declared its fourth quarter 2019 distribution of $27 million in February 2020, of which the Partnership will receive its 49.34 percent share or $14 million on March 30, 2020.

Investing Cash Flow Outlook

The Partnership expects to make a $10 million contribution in 2020 to Great Lakes to fund debt repayments which is consistent with prior years.

In 2020, our pipeline systems expect to invest approximately $152 million in maintenance capital for existing facilities, of which the Partnership’s share will be $113 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.

Our pipeline systems also expect to invest approximately $242 million in growth projects in 2020, of which the Partnership’s share will be $187 million. Growth capital expenditures include $102 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.” 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 $21 million as of December 31, 2019 in connection with various maintenance and general plant projects.

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

Financing Cash Flow Outlook

On January 21, 2020, the board of directors of our General Partner declared the Partnership’s fourth quarter 2019 cash distribution in the amount of $0.65 per common unit which was paid on February 14, 2020 to unitholders of record as of January 31, 2020. The total amount of cash distribution paid to common unitholders and General Partner was $47 million.

On January 21, 2020, the board of directors of our General Partner declared distributions to Class B unitholders in the amount of $8 million which was paid on February 14, 2020. The Class B distribution represents an amount equal to 30

TC PipeLines, LP Annual Report 2019    51

percent of GTN’s distributable cash flow during the year ended December 31, 2019 less the threshold level of $20 million and the Class B Reduction. For 2020 and beyond, we expect the impact of Class B distribution on our cashflows to be significantly lower compared to the previous periods.

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

Please read Notes 8, 11, 14 and 15, Notes to Consolidated Financial Statements included in Part IV, Item 15. “Exhibits and Financial Statement Schedules.”

The majority of our growth projects as discussed in the Investing Cashflow Outlook section above is being financed through debt.

As of February 20, 2020, the available borrowing capacity on our Senior Credit Facility was $500 million.

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

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

Our Adjusted EBITDA excludes the 2018 impact of the following:

● 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, 2019 and 2017, we do not have any similar adjustments in our Adjusted EBITDA. Accordingly, for the years ended December 31, 2019 and 2017 our EBITDA is the same as Adjusted EBITDA.

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

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

● Distributions from our equity investments

less:

● Earnings from our equity investments,

● Allowance for funds used during construction (AFUDC),

● Interest expense,

● Current income taxes,

● Distributions to non-controlling interests,

● Distributions to TC Energy as former parent of PNGTS, and

● Maintenance capital expenditures.

Distributable cash flow is computed net of distributions declared to the General Partner and distributions allocable to Class B units. Distributions declared to the General Partner are based on its two percent interest plus an amount equal to incentive distributions. Distributions allocable to the Class B units equal 30 percent of GTN’s distributable cash flow for the year ended December 31, 2019, less $20 million (Class B Distribution) (2018 and 2017 – less $20 million).

For the year ended December 31, 2019, 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

52    TC PipeLines, LP Annual Report 2019

for such calendar year do not equal or exceed $3.94 per common unit. The Class B Reduction was not applicable during 2017.

Adjusted earnings and Adjusted earnings per common unit exclude the 2018 impact of the $97 million of Bison contract termination proceeds and $596 million of impairment charges incurred during the year ended December 31, 2018 on our net income on a whole and per common unit basis, respectively.

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

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

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

The following table presents a reconciliation of the non-GAAP financial measures of EBITDA, Adjusted EBITDA and Distributable Cash Flow, to the GAAP financial measure of net income.

Year Ended December 31
(unaudited)
(millions of dollars)	2019	2018	2017
Net income (loss)	298	(165)	263
Add (Less):
Interest expense(a)	85	94	84
Depreciation and amortization	78	97	97
Income tax expense (benefit)	(1)	1	1
EBITDA	460	27	445
Add:
Impairment of goodwill	—	59	—
Impairment of long‑lived assets	—	537	—
Bison contract terminations	—	(97)	—
ADJUSTED EBITDA	460	526	445
Add:
Distributions from equity investments(b)
Northern Border	93	85	82
Great Lakes	55	66	38
Iroquois(c)	69	56	41
	217	207	161
Less:
Equity earnings:
Northern Border	(69)	(68)	(67)
Great Lakes	(51)	(59)	(31)
Iroquois	(40)	(46)	(26)
	(160)	(173)	(124)
Less:
AFUDC	(2)	(1)	—
Interest expense(a)	(85)	(94)	(84)
Current income taxes (d)	(1)	(1)	(1)
Distributions to non‑controlling interests(e)	(21)	(20)	(14)
Distributions to TC Energy as PNGTS' former parent(f)	—	—	(2)
Maintenance capital expenditures(g)	(56)	(36)	(38)
	(165)	(152)	(139)
Total Distributable Cash Flow	352	408	343
General Partner distributions declared(h)	(4)	(4)	(18)
Distributions allocable to Class B units(i)	(8)	(13)	(15)
Distributable Cash Flow	340	391	310

(a) Interest expense as presented includes net realized loss related to the interest rates swaps and amortization of realized loss on PNGTS’ derivative instruments (Refer to Notes 13 and 20, Notes to Consolidated Financial Statements included in Part IV, Item 15. “Exhibits and Financial Statement Schedules”).

TC PipeLines, LP Annual Report 2019    53

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

(c) This amount represents our proportional 49.34 percent share of the distribution declared by our equity investee Iroquois and includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $10 million for both years ended December 31, 2019 and December 31, 2018 and $8 million for the year ended December 31, 2017. In 2019, we also received an additional distribution of $15 million related to the increase in the cash Iroquois generated from its higher income in 2017 (post acquisition) and 2018. (Refer to Notes 5 and 7, Notes to Consolidated Financial Statements included in Part IV, Item 15. “Exhibits and Financial Statement Schedules”).

(d) Beginning the year ended December 31, 2019, we reduced our distributable cashflows based on the current income tax expense paid by PNGTS on its New Hampshire state taxes which approximates net cash paid during the current period. The change did not materially impact comparability to prior periods.

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

(f) Distributions to TC Energy as PNGTS’ former parent represent TC Energy’s respective share of PNGTS’ distributable cash not owned by us during the periods presented.

(g) The Partnership’s maintenance capital expenditures include expenditures made to maintain, over the long term, our assets’ operating capacity, system integrity and reliability. Accordingly, this amount represents the Partnership’s and its Consolidated Subsidiaries’ maintenance capital expenditures and does not include the Partnership’s share of maintenance capital expenditures on our equity investments. Such amounts are reflected in “Distributions from equity investments” as those amounts are withheld by those entities from their quarterly distributable cash. Please read the Capital spending section for more information regarding the Partnership’s total proportionate share of maintenance capital expenditures from our consolidated entities and equity investments.

(h) Distributions declared to the General Partner for the year ended December 31, 2019 did not include any incentive distributions (2018 - none; 2017 - $12 million).

(i) Distributions allocable to the Class B units is based on 30 percent of GTN’s distributable cashflow during the current reporting period but declared and paid in the subsequent reporting period.

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

Our EBITDA was $433 million higher in 2019 compared to 2018 due to the 2018 goodwill impairment of $59 million for Tuscarora and the long-lived asset impairment for Bison of $537 million, partially offset by the additional $97 million in revenue recognized for the Bison contract terminations. Our Adjusted EBITDA was lower by $66 million compared to 2018 as a result of higher equity earnings lower revenues and higher operating expenses Refer to “Results of Operations” for more details.

Our distributable cash flow decreased by $51 million for the year ended December 31, 2019 compared to the same period in 2018 due to the net effect of:

● lower Adjusted EBITDA from our Consolidated Subsidiaries primarily due to significantly lower revenues from Bison from being 100 percent fully contracted in 2018 to only approximately 40 percent in 2019 and an overall increase in our operating expenses as discussed in more detail in the Results of Operations Section;

● higher distributions from our equity investment in Northern Border primarily due to lower capital spending related to compressor station maintenance costs;

● lower distributions from Great Lakes resulting from decreased earnings and increased maintenance capital spending;

● additional distribution received from Iroquois due to the surplus cash accumulated from previous years' higher net income;

● higher maintenance capital expenditures related to major compression equipment overhauls and pipe integrity costs on GTN as a result of higher transportation volumes of natural gas;

● lower interest expense due to the full repayment of the $170 million Term Loan during the fourth quarter of 2018 and the partial repayment of borrowings under our Senior Credit Facility in the first quarter of 2019; and

● lower Class B allocation due to lower distributable cash flow generated by GTN.

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

Our EBITDA was $418 million lower in 2018 compared to 2017 due to the goodwill impairment of $59 million for Tuscarora and the long-lived asset impairment for Bison of $537 million, partially offset by the additional $97 million in revenue recognized for the Bison contract terminations. Our Adjusted EBITDA was higher by $81 million compared to 2017 as a result of higher equity earnings and an overall increase in revenues in 2018. Refer to “Results of Operations” for more details.

54    TC PipeLines, LP Annual Report 2019

Our distributable cash flow for the twelve months ended December 31, 2018 was $81 million higher compared to the twelve months ended December 31, 2017 due to the net effect of:

● higher Adjusted EBITDA from GTN, PNGTS and North Baja due to an increase in their revenues generated during the twelve months ended December 31, 2018 as described in the “Results of Operations” section;

● four quarters of distributions received from Iroquois during the twelve months ended December 31, 2018 compared to three quarters of distributions received during the previous period (ownership of 49.34 percent was effective June 1, 2017);

● higher financing costs as a result of additional debt incurred to partially finance the 2017 Acquisition;

● higher distributions from Great Lakes due to the increase in its revenue generated during the twelve months ended December 31, 2018 from higher short-term services sold during the year and the elimination of Great Lakes’ revenue sharing mechanism that began in 2018 as part of Great Lakes rate settlement in 2017;

● higher distributable cash flow from Northern Border primarily due to an overall decrease in its system integrity maintenance capital expenditures in 2018;

● reduction in declared distributions which did not result in any IDR allocation to our General Partner during the current period; and

● lower distributions allocated to the Class B units as a result of the Class B Reduction, which was directly related to the reduction in distributions declared for the common units.

Contractual Obligations

The Partnership’s Contractual Obligations

The Partnership’s contractual obligations as of December 31, 2019 included the following:

		Payments Due by Period
						Weighted
						Average
						Interest
						Rate for the
						Year Ended
(unaudited)		Less than	1‑3	4‑5	More than	December 31,
(millions of dollars)	Total	1 Year	Years	Years	5 Years	2019
TC PipeLines, LP
Senior Credit Facility due 2021	—	—	—	—	—	—
2013 Term Loan Facility due 2022	450	—	450	—	—	3.52	%
4.65% Senior Notes due 2021	350	—	350	—	—	4.65	%(a)
4.375% Senior Notes due 2025	350	—	—	—	350	4.375	%(a)
3.90% Senior Notes due 2027	500	—	—	—	500	3.90	%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100	100	—	—	—	5.29	%(a)
5.69% Unsecured Senior Notes due 2035	150	—	—	—	150	5.69	%(a)
PNGTS
Revolving Credit Facility due 2023	39	—	—	39	—	3.47	%
Transportation by others	1	1	—	—	—
Tuscarora
Unsecured Term Loan due 2020	23	23	—	—	—	3.39	%
North Baja
Unsecured Term Loan due 2021	50	—	50	—	—	3.34	%
Partnership (TC PipeLines, LP and its subsidiaries)
Interest on debt obligations(b)	430	78	123	87	142
Operating leases	3	1	1	—	1
	2,446	203	974	126	1,143

(a) Fixed Rate debt

(b) Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at December 31, 2019 and are therefore subject to change beyond 2019. Future interest payments on floating rate debt do not include potential obligation related to our interest rate swaps.

TC PipeLines, LP Annual Report 2019    55

Additional information regarding the Partnership’s debt and interest rate swaps can be found under Note 9 - Debt and Credit Facilities and Note 20- Fair Value measurements, respectively within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

Summary of Northern Border’s Contractual Obligations

Northern Border’s contractual obligations as of December 31, 2019 included the following:

		Payments Due by Period(a)
(unaudited)		Less than	1‑3	4‑5	More than
(millions of dollars)	Total	1 Year	Years	Years	5 Years
$200 million Credit Agreement due 2024	115	—	—	115	—
7.50% Senior Notes due 2021	250	—	250	—	—
Interest payments on debt	50	22	21	7	—
Other commitments(b)	48	3	5	5	35
	463	25	276	127	35

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

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

Northern Border has commitments of $9 million as of December 31, 2019 in connection with various pipeline, metering and overhaul projects.

Senior Notes

Northern Border’s outstanding debt securities are senior unsecured notes. The indentures for the notes do not limit the amount of unsecured debt Northern Border may incur but do restrict secured indebtedness. At December 31, 2019, Northern Border was in compliance with all of its financial covenants.

Credit Agreement

Northern Border’s credit agreement consists of a $200 million revolving credit facility. On October 1, 2019, the credit agreement was extended to mature on October 1, 2024. At December 31, 2019, $115 million was outstanding on this facility. At Northern Border’s option, the interest rate on the outstanding borrowings may be the lenders' base rate or LIBOR plus, in either case, an applicable margin that is based on Northern Border’s long-term unsecured credit ratings. The interest rate on Northern Border’s credit agreement at December 31, 2019 was 2.82 percent (2018 – 3.48 percent). At December 31, 2019, Northern Border was in compliance with all of its financial covenants.

Summary of Great Lakes’ Contractual Obligations

Great Lakes’ contractual obligations as of December 31, 2019 included the following:

		Payments Due by Period(a)
(unaudited)		Less than	1‑3	4‑5	More than
(millions of dollars)	Total	1 Year	Years	Years	5 Years
9.09% series Senior Notes due 2016 to 2021	20	10	10	—	—
6.95% series Senior Notes due 2020 to 2028	99	11	22	22	44
8.08% series Senior Notes due 2021 to 2030	100	—	20	20	60
Interest payments on debt	82	16	26	19	21
Right-of-way commitments	1	—	—	—	1
	302	37	78	61	126

(a) Represents 100 percent of Great Lakes’ contractual obligations.

Great Lakes has commitments of $4 million as of December 31, 2019 in connection with compressor overhaul projects.

Long-Term Financing

All of Great Lakes’ outstanding debt securities are senior unsecured notes with similar terms except for interest rates, maturity dates and prepayment premiums.

Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately $118 million of Great Lakes’ partners’ capital was restricted as to distributions as of December 31, 2019 (2018 - $129 million). Great Lakes was in compliance with all of its financial covenants at December 31, 2019.

56    TC PipeLines, LP Annual Report 2019

Summary of Iroquois’ Contractual Obligations

Iroquois’ contractual obligations as of December 31, 2019 included the following:

		Payments Due by Period(a)
(unaudited)		Less than	1‑3	4‑5	More than
(millions of dollars)	Total	1 Year	Years	Years	5 Years
4.12% series Senior Notes due 2034	140	—	—	—	140
4.07% series Senior Notes due 2030	150	—	—	—	150
6.10% series Senior Notes due 2027	29	3	8	8	10
Interest payments on debt	95	11	14	14	56
Transportation by others(b)	9	3	6	—	—
Operating leases	4	1	1	—	2
Pension contributions(c)	1	1	—	—	—
	428	19	29	22	358

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

(b) Rates are based on known 2020 levels. Beyond 2020, demand rates are subject to change.

(c) Pension contributions cannot be reasonably estimated by Iroquois beyond 2020.

Iroquois has commitments of $2.5 million as of December 31, 2019 relative to capital expenditures.

Iroquois is restricted under the terms of its note purchase agreement from making cash distributions to its partners unless certain conditions are met. Before a distribution can be made, the debt/capitalization ratio must be below 75 percent and the debt service coverage ratio must be at least 1.25 times for the four preceding quarters. At December 31, 2019, the debt/capitalization ratio was 52.1 percent and the debt service coverage ratio was 5.38 times, therefore, Iroquois was not restricted from making cash distributions.

Cash Distribution Policy of the Partnership

The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and our General Partner after providing for Class B distributions based on the specified target distribution levels. The percentage interests set forth below for our General Partner include its IDRs and two percent general partner interest and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The percentage interest distributions to the General Partner illustrated below that are in excess of its two percent general partner interest represent the IDRs.

			Marginal Percentage
			Interest in Distribution
		Total Quarterly Distribution	Common		General
		Per Unit Target Amount	Unitholders		Partner
Minimum Quarterly Distribution	$	0.45	98	%	2	%
First Target Distribution		above $0.45 up to $0.81	98	%	2	%
Second Target Distribution		above $0.81 up to $0.88	85	%	15	%
Thereafter		above $0.88	75	%	25	%

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

Distribution Policies of Our Pipeline Systems

Distributions of available cash are made to partners on a pro rata basis according to each partner’s ownership percentage, approximately one month following the end of a quarter. Our pipeline systems’ respective management committees determine the amounts and timing of cash distributions, where the amounts of such distributions are based on distributable cash flow as determined by a prescribed formula. Any changes to, or suspension of our pipeline systems’ cash distribution policies requires the unanimous approval of their respective management committees.

GTN, Bison, PNGTS and North Baja’s distribution policies require the pipelines to distribute 100 percent of distributable cash flow based on earnings before depreciation and amortization less AFUDC and maintenance capital expenditures. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

TC PipeLines, LP Annual Report 2019    57

Tuscarora’s distribution policy requires the distribution of 100 percent of distributable cash flow based on earnings before depreciation and amortization less debt repayment, AFUDC and maintenance capital expenditures. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

Iroquois and PNGTS distribute their available cash less any required reserves that are necessary to comply with debt covenants and/or appropriately conduct their respective businesses, as determined and approved by their management committees. While PNGTS’ and Iroquois’ debt repayments are not funded with capital calls to their owners, PNGTS and Iroquois have historically funded scheduled debt repayments by adjusting cash available for distribution, which effectively reduces the amount of cash available for distributions.

Northern Border’s distribution policy requires Northern Border to distribute on a monthly basis, 100 percent of the distributable cash flow based on earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. Northern Border adopted certain changes related to equity contributions that defined minimum equity to total capitalization ratios to be used by the Northern Border management committee to determine the amount of required equity contributions, timing of the required contributions and for any shortfall due to the inability to refinance maturing debt to be funded by equity contributions.

Great Lakes’ distribution policy requires the distribution of 100 percent of distributable cash flow based on earnings before income taxes, depreciation, AFUDC less capital expenditures and debt repayments not funded with cash calls to its partners. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ.

We believe our critical accounting estimates discussed in the following paragraphs require us to make the most significant assumptions when preparing our financial statements and changes in these assumptions could have a material impact on the financial statements. These critical accounting estimates should be read in conjunction with our accounting policies summarized on Notes 2 and 3, Notes to Consolidated Financial Statements included in Part IV within Item 15. “Exhibits and Financial Statement Schedules."

Regulation

Our pipeline systems’ accounting policies conform to Accounting Standards Codification (ASC) 980 – Regulated Operations. As a result, our pipeline systems record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. Our pipeline systems consider several factors to evaluate their continued application of the provisions of ASC 980 such as potential deregulation of their pipelines; anticipated changes from cost-based rate-making to another form of regulation; increasing competition that limits their ability to recover costs; and regulatory actions that limit rate relief to a level insufficient to recover costs.

Certain assets that result from the rate-making process are reflected on the balance sheets of our pipeline systems. If it is determined that future recovery of these assets is no longer probable as a result of discontinuing application of ASC 980 or other regulatory actions, our pipeline systems would be required to write off the regulatory assets at that time. Due to the impairment recognized on Bison during the fourth quarter of 2018 (discussed in more detail below under “Long Lived Assets”), ASC 980 on Bison was discontinued as the future recovery of costs is no longer probable. The impact of ASC 980 discontinuance on Bison was immaterial to the consolidated results of the Partnership.

At December 31, 2019, the Partnership had no regulatory assets or regulatory liabilities reported as part of other current assets or accounts payable and accrued liabilities on the balance sheet, respectively.

As of December 31, 2019, our equity investees have regulatory assets amounting to $13 million (2018 - $14 million).

As of December 31, 2019, our equity investees have regulatory liabilities amounting to $39 million (2018 - $34 million).

At December 31, 2018, the Partnership had $2 million of regulatory assets reported as part of other current assets on the balance sheet and $2 million of regulatory liabilities reported on the balance sheet as part of accounts payable and

58    TC PipeLines, LP Annual Report 2019

accrued liabilities both representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers on a continued basis.

As of December 31, 2019, the Partnership had regulatory liabilities of $29 million largely related to estimated costs associated with future removal of transmission and gathering facilities or allowed by FERC to be collected in depreciation rates (also known as “negative salvage”) (2018 - $27 million).

Impairment of Goodwill, Long-Lived Assets and Equity Investments

Goodwill

We test goodwill for impairment annually based on ASC 350 – Intangibles – Goodwill and Other, or more frequently if events or changes in circumstances lead us to believe it might be impaired. We can initially assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired and, if we conclude that there is not a greater than 50 percent likelihood that the fair value of the reporting unit is greater than its carrying value, will then perform the quantitative goodwill impairment test. We can also elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Partnership compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value.

We base these valuations on our projection of future cash flows which involves making estimates and assumptions about:

● discount rates and multiples;

● commodity and capacity prices;

● market supply and demand assumptions;

● growth opportunities;

● output levels;

● competition from other companies;

● regulatory changes; and

● regulatory rate action or settlement.

If our assumptions are not appropriate, or future events indicate that our goodwill is impaired, our net income would be impacted by the amount by which the carrying value exceeds the fair value of reporting unit, to the extent of the balance of goodwill.

2018 Impairment of Goodwill related to Tuscarora

In the fourth quarter of 2018, Tuscarora initiated its regulatory approach in response to the 2018 FERC Actions, resulting in a reduction in its maximum rates. In connection with our annual goodwill impairment analysis, we evaluated Tuscarora’s future revenues as well as changes to other valuation assumptions responsive to Tuscarora’s commercial environment, which included estimates related to discount rates and earnings multiples. In doing so, we incorporated the expected impact of Tuscarora’s regulatory approach in response to the 2018 FERC Actions, in which it elected to make a limited NGA Section 4 filing to reduce its maximum rates and eliminate its deferred income tax balances previously used for rate setting. Additionally, for the year ended December 31, 2018, we considered the outcome of the 2019 Tuscarora Settlement with its customers in our overall conclusion.

Our analysis resulted in the estimated fair value of Tuscarora not exceeding its carrying value, including goodwill. The fair value was measured using a discounted cash flow approach whereby the expected cashflows were discounted using a risk adjusted discount rate to determine fair value.

As a result, we recorded a goodwill impairment charge amounting to $59 million against Tuscarora’s goodwill balance of $82 million. The non-cash impairment charge was recorded in the Impairment of goodwill line on the Consolidated statement of operations and reduced our total consolidated goodwill balance from $130 million to $71 million.

2019 Update

In 2019, based on our qualitative analysis of Tuscarora and North Baja’s current market conditions, which includes consideration of the potential qualitative impact of current year changes in the multiples and discount rate assumptions compared to multiples and discount rate assumptions used in the prior quantitative model, we believe there is a greater than 50 percent likelihood that Tuscarora and North Baja’s estimated fair value exceeded their carrying value. As a result, at December 31, 2019, we have not identified an impairment on the $71 million of goodwill related to Tuscarora ($23 million) and North Baja ($48 million) acquisitions.

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There is a risk that adverse changes in our key assumptions could result in an additional future impairment on Tuscarora’s remaining goodwill of $23 million.

Long-Lived Assets

We assess our long-lived assets for impairment based on ASC 360-10-35 Property, Plant and Equipment – Overall – Subsequent Measurement when events or changes in circumstances indicate that the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows expected to be generated by that asset or asset group is less than the carrying value of the assets, an impairment charge is recognized for the excess of the carrying value over the fair value of the assets. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals as considered necessary.

Our management evaluates changes in our business and economic conditions and their implications for recoverability of our long-lived assets’ carrying values when assessing these assets for impairments. The development of fair value estimates requires significant judgement in estimating future cash flows. In order to determine the estimated future cash flows, management must make certain estimates and assumptions, which include the same factors we consider in our annual impairment test of goodwill such as:

● discount rates and multiples;

● commodity and capacity prices;

● market supply and demand assumptions;

● growth opportunities;

● output levels;

● competition from other companies;

● regulatory changes; and

● regulatory rate action or settlement.

Any changes we make to these estimates and assumptions could materially affect future cash flows, which could result to the recognition of an impairment loss in our Consolidated statement of operations.

As of December 31, 2019, there were no indicators of impairment on our long-lived assets.

2018 Impairment on Bison’s long-lived assets

During the fourth quarter of 2018, Bison received an unsolicited offer from a customer regarding the termination of its contract, which represented approximately 60 percent of Bison’s contracted revenues. Bison and the customer mutually agreed to terms which included a cash payment to Bison of $95.4 million in December 2018 in exchange for the termination of all its contract obligations with Bison. Following the amendment of its tariff to enable this transaction, another customer executed a similar agreement to terminate its contract on Bison in exchange for a lumpsum payment to Bison of approximately $2.0 million in December 2018. At the termination of the contracts, Bison was released from performing any future services with the two customers and as such, the amounts received were recorded in revenue in 2018 and the cash payments were used by the Partnership, together with other cash to pay in full its 2015 Term Loan Facility.

As disclosed under Part 1, Item 1. Business - Customers, Contracting and Demand section, natural gas is currently not flowing on Bison as a result of the relative cost advantage of WCSB and Bakken sourced gas versus Rockies production. Since its inception in January 2011, Bison has not experienced a decrease in its revenue as its original ten-year contracts included ship-or-pay terms that resulted in payment to Bison regardless of gas flows. In 2018, the Partnership expected a significant erosion on the cash flows Bison will generate in the future as a result of the advanced payments to Bison and related cancellation of the above contracts. The customer contract cancellations coupled with the persistence of unfavorable market conditions which have inhibited system flows prompted management to re-evaluate the carrying value of Bison’s long-lived assets.

Although the Partnership continues to explore alternative transportation-related options for Bison, management is currently unable to quantify the future cash flows of a viable operating plan beyond the remaining customer contracts’ expiry in January 2021, and accordingly the Partnership evaluated for impairment the carrying value of its property, plant and equipment on Bison at December 31, 2018. The Partnership will continue to maintain Bison to stand ready for redevelopment and has concluded that the remaining obligations of Bison, primarily in the form of property tax obligations and operating and maintenance costs, exceed the net cash inflows that management currently considers probable and estimable.

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Based on these factors, during the fourth quarter of 2018, the Partnership recognized a non-cash impairment charge of $537 million relating to the remaining carrying value of Bison’s property, plant and equipment after determining that it was no longer recoverable. The non-cash charge was recorded under the Impairment of long-lived assets line on the Consolidated statement of operations.

Equity Investments

We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows which are determined using the same factors we consider in our annual impairment test of goodwill such as:

● discount rates and multiples;

● commodity and capacity prices;

● market supply and demand assumptions;

● growth opportunities;

● output levels;

● competition from other companies;

● regulatory changes; and

● regulatory rate action or settlement.

Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered impairment.

If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.

As of December 31, 2019, no impairment charge has been recorded related to our equity investments.

2018 Quantitative Assessment of Great Lakes’ Fair Value

At December 31, 2018, the equity method goodwill balance related to Great Lakes amounted to $260 million (December 31, 2017- $260 million). The equity method goodwill relates to the Partnership’s February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes and is the difference between the carrying value of our investment in Great Lakes and the underlying equity in Great Lakes’ net assets.

During the fourth quarter of 2018, Great Lakes finalized its regulatory approach in response to the 2018 FERC Actions and elected to make a limited NGA section 4 filing with FERC to reduce its maximum rates and eliminate its tax allowance and deferred income tax balances previously used for rate setting. As a result of this action, and because the estimated fair value of our investment in Great Lakes exceeded its carrying value by less than ten percent in its 2017 valuation, we performed a quantitative test to determine if there was an other than temporary decline in Great Lakes’ fair value. The assumptions we used in our analysis related to the estimated fair value of our equity investment in Great Lakes included expected results from its limited NGA Section 4 filing with FERC, revenue opportunities on the system as well as changes to other valuation assumptions responsive to Great Lakes’ commercial environment, which includes estimates related to discount rates and earnings multiples. At December 31, 2018, we concluded the estimated fair value of our investment in Great Lakes exceeded its carrying value by more than ten percent.

2019 update

During the year ended December 31, 2019, Great Lakes’ current market conditions and other factors relevant to Great Lakes’ long-term financial performance have remained relatively stable. There is a risk that reductions in future cash flow forecasts or adverse changes in other key assumptions could result in an additional future impairment of the carrying value of our investment in Great Lakes.

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Contingencies

Our pipeline systems’ accounting for contingencies covers a variety of business activities, including contingencies that could arise from legal and environmental liabilities. Our pipeline systems accrue for these contingencies when their assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with ASC 450 – Contingencies. Our pipeline systems base their estimates on currently available facts and their estimates of the ultimate outcome or resolution. Actual results may differ from our estimates or additional facts and circumstances cause us to revise our estimates resulting in an impact, positive or negative, on earnings and cash flow.

At December 31, 2019, the Partnership is not aware of any contingent liabilities that would have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

RELATED PARTY TRANSACTIONS

Please read Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence” and Note 17 within Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more information regarding related party transactions.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

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

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

We record derivative financial instruments on the balance sheet as assets and liabilities at fair value. We estimate the fair value of derivative financial instruments using available market information and appropriate valuation techniques. Changes in the fair value of derivative financial instruments are recognized in earnings unless the instrument qualifies as a hedge and meets specific hedge accounting criteria. Qualifying derivative financial instruments’ gains and losses may offset the hedged items’ related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge.

MARKET RISK

From time to time, and in order to finance our business and that of our pipeline systems, the Partnership and our pipeline systems issue debt to invest in growth opportunities and provide for ongoing operations. The issuance of debt exposes the Partnership and our pipeline systems to market risk from changes in interest rates which affect earnings and the value of the financial instruments we hold.

Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.

LIBOR, which is set to be phased out at the end of 2021, is used as a reference rate for certain of our financial instruments, including the Partnership's term loans, revolving credit facilities and the interest rate swap agreements that we use to manage our interest rate exposure. We are reviewing how the LIBOR phase-out will affect the Partnership, but we currently do not expect the impact to be material.

As of December 31, 2019, the Partnership’s interest rate exposure resulted from our floating rate on North Baja’s Unsecured Term Loan Facility, PNGTS’ Revolving Credit Facility and Tuscarora’s Unsecured Term Loan Facility, under which $112 million, or 6 percent, of our outstanding debt was subject to variability in LIBOR interest rates (December 31, 2018 - $168 million or 8 percent).

As of December 31, 2019, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 3.26 percent. If interest rates hypothetically increased (decreased) on these facilities by one percent (100 basis points), compared with rates in effect at December 31, 2019, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $1 million.

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As of December 31, 2019, $115 million, or 32 percent, of Northern Border’s outstanding debt was at floating rates.

If interest rates hypothetically increased (decreased) by one percent (100 basis points), compared with rates in effect at December 31, 2019, Northern Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately $1 million.

GTN’s Unsecured Senior Notes, Northern Border’s and Iroquois’ Senior Notes, and all of Great Lakes’ Notes represent fixed-rate debt; therefore, they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison, as it currently does not have any debt.

The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to assist in managing exposures to market risk resulting from these activities within established policies and procedures. Derivative contracts used to manage market risk generally consist of the following:

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

● Options – contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period.

The Partnership and our pipeline systems enter into interest rate swaps and option agreements to mitigate the impact of changes in interest rates. For details regarding our current interest swaps and other agreements related to mitigation of impact on changes in interest rates, see Note 20- Fair Value Measurements within Part IV, Item 15. “Exhibits and Financial Statement Schedules," which information is incorporated herein by reference.

COMMODITY PRICE RISK

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

COUNTERPARTY CREDIT RISK AND LIQUIDITY RISK

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

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

● cash and cash equivalents;

● accounts receivable and other receivables; and

● the fair value of derivative assets.

At December 31, 2019, we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired. Additionally, during year ended December 31, 2019 and at December 31, 2019, no customer accounted for more than 10 percent of our consolidated revenue and accounts receivable, respectively.

The Partnership and our pipeline systems have significant credit exposure to financial institutions as they hold cash deposits and provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy customers. The Partnership closely monitors the creditworthiness of our counterparties, including financial institutions, reviews accounts receivable regularly and, if needed, records allowances for doubtful accounts using the specific identification method. However, we cannot predict to what extent our business would be impacted by uncertainty in energy commodity prices, including possible declines in our customers' creditworthiness. Refer to Note 17 - Transactions with major customers within Part IV, Item 15. “Exhibits and Financial Statement Schedules” for more information. See also Part I, Item 1. "Business Customers, Contracting and Demand” section for more information on certain customers.

Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they become due. We manage our liquidity risk by continuously forecasting our cash flow on a regular basis to ensure we have adequate cash balances, cash flow from operations and credit facilities to meet our operating, financing and capital expenditure obligations when due, under both normal and stressed conditions. Refer to "Liquidity and Capital Resources" section for more information about our liquidity.

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At December 31, 2019, the Partnership had a Senior Credit Facility of $500 million maturing in 2021 with no outstanding balance. At December 31, 2019, PNGTS has a $125 million Revolving Credit Facility maturing in 2023 and has an outstanding balance of $39 million and finally, at December 31, 2019, Northern Border had a committed revolving bank line of $200 million maturing in 2024 and $115 million was drawn. The Partnership’s Senior Credit Facility, PNGTS’ Revolving Credit Facility and the Northern Border’s Credit Facility have accordion features for additional capacity of $500 million, $50 million and $200 million respectively, subject to lender consent.

Item 8. Financial Statements and Supplementary Data

The financial statements required by this item are included in Part IV, Item 15 of this report on page F-1 and are incorporated herein by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As required by Rule 13a-15(e) under the Exchange Act, the management of our General Partner, including the principal executive officer and principal financial officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. The Partnership’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives. Based upon and as of the date of the evaluation, the management of our General Partner, including the principal executive officer and principal financial officer, concluded that the Partnership’s disclosure controls and procedures as of the end of the year covered by this annual report were effective to provide reasonable assurance that the information required to be disclosed by the Partnership in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the Exchange Act), is (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (b) accumulated and communicated to the management of our General Partner, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

During the year ended December 31, 2019, there was no change in the Partnership’s internal control over financial reporting that materially impacted or is reasonably likely to materially impact our internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange Act. Internal control over financial reporting, no matter how well designed, has inherent limitations and can only provide reasonable assurance with respect to the preparation and fair presentation of published financial statements. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on our assessment according to the above framework, management has concluded that our internal control over financial reporting was effective as of December 31, 2019 at providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. No material weaknesses were identified.

Our independent registered public accounting firm, KPMG LLP (KPMG), independently assessed the effectiveness of the Partnership’s internal control over financial reporting. KPMG has issued an attestation report concurring with management’s assessment, which is included starting on page F-2 of the financial statements included in this Form 10-K.

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Item 9B. Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

The Partnership is a limited partnership and as such has no officers, directors or employees. Set forth below is certain information concerning the directors and officers of the General Partner who manage the operations of the Partnership as of February 20, 2020. Directors are appointed by the General Partner’s sole stockholder to serve one-year terms or until their successors are appointed. All officers of the General Partner serve at the discretion of the board of directors of the General Partner which is an indirect wholly-owned subsidiary of TC Energy.

Name	Age	Position with General Partner
Stanley G. Chapman, III	54	Chair and Director
Jack F. Stark	69	Independent Director
Malyn K. Malquist	67	Independent Director
Walentin (Val) Mirosh	74	Independent Director
Nathaniel A. Brown	43	President, Principal Executive Officer and Director
Nadine E. Berge	47	Director
Sean M. Brett	54	Director
Janine M. Watson	50	Vice-President and General Manager
Alisa Williams	36	Vice-President, Taxation
Jon A. Dobson	53	Secretary
Burton D. Cole	45	Controller
William C. Morris	57	Principal Financial Officer, Vice-President and Treasurer

Mr. Chapman has served as a director and Chair of the Board of Directors of the General Partner since January 1, 2019. Mr. Chapman’s principal occupation is Executive Vice-President and President, U.S. Natural Gas Pipelines of TC Energy, a position he has held since April 2017. He is responsible for all pipeline operations and commercial activities across TC Energy's FERC-regulated transmission and storage assets. Mr. Chapman joined TC Energy as part of its acquisition of the Columbia Pipeline Group (Columbia) in July 2016 and served as Senior Vice President and General Manager of TC Energy’s FERC-regulated US natural gas pipeline business from July 2016 to April 2017. Prior to joining TC Energy, Mr. Chapman held several positions at Columbia from December 2011 to July 2016, most recently as Executive Vice-President and Chief Commercial Officer. Before joining Columbia, Mr. Chapman held various positions of increasing responsibility with El Paso Corp and Tenneco Energy and was responsible for various marketing and commercial operations, as well as supply, regulatory, business development and optimization activities. His industry knowledge, management experience and leadership skills are highly valuable in developing and implementing our business strategies and assessing accompanying risks.

Mr. Stark has served as a director and member of the audit and conflicts committee of the board of directors of the General Partner since July 1999. Mr. Stark currently serves as the Chief Financial Officer of Generate Capital Inc., a clean energy financing company. He previously served as Chief Financial Officer of Imergy Power Systems, formerly Deeya Energy, an energy storage systems company, from December 2013 to July 2016. Mr. Stark was the Chief Financial Officer of BrightSource Energy Inc., a provider of technology for use in large-scale solar thermal power plants, from May 2007 to November 2013 and Chief Financial Officer of Silicon Valley Bancshares, a diversified financial services provider, from April 2004 to May 2007. Prior to May 2007, Mr. Stark held chief financial officer positions at Itron Inc., Silicon Energy Corporation and GATX Capital as well as senior management roles at PG&E Corporation for more than 20 years. Mr. Stark previously served as a director, Chairman of the Board and member of the audit committee of the board of directors of Washington Gas Light Company, a regulated natural gas utility. He also serves on the board of directors of AltaGas Services (U.S.) Inc. (ASUS), a wholly-owned subsidiary of AltaGas Ltd., and AltaGas Utility Holdings (U.S.) Inc., a wholly owned subsidiary of ASUS. From November 2015 to October 2017, he served as a director of TerraForm Power, Inc. and TerraForm Global, Inc., where he also served on the compensation and audit committees of both companies. Through his roles as chief financial officer of numerous companies, Mr. Stark brings valuable financial expertise and management experience, including extensive knowledge regarding financial operations, investor relations, finance, energy risk management, regulatory affairs and knowledge of the natural gas industry. Mr. Stark’s prior audit committee experience further enhances his qualifications to serve as a member of our Board and our Audit Committee.

Mr. Malquist has served as a director, Chair of the audit committee and member of the conflicts committees of the board of directors of the General Partner since April 2011. Mr. Malquist is an executive with more than 30 years of experience

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serving in a variety of business, operations and financial roles. Mr. Malquist served on the board of directors and audit committee of Headwaters Incorporated (Headwaters), an NYSE-listed company that provides products, technologies and services in the light building products, heavy construction materials and energy industries, from January 2003 to May 2017, when Headwaters was acquired by Boral, Ltd. From September 2002 to March 2009, Mr. Malquist held various senior executive positions with Avista Corporation (Avista), an energy production, transmission and distribution company, including Senior Vice President from September 2002 to May 2006, Executive Vice President from May 2006 to March 2009, Chief Financial Officer from November 2002 to September 2008 and Treasurer from February 2004 to January 2006. Prior to his employment at Avista, Mr. Malquist held various positions at Sierra Pacific Resources, (electricity provider), including President, Chief Executive Officer and Chief Operating Officer from January 1998 to April 2000 and various Senior Vice-President positions from 1994 to 1998. Through his extensive prior management experience, including serving as chief financial officer and chief executive officer of various energy companies, Mr. Malquist brings extensive knowledge regarding financial operations, energy risk management and knowledge of the energy industry to the Board of Directors and the Audit Committee. His valuable management and financial expertise include an understanding of the accounting and financial matters that the Partnership and industry address on a regular basis. In addition, Mr. Malquist’s experience in the energy industry is beneficial to the service he provides to the Board of Directors.

Mr. Mirosh has served as a director and member of the audit and conflicts committees of the board of directors of the General Partner since September 2004. Mr. Mirosh’s principal occupation is President of Mircan Resources Ltd., (private consulting company), a position he has held since 2009. From April 2008 to December 2009, he was Vice-President and Special Advisor to the President and Chief Operating Officer of NOVA Chemicals Corporation (NOVA), a commodity chemicals and plastics company. From July 2003 to April 2008, Mr. Mirosh was President of Olefins and Feedstocks, a division of NOVA. Prior to joining NOVA, Mr. Mirosh was a partner at Macleod Dixon law firm. Mr. Mirosh is also a director of Murphy Oil Corporation (an international oil and gas company). Mr. Mirosh’s extensive experience in the natural gas transmission sector enhances the knowledge of the Board in this area of the industry. As a current and former executive and director of various companies, his breadth of experience is applicable to many of the matters routinely facing the Partnership. Moreover, Mr. Mirosh’s experience and industry knowledge are complemented by an engineering educational background and legal experience, are beneficial to the Board of Directors and Audit Committee on a full range of business, financial, technical and professional matters.

Mr. Brown has served as President, Principal Executive Officer and a director of the General Partner since May 1, 2018. He previously served as Controller and Principal Financial Officer of the General Partner from May 2014 to May 2018. His principal occupation is Vice-President, U.S. Natural Gas Pipelines Financial Services of TransCanada USA Services Inc., an indirect wholly owned subsidiary of TC Energy (“TC USA”), a position he has held since February 2018. In this position, he is responsible for the accounting, financial reporting, planning and budgeting of TC Energy’s U.S. natural gas pipelines. Mr. Brown also served as Director of Financial Services for TC Energy’s U.S. Pipelines from May 2014 to February 2018 and Manager of Accounting for TC Energy’s U.S. Pipelines West from November 2009 to May 2014. Prior to joining TC Energy, Mr. Brown spent eight years in public accounting, most recently as an audit manager for Grant Thornton LLP and Ernst & Young.

Ms. Berge has been a director of the General Partner since May 2018. Ms. Berge's principal occupation is Director, Corporate Compliance and Legal Operations with TC Energy, a position she has held since December 2014. Ms. Berge has served in several positions of increasing responsibility in the legal department since joining TC Energy in May 2005. Ms. Berge is responsible for directing the corporate compliance area across Canada, the US and Mexico, as well as leadership of operational matters for the TC Energy legal department in all three jurisdictions. Prior to joining TC Energy, Ms. Berge spent five years practicing law in the area of energy regulation. Ms. Berge brings valuable legal skills and experience to the Board of Directors.

Mr. Brett has served as a director of the General Partner since May 2018. Mr. Brett's principal occupation is Senior Vice-President, Power and Storage with TC Energy, a role he has held since January 2019 and in which he is responsible for all aspects of TC Energy’s Power and Storage business, including strategy, commercial, business development, projects and operations. Mr. Brett joined TC Energy in March 1997 and held several positions of increasing responsibility prior to his current role, including Vice-President, Power and Storage from June 2018 to January 2019, Vice-President, Risk Management from August 2015 to June 2018 and Vice President and Treasurer from July 2010 to August 2015. Mr. Brett also previously served as Vice President, Commercial Operations of the General Partner from December 2009 to July 2010 and as Treasurer of the General Partner from January 2007 to December 2008. Mr. Brett’s familiarity with the Partnership and TC Energy and his breadth of experience are highly valuable to the Board of Directors and are useful in assessing our business strategies and accompanying risks.

Ms. Watson has served as Vice-President and General Manager for the General Partner since October 2015. Her principal occupation is Director, LP Management & Pricing for TC Energy, a position she has held since October 2015. Ms. Watson joined TC Energy in 1997 and has served in progressively senior positions in the natural gas pipeline and energy business segments of TC Energy prior to her current position, most recently as Associate General Counsel, Energy Law. Prior to joining TC Energy, Ms. Watson practiced law at the Calgary office of McCarthy Tétrault and clerked at the Alberta Court of Appeal.

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Ms. Williams has served as Vice-President, Taxation of the General Partner since July 2019. Her principal occupation is Director, U.S. Income Taxation of TC USA, in which role she leads the U.S. tax group and is responsible for providing tax administration, tax planning, regulatory and accounting support for TC Energy’s U.S. subsidiaries. Ms. Williams joined TC Energy in July 2018 as the Manager of Tax Reporting until she was appointed Director, US Taxation in July 2019. Prior to joining TC Energy, Ms. Williams spent more than a decade in public accounting and private industry, most recently as Manager, Federal Income Tax for CITGO Petroleum Corporation from April 2018 to July 2018 and as Tax Manager, Income Tax Services for Enbridge Inc. (formerly Spectra Energy Corp) from May 2011 to April 2018.

Mr. Dobson has served as Secretary of the General Partner since May 2014, prior to which he served as Assistant Secretary of the General Partner from April 2012. Mr. Dobson’s principal occupation is Director, U.S. Governance and Securities Law of TC USA and Corporate Secretary for TC Energy’s U.S. subsidiaries. Prior to joining TC Energy in January 2011, Mr. Dobson spent 18 years practicing law in corporate and law firm positions, including Vice President and Assistant General Counsel of Nash Finch Company; Vice President, General Counsel and Secretary of BMC Industries, Inc.; and associate attorney at Lindquist & Vennum, PLLP.

Mr. Cole has served as Controller of the General Partner since July 2019. His principal occupation is Director, U.S. Accounting of TC USA, a position he has held since November 2018 and in which he leads the accounting and financial reporting group and supports the commercial, compliance and regulatory functions for TC Energy’s U.S. natural gas pipelines. Prior to joining TC Energy, Mr. Cole spent more than two decades in public accounting and private industry positions, including Vice President, Chief Accounting Officer of Talos Energy Inc. from April 2018 to September 2018, Vice President, Finance of Speargrass Oil & Gas, LLC from April 2017 to March 2018 and various positions of increasing responsibility at Spectra Energy Corp, most recently as General Manager, Credit and Enterprise Risk from January 2014 to March 2017 and Corporate Controller from March 2011 to January 2014.

Mr. Morris has served as Vice-President, Principal Financial Officer and Treasurer of the General Partner since February 2018. Mr. Morris previously served as Vice President and Treasurer of the General Partner from November 2017 to February 2018 and as Treasurer of the General Partner from 2012 to November 2017. Mr. Morris’ principal occupation is Director, Finance of TC Energy, a position he has held since November 2012. In this role, he is responsible for the development, execution and monitoring of TC Energy’s financing strategy. Mr. Morris joined TC Energy in 1996 and has held various positions of increasing responsibility, including manager, Risk Management, and Director of Risk Management. Prior to joining TC Energy, Mr. Morris spent 12 years in the public accounting and banking industries.

GOVERNANCE MATTERS

We are a limited partnership and a ‘controlled company’ as that term is used in NYSE Rule 303A.00, because all of our voting shares are owned by the General Partner. As such, the NYSE listing standards do not require that we or the General Partner have a majority of independent directors or a nominating or compensation committee of the General Partner’s board of directors.

The NYSE listing standards require our principal executive officer to annually certify that he is not aware of any violation by the Partnership of the NYSE corporate governance listing standards. The most recent certification was provided to the NYSE on March 20, 2019.

AUDIT COMMITTEE FINANCIAL EXPERT

The board of directors of the General Partner has determined that Malyn Malquist and Jack Stark are “audit committee financial experts,” are “independent” and are “financially sophisticated” as defined under applicable SEC rules and NYSE Corporate Governance Standards. The board’s affirmative determination for both Malyn Malquist and Jack Stark was based on their respective education and extensive experience as chief financial officers for corporations that presented a breadth and level of complexity of accounting issues that are generally comparable to those of the Partnership.

CODE OF ETHICS AND CORPORATE GOVERNANCE GUIDELINES

The Partnership believes that director, management and employee honesty and integrity are important factors in ensuring good corporate governance. The directors, officers, employees and contractors of the General Partner are subject to TC Energy’s Code of Business Ethics (COBE), which also has been adopted for the Partnership by our General Partner. Our COBE is published on our website at www.tcpipelineslp.com. If any substantive amendments are made to the COBE for senior officers or if any waivers are granted, the amendment or waiver will be published on the Partnership’s website or filed in a report on Form 8-K.

We also have a statement of Corporate Governance Guidelines that sets forth the expectation of how our Board of Directors should function and its position with respect to key corporate governance issues. A copy of the Corporate Governance Guidelines is available on our website at www.tcpipelineslp.com. If any amendments are made to the

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Corporate Governance Guidelines, the amendment will be published on the Partnership’s website or filed in a report on Form 8-K.

AUDIT COMMITTEE

The General Partner of the Partnership has a separately designated audit committee consisting of three independent Board members. The members of the Audit Committee are Malyn Malquist, as Chair, Jack Stark and Walentin (Val) Mirosh. All members of the Audit Committee meet the criteria for independence and experience requirements of the NYSE and the Exchange Act. None of the Audit Committee members have participated in the preparation of the financial statements of the Partnership or any of its subsidiaries at any time during the past three years. In addition, all members of the Audit Committee are financially literate.

The Audit Committee has adopted a charter which specifically provides that it is responsible for the appointment, compensation, retention and oversight of the independent public accountants engaged in preparing and issuing the Partnership’s audit report, that the Audit Committee has the authority to engage independent counsel and other advisors as it determines necessary to carry out its duties and for the committee to be responsible for establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters, including procedures for the confidential, anonymous submission by employees of the General Partner of concerns regarding questionable accounting or auditing matters. The Audit Committee has adopted TC Energy’s Ethics Help-Line in fulfillment of its responsibility to establish a confidential and anonymous whistle blowing process. The toll-free Ethics Help-Line number and the Audit Committee’s charter are published on the Partnership’s website at www.tcpipelineslp.com.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

The Board of Directors of our General Partner does not have a separate compensation committee, nor does it make any determination with respect to the amount of compensation to be paid to our executive officers.

EXECUTIVE SESSIONS OF NON-MANAGEMENT DIRECTORS

The independent directors of the General Partner meet at regularly scheduled executive sessions without management and non-independent directors. Jack Stark serves as the presiding director at those executive sessions. Persons wishing to communicate with the General Partner’s independent directors may do so by writing in care of Secretary, Board of Directors, TC PipeLines, GP, Inc., 700 Louisiana Street, Suite 700, Houston, TX 77002.

Item 11. Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS

We are a master limited partnership and are managed by the executive officers of our General Partner. We do not directly employ any of the individuals responsible for managing or operating our business. The executive officers of our General Partner are compensated directly by TC Energy.

The compensation policies and philosophy of TC Energy govern the types and amount of compensation granted to each of the named executive officers. Since these policies and philosophy are those of TC Energy, we refer you to a discussion of those items as set forth in the Executive Compensation section of the TC Energy “Management Information Circular” on the TC Energy website at www.tcenergy.com. The TC Energy “Management Information Circular” is prepared by TC Energy pursuant to applicable Canadian securities regulations and is not incorporated into this document by reference or deemed furnished or filed by us under the Securities Exchange Act of 1934, as amended; rather the reference is to provide our investors with an understanding of the compensation policies and philosophy of the ultimate parent of our General Partner.

The Board of Directors of our General Partner does not have a separate compensation committee, nor does it make any determination with respect to the amount of compensation to be paid to our executive officers. The Board of our General Partner does have responsibility for evaluating and determining the reasonableness of costs allocated to us for managerial, administrative and operational support provided by TC Energy and its affiliates, including our General Partner. We reimburse TC Energy for a percentage of the compensation, including base salary and certain benefit expenses related to the officers of our General Partner and employees of TC Energy who perform services on our behalf. The total compensation that are allocable to us vary for each officer or employee performing services on our behalf and are based on the estimated amount of time an employee devotes to matters related to our business as compared to the amount of time such employee devotes to matters related to the business of TC Energy and its other affiliates. The Board of Directors of our General Partner specifically approves the percentage allocation to the Partnership of the compensation

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of the executive officers of the General Partner on an annual basis. Please read Part III, Item 13. “Certain Relationships and Related Transactions, and Director Independence” for more information regarding this arrangement.

Compensation Committee Report

Neither we, nor our General Partner, have a compensation committee. The board of directors of our General Partner has reviewed and discussed the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.

The board of directors of TC PipeLines GP, Inc:

Nadine E. Berge

Sean M. Brett

Nathaniel A. Brown

Stanley G. Chapman, III

Malyn K. Malquist

Walentin (Val) Mirosh

Jack F. Stark

The following table summarizes the allocation percentages and amounts of the base salary and benefits charged to the Partnership in 2019, 2018 and 2017, as applicable, for the individuals serving as our President and Principal Executive Officers during 2019, Vice President, Principal Financial Officer and Treasurer and other executive officers of our General Partner for whom the salaries and benefits allocations to us exceeded $100,000.

Summary Compensation Table

				Total
		Approximate		Compensation
		Percentage of		allocated to the
		Time Devoted to		Partnership(a)
Name and Principal Position	Year	the Partnership		(in US dollars)
Nathaniel A. Brown(b)	2019	35	%	177,755
President and Principal Executive Officer	2018	35	%	156,986
	2017	35	%	121,737
William C. Morris (c) (e)	2019	50	%	172,165
Vice‑President, Principal Financial Officer and Treasurer	2018	50	%	169,280
	2017	50	%	163,891
Janine Watson(e)	2019	50	%	185,613
Vice‑President and General Manager	2018	50	%	182,504
	2017	50	%	170,244
Jon A. Dobson	2019	60	%	238,074
Secretary	2018	60	%	268,024
	2017	60	%	253,793
Burton D. Cole(d)	2019	35	%	134,693
Controller and Principal Accounting Officer	2018	—		—
	2017	—		—

(a) Amounts presented are based on the amount of reimbursement made by the Partnership to TC Energy representing base salary and benefits rate allocations from TC Energy to the Partnership for the year indicated and is based on the percentage of the applicable officer’s time devoted to the Partnership. The benefit reimbursement is based on the total monthly or annual base salary allocated to the Partnership multiplied by a factor applicable to benefits of US and Canadian employees.

(b) Appointed as President and Principal Executive Officer effective May 1, 2018. The total compensation allocated to the Partnership in 2018 includes salary as Controller and Principal Financial Officer of the Partnership from January 1, 2018-April 30, 2018.

(c) Appointed as Vice-President, Principal Financial Officer and Treasurer effective May 1, 2018. The total compensation allocated to the Partnership in 2018 includes salary as Vice-President and Treasurer of the Partnership from January 1, 2018 - April 30, 2018.

(d) Appointed as Controller, Principal Accounting Officer effective July 1, 2019. The total compensation presented here is his total compensation allocated to the Partnership in for the full year of 2019.

(e) Amounts presented have been converted to U.S. Dollars from Canadian dollars using the average exchange rate for the applicable year.

TC PipeLines, LP Annual Report 2019    69

Independent Director Compensation^(a)

	Fees Earned	Deferred
For the year ended December 31, 2019	or Paid in	Share Unit
(in dollars)	Cash	Awards(b)	Total
Malyn K. Malquist(c)	95,000	80,000	175,000
Jack F. Stark(d)	95,000	80,000	175,000
Walentin (Val) Mirosh(e)	80,000	80,000	160,000

(a) Employee directors do not receive any additional compensation for serving on the board of directors of our General Partner; therefore, no amounts are shown for employee directors. Amounts paid as reimbursable business expenses to each director for attending board functions are not reflected in this table. Our General Partner does not consider the directors’ reimbursable business expenses for attending board functions and other business expenses required to perform board duties to have a personal benefit and thus be considered a perquisite.

(b) Amounts presented reflect the compensation expense recognized pursuant to FASB ASC Topic 718 related to the deferred share units (DSUs) granted during 2019 under the DSU Plan. All of the DSUs granted to Messrs. Malquist, Stark and Mirosh were outstanding at December 31, 2019.

At December 31, 2019, Mr. Malquist, Mr. Stark and Mr. Mirosh held 19,880, 28,502 and 20,758 DSUs, respectively. The fair market value of the DSUs held by Mr. Malquist, Mr. Stark and Mr. Mirosh at December 31, 2019 was $840,930, $1,205,627 and $878,072, respectively. These amounts include distribution like payments credited to each independent director’s DSU account equal to the distributions payable on the Partnership’s common units multiplied by the number of DSU’s in the director’s account. In this regard, Mr. Malquist was credited 1,296 DSUs, Mr. Stark was credited 1,897 DSUs and Mr. Mirosh was credited 1,357 DSUs. All DSUs credited during 2019 were outstanding at December 31, 2019.

(c) Chair of the Audit Committee. Cash payments to Mr. Malquist include the $70,000 annual cash retainer, $15,000 Audit Committee Chair retainer and $10,000 of committee member retainer.

(d) Lead Independent Director and Chair of the Conflicts Committee. Cash payments to Mr. Stark include the $70,000 annual cash retainer, $15,000 Conflicts Committee Chair retainer and $10,000 of committee member retainer.

(e) Cash payments to Mr. Mirosh include the $70,000 annual cash retainer and $10,000 of committee member retainer.

Cash Compensation

In 2019, each director who was not an employee of TC Energy, the General Partner or its affiliates (independent director) was entitled to a directors’ retainer fee of $150,000 per annum, of which $80,000 was automatically granted in DSUs (see Deferred Share Units section below). The independent director appointed as Lead Independent Director and Chair of the Conflicts Committee and the independent director appointed as Chair of the Audit Committee were each entitled to an additional fee of $15,000 per annum. Each independent director was also paid a committee member retainer of $5,000 for participating in each committee. The independent directors are reimbursed for out-of-pocket expenses incurred in the course of attending such meetings. All fees are paid by the Partnership on a quarterly basis. The independent directors are permitted to elect to receive any portion of their cash fees in the form of DSUs pursuant to the DSU Plan.

Deferred Share Units

The DSU Plan was established in 2007 with the first grant occurring in January 2008. The DSU Plan was amended and restated in its entirety effective as of January 1, 2014. In 2019, as part of the retainer fee, each independent director received quarterly automatic grants of DSUs valued at $20,000 each for a total annual grant value of $80,000.

At the time of grant, the value of a DSU is equal to the market value of one common unit of the Partnership at the time the DSU is credited to the independent director’s account. The value of a DSU when redeemed is equivalent to the market value of one common unit of the Partnership at the time the redemption takes place. DSUs cannot be redeemed until the director ceases to be a member of the Board. Directors may redeem DSUs for cash or common units purchased in the open market through a broker at their option.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth information as of February 19, 2020 regarding the (i) beneficial ownership of our common units and shares of TC Energy by the General Partner’s directors, the named executive officers and directors and

70    TC PipeLines, LP Annual Report 2019

executive officers as a group and (ii) beneficial ownership of our common units by all persons known by the General Partner to own beneficially at least five percent of our common units.

	Amount and Nature of Beneficial Ownership
	TC PipeLines, LP		TC Energy Corporation
	Number of	Per cent	Common	Per cent
Name and Business Address	Units(a)	of Class(b)	Shares	of class
TransCan Northern Ltd(c)
450-1st Street SW	11,287,725	15.8	—	—
Calgary, Alberta T2P 5H1
TC Pipelines GP, Inc.(d)
450-1st Street SW	5,797,106	8.1	—	—
Calgary, Alberta T2P 5H1
ALPS Advisors, Inc.(e)
1290 Broadway, Suite 1100	6,466,808	9.07	—	—
Denver, CO 80203
First Trust Portfolios LP(f)
120 East Liberty Drive, Suite 400	6,649,340	9.33
Wheaton, Illinois 60187
Energy Income Partners, LLC(g)
10 Wright Street	8,425,884	11.8
Westport, Connecticut 06880
Invesco Ltd.(h)
1555 Peachtree Street NE, Suite	7,764,229	10.9
1800
Atlanta, GA 30309
Malyn K. Malquist(i)	21,194	*	—	—
Jack F. Stark(j)	29,242	*	—	—
Walentin (Val) Mirosh(k)	21,087	*	995	*
Stanley G. Chapman, III (l)	—	—	133,539	*
Nadine E. Berge(m)	—	—	273	*
Sean M. Brett(n)	—	—	78,796	*
Nathaniel A. Brown(o)	—	—	6,117	*
Burton D. Cole	—	—	—	—
Jon A. Dobson	—	—	—	*
William C. Morris(p)	—	—	20,277	*
Janine M. Watson(q)	—	—	129	*
Directors and Executive officers as a Group(r) (13 people)	71,523	*	240,126	*

(a) A total of 71,306,396 common units are issued and outstanding. For certain beneficial owners, the number of common units includes DSUs, which are a bookkeeping entry, equivalent to the value of a Partnership common unit, and do not entitle the holder to voting or other unitholder rights, other than the accrual of additional DSUs for the value of distributions. A director cannot redeem DSUs until the director ceases to be a member of the Board. Directors can then redeem their units for cash or common units.

(b) Any DSUs shall be deemed to be outstanding for the purpose of computing the percentage of outstanding common units owned by such person, but shall not be deemed to be outstanding for the purpose of computing the percentage of common units by any other person.

(c) TransCan Northern Ltd. is a wholly-owned indirect subsidiary of TC Energy.

(d) TC PipeLines GP, Inc. is a wholly-owned indirect subsidiary of TC Energy and also owns a two percent general partner interest of the Partnership.

(e) Based on a Schedule 13G/A filed with the SEC on February 7, 2020 by ALPS Advisors, Inc. In this Schedule 13G/A ALPS Advisors, Inc. disclaims beneficial ownership, and has shared power to vote and to dispose of the 6,466,808 common units.

(f) Based on Schedule 13G/A filed with the SEC on January 31, 2020 jointly by First Trust Portfolios LP, First Trust Advisors L.P. and The Charger Corporation. In this Schedule 13G, First Trust Advisors L.P. and The Charger Corporation have shared power to vote 6,649,340 common units and shared power to dispose of 6,655,236 common units, and First Trust Portfolios LP, First Trust Advisors L.P. and The Charger Corporation. disclaim beneficial ownership of all of said common units.

(g) Based on Schedule 13G/A filed with the SEC on February 14, 2020 by Energy Income Partners, LLC. In this Schedule 13G/A, Energy Income Partners LLC has shared power to vote and to dispose of the 8,425,884 common units.

(h) Based on a Schedule 13G/A filed with the SEC on February 7, 2020 by Invesco Ltd. In this Schedule 13G/A Invesco Ltd. disclaims beneficial ownership, and has shared power to vote 7,764,229 common units and shared power to dispose of 7,685,760 common units.

(i) Includes 20,194 DSUs and 1,000 common units of the Partnership.

(j) Includes 28,952 DSUs and 290 common units of the Partnership.

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(k) Includes 21,087 DSUs and 995 TC Energy common shares.

(l) Includes 109,832 options exercisable within 60 days for TC Energy common shares and 23,707 TC Energy common shares held directly by Mr. Chapman.

(m) Includes 273 TC Energy common shares held in her Employee Share Savings Plan account.

(n) Includes 62,202 options exercisable within 60 days for TC Energy common shares, 3,500 TC Energy common shares held in his Employee Share Savings Plan accounts, 4,494 TC Energy common shares held directly and 8,600 TC Energy shares held by Mr. Brett’s mother, of which he disclaims beneficial ownership.

(o) Includes 6,117 options exercisable within 60 days for TC Energy common shares.

(p) Includes 9,957 TC Energy common shares held in his Employee Share Savings Plan account and 10,320 TC Energy common shares held jointly with his spouse.

(q) Includes 129 TC Energy common shares held in her Employee Share Savings Plan account.

(r) Includes 70,233 DSUs and 1,290 common units of the Partnership, 21,196 TC Energy common shares held directly, 10,320 TC Energy common shares held with a spouse, 178,151 options exercisable within 60 days for TC Energy common shares, 8,600 TC Energy common shares owned by immediate family members of which beneficial ownership of such common shares is disclaimed, and 13,859 TC Energy common shares held in the TC Energy Employee Share Savings Plan

*       Less than one percent.

Item 13. Certain Relationships and Related Transactions, and Director Independence

As of February 19, 2020, subsidiaries of TC Energy own 17,084,831, or approximately 24 percent, of our outstanding common units, including 5,797,106 common units held by the General Partner. In addition, the General Partner owns 100 percent of our IDRs and a two percent general partner interest in the Partnership through which it manages and operates the Partnership. TC Energy also owns 100 percent of our Class B units. For more details regarding the Class B units, see Note 11 within Part IV, Item 15. “Exhibits and Financial Statement Schedules.”

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments made or to be made by us to our General Partner and its affiliates, which includes TC Energy, in connection with the ongoing operation and, if applicable, upon liquidation of the

72    TC PipeLines, LP Annual Report 2019

Partnership. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arms-length negotiations.

Operational Stage
Distributions of average Cash to our General Partner and its affiliates	We generally make cash distributions of 98 percent to common unitholders, including our general partner with its affiliates as holders of an aggregate of 17,084,831 common units, and the remaining two percent to our General Partner. Additionally, the Class B units entitle TC Energy to receive an annual distribution based on 30 percent of GTN’s annual distributions exceeding certain thresholds and adjustments, after the Class B reduction.
Payments to our General Partner and its affiliates	If distributions exceed the minimum quarterly distribution and other higher target levels, our General Partner will be entitled to increasing percentages of the distributions, up to 25 percent of the distributions above the highest target level. We refer to the rights to the increasing distributions as “incentive distribution rights.” For further information about distributions, please read Part II Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”
Withdrawal or removal of our General Partner	If our General Partner withdraws or is removed, its General Partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation	Upon our liquidation, the partners, including our General Partner, will be entitled to receive liquidating distributions according to their particular capital account balances. The Class B units rank equally with common units upon liquidation.

Reimbursement of Operating and General and Administrative Expense

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership. The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner were $4 million for the year ended December 31, 2019.

Cash Management Programs

Great Lakes has a cash management agreement with TC Energy whereby its funds are pooled with other TC Energy affiliates. The agreement gives Great Lakes the ability to obtain short-term borrowings to provide liquidity for its operating needs. At December 31, 2019 and 2018, Great Lakes had outstanding receivables from this arrangement amounting to $34 million and $36 million, respectively.

Transportation Agreements with Related Party

Refer to Note 18 within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

Acquisitions

In the past, we have participated in several business acquisitions with TC Energy that were accounted for as transactions between entities under common control. For more details regarding the transactions’ size, structure and terms, see Note 8 within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

TC PipeLines, LP Annual Report 2019    73

Operating Agreements with Our Pipeline Companies

Our pipeline systems are operated by TC Energy and its affiliates pursuant to operating agreements. Under these agreements, our pipeline systems are required to reimburse TC Energy for their costs including payroll, employee benefit costs, and other costs incurred on behalf of our pipeline systems. Costs for materials, services and other charges that are third-party charges are invoiced directly to each of our pipeline systems.

Total costs charged to our pipeline systems for the years ended December 31, 2019, 2018 and 2017 by TC Energy’s subsidiaries and amounts payable to TC Energy’s subsidiaries at December 31, 2019 and 2018 are summarized in Note 18 within Part IV, Item 15. “Exhibits and Financial Statement Schedules,” which information is incorporated herein by reference.

Other Agreements

Our pipeline systems currently have interconnection, operational balancing agreements, transportation and exchange agreements and/or other inter-affiliate agreements with affiliates of TC Energy. In addition, each of our pipeline systems currently has other routine agreements with TC Energy that arise in the ordinary course of business, including agreements for services and other transportation and exchange agreements and interconnection and balancing agreements.

Relationship with our General Partner and TC Energy and Conflicts of Interest Resolution

Our Partnership Agreement contains specific provisions that address potential conflicts of interest between our General Partner and its affiliates, including TC Energy, on one hand, and us and our subsidiaries, on the other hand. Whenever such a conflict of interest arises, our General Partner will resolve the conflict. Our General Partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of our General Partner (Special Approval), which is comprised of independent directors.

Any conflict of interest and any resolution of such conflict of interest shall be conclusively deemed fair and reasonable if such conflict of interest or resolution is approved by Special Approval:

● on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; or

● fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

The General Partner may also adopt a resolution or course of action that has not received Special Approval.

In acting for the Partnership, the General Partner is accountable to us and the unitholders as a fiduciary. Neither the Delaware Revised Uniform Limited Partnership Act (Delaware Act) nor case law defines with particularity the fiduciary duties owed by general partners to limited partners of a limited partnership. The Delaware Act does provide that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by a general partner to limited partners and the partnership.

In order to induce the General Partner to manage the business of the Partnership, the Partnership Agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by the General Partner. The following is a summary of the material restrictions of the fiduciary duties owed by the General Partner to the limited partners:

● The Partnership Agreement permits the General Partner to make a number of decisions in its “sole discretion.” This entitles the General Partner to consider only the interests and factors that it desires and it shall have no duty or obligation to give any consideration to any interest of, or factors affecting, the Partnership, its affiliates or any limited partner. Other provisions of the Partnership Agreement provide that the General Partner’s actions must be made in its reasonable discretion.

● The Partnership Agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be “fair and reasonable” to the Partnership. In determining whether a transaction or resolution is “fair and reasonable” the General Partner may consider interests of all parties involved, including its own. Unless the General Partner has acted in bad faith, the action taken by the General Partner shall not constitute a breach of its fiduciary duty.

● The Partnership Agreement specifically provides that it shall not be a breach of the General Partner’s fiduciary duty if its affiliates engage in business interests and activities in competition with, or in preference or to the exclusion of, the Partnership. Further, the General Partner and its affiliates have no obligation to present business opportunities to the Partnership.

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● The Partnership Agreement provides that the General Partner and its officers and directors will not be liable for monetary damages to the Partnership, the limited partners or assignees for errors of judgment or for any acts or omissions if the General Partner and those other persons acted in good faith.

The Partnership is required to indemnify the General Partner and its officers, directors, employees, affiliates, partners, members, agents and trustees (collectively referred to hereafter as the General Partner and others), to the fullest extent permitted by law, against liabilities, costs and expenses incurred by the General Partner and others. This indemnification is required if the General Partner and others acted in good faith and in a manner, they reasonably believed to be in, or (in the case of a person other than the General Partner) not opposed to, the best interests of the Partnership. Indemnification is required for criminal proceedings if the General Partner and others had no reasonable cause to believe their conduct was unlawful. Please read Part III, Item 10. “Directors, Executive Officers and Corporate Governance” for additional information.

Director Independence

Please read Part III, Item 10. “Directors, Executive Officers and Corporate Governance” for information about the independence of our General Partner’s board of directors and its committees, which information is incorporated herein by reference in its entirety.

Item 14. Principal Accountant Fees and Services

The following table sets forth, for the periods indicated, the fees billed by the principal accountants:

Year ended December 31 (thousands of dollars)	2019	2018		2017
Audit Fees	1,185	1,165	(a)​	861	(a)(b)
Audit Related Fees	—	—		—
Tax Fees(c)	—	—		—
All Other Fees	—	—		—
Total	1,185	1,165		861

(a) $50 thousand of the 2018 audit fees related to ATM equity financing (2017 - $200 thousand).

(b) $65 thousand of the 2017 audit fees related to issuance of senior unsecured notes.

(c) The Partnership did not engage its external auditors for any tax or other services in 2019, 2018 or 2017.

AUDIT FEES

Audit fees include fees for the audit of annual GAAP financial statements, reviews of the related quarterly financial statements and related consents and comfort letters for documents filed with the SEC. Before our independent registered public accounting firm is engaged each year for annual audit and any non-audit services, these services and fees are reviewed and approved by our Audit Committee.

The Audit Committee has a policy to pre-approve the engagement fees and terms of all audit, audit-related, tax and other non-audit services provided to the Partnership by the independent registered public accounting firm. All of the fees in the table above were approved in accordance with this policy. As part of the pre-approval process, the Audit Committee also evaluates all non-audit services to be provided by the independent registered public accounting firm to ensure the provision of the non-audit services is compatible with maintaining the independence of the independent registered public accounting firm under applicable U.S. federal securities laws and stock exchange rules. Pre-approval is detailed as to the particular service or category of services and is subject to a specific budget or fee structure. The Audit Committee may delegate to one of its members the authority to pre-approve the engagement of the independent registered public accounting firm for permitted non-audit services, provided that such member is required to present the pre-approval of any permitted non-audit service to the full Audit Committee at its next meeting following any such pre-approval.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)    (1)   Financial Statements

See “Index to Financial Statements” set forth on Page F-1.

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(2)   Financial Statement Schedules

All schedules are omitted because they are either not applicable or the required information is shown in the consolidated financial statements or notes thereto.

(3)   Exhibits

The exhibit list required by this Item is incorporated by reference to the Exhibit Index that follows the financial statements files as a part of this report.

No.	Description
2.1*	Agreement for Purchase and Sale of Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
2.1.1*	First Amendment to Purchase and Sale Agreement by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 31, 2017 (Incorporated by reference from Exhibit 2.1.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).
2.2*	Agreement for Purchase and Sale of Partnership Interest in Portland Natural Gas Transmission System, by and between TCPL Portland Inc., as Seller and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.3 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).
3.1*	Certificate of Limited Partnership of TC PipeLines, LP (Incorporated by reference to Exhibit 3.2 to TC PipeLines, LP’s Form S-1 Registration Statement, filed on December 30, 1998).
3.2	Conformed Copy of Fourth Amended and Restated Agreement of Limited Partnership of TC Pipelines, LP (incorporating Amendment No. 1 thereto, entered into on February 4, 2020 and effective as of December 31, 2018).
4.1*	Indenture, dated as of June 17, 2011, between the Partnership and The Bank of New York Mellon, as trustee (Incorporated by reference to Exhibit 4.1 to TC PipeLines, LP’s Form 8-K filed on June 17, 2011).
4.2*	Supplemental Indenture, dated as of June 17, 2011 relating to the issuance of $350,000,000 aggregate principal amount of 4.65% Senior Notes due 2021 (Incorporated by reference to Exhibit 4.2 to TC PipeLines, LP’s Form 8-K filed on June 17, 2011).
4.3*	Specimen of 4.65% Senior Notes due 2021 (Incorporated by reference to Exhibit A to the Supplemental Indenture filed as Exhibit 4.2 to TC PipeLines, LP’s Form 8-K filed on June 17, 2011).
4.4*	Form of indenture for senior debt securities (Incorporated by reference to Exhibit 4.1 to TC PipeLines, LP’s Form 8-K filed on June 14, 2011).
4.5*	Second Supplemental Indenture, dated March 13, 2015, between TC PipeLines, LP and The Bank of New York Mellon (incorporated by reference from Exhibit 4.1 to TC PipeLines, LP’s Form 8-K filed March 13, 2015).
4.6*	Third Supplemental Indenture, dated as of May 25, 2017, relating to the issuance of $500,000,000 aggregate principal amount of 3.900% Senior Notes due 2027 (Incorporated by reference from Exhibit 4.2 to TC PipeLines, LP’s Form 8-K filed May 25, 2017).
4.7	Description of the Registrant’s Securities.
10.1*	Third Amended and Restated Revolving Credit and Term Loan Agreement, dated as of November 10, 2016, by an among TC PipeLines, LP, the Lenders, and SunTrust Bank, as administrative agent for the Lenders (Incorporated by reference to Exhibit 10.21 to TC PipeLines, LP’s Form 10-K filed on February 28, 2017).

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No.	Description
10.1.1*	First Amendment to TC PipeLines, LP’s Third Amended and Restated Revolving Credit Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.3 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
10.2*	Term Loan Agreement, dated as of July 1, 2013, between TC PipeLines, LP and the lenders (Incorporated by reference to Exhibit 10.1 to TC PipeLines, LP’s Form 8-K filed on July 3, 2013).
10.2.1*	First Amendment to Term Loan Agreement, dated as of November 10, 2016, by and among TC PipeLines, LP, the Required Lenders and SunTrust Bank, as administrative agent for the Lenders (Incorporated by reference to Exhibit 10.11.1 to TC PipeLines, LP’s Form 10-K filed on February 28, 2017).
10.2.2*	Second Amendment to TC PipeLines, LP’s July 1, 2013 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference to Exhibit 99.1 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).
21.1	Subsidiaries of the Registrant.
23.1	Consent of KPMG LLP with respect to the financial statements of TC PipeLines, LP.
23.2	Consent of KPMG LLP with respect to the financial statements of Northern Border Pipeline Company.
23.3	Consent of KPMG LLP with respect to the financial statements of Great Lakes Gas Transmission Limited Partnership.
23.4	Consent of Blum, Shapiro & Company, P.C. with respect to the financial statements of Iroquois Gas Transmission System, L.P.
31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Amended Transportation Service Agreement FT18311 between Great Lakes Gas Transmission Limited Partnership and TransCanada PipeLines Limited, effective date November 01, 2020.
99.2	Amended Transportation Service Agreement FT18229 between Great Lakes Gas Transmission Limited Partnership and TransCanada PipeLines Limited, effective date November 01, 2020.
99.3	Amended Transportation Service Agreement FT17193 between Great Lakes Gas Transmission Limited Partnership and TransCanada PipeLines Limited, effective date November 01, 2020.
99.4	Amended Transportation Service Agreement FT18147 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date November 01, 2020.
99.5	Amended Transportation Service Agreement FT18150 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date November 01, 2020.
99.6	Amended Transportation Service Agreement FT17593 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date November 01, 2020.
99.7	Amended Transportation Service Agreement FT18659 between Great Lakes Gas Transmission Limited Partnership and ANR Pipeline Company, effective date November 01, 2020.

TC PipeLines, LP Annual Report 2019    77

No.	Description
101	The following materials from TC PipeLines, LP’s Annual Report on Form 10-K for the year ended December 31, 2019 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statement of Cash Flows, (v) the Consolidated Statement of Changes in Partners’ Equity, and (vi) the Notes to Consolidated Financial Statements (Audited)
104	Cover Page Interactive Data File (embedded within the Inline XBRL document)

*      Indicates exhibits incorporated by reference.

#      Management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 20^th day of February 2020.

TC PIPELINES, LP (A Delaware Limited Partnership) by its General Partner, TC PipeLines GP, Inc.
By:	/s/ Nathaniel A. Brown Nathaniel A. Brown President TC PipeLines GP, Inc. (Principal Executive Officer)
By:	/s/ William C. Morris William C. Morris Vice President and Treasurer TC PipeLines GP, Inc. (Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Stanley G. Chapman III	Chair	February 20, 2020
Stanley G. Chapman III
/s/ Nathaniel A. Brown	Principal Executive Officer and President	February 20, 2020
Nathaniel A. Brown
/s/ William C. Morris	Principal Financial Officer, Vice President and Treasurer	February 20, 2020
William C. Morris
/s/ Nadine E. Berge	Director	February 20, 2020
Nadine E. Berge
/s/ Sean M. Brett	Director	February 20, 2020
Sean M. Brett
/s/ Walentin (Val) Mirosh	Director	February 20, 2020
Walentin (Val) Mirosh
/s/ Jack F. Stark	Director	February 20, 2020
Jack F. Stark
/s/ Malyn K. Malquist	Director	February 20, 2020
Malyn K. Malquist

TC PipeLines, LP Annual Report 2019    79

TC PIPELINES, LP

INDEX TO FINANCIAL STATEMENTS

	Page No.
CONSOLIDATED FINANCIAL STATEMENTS OF TC PIPELINES, LP
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets – December 31, 2019 and 2018	F-4
Consolidated Statements of Operations – Years Ended December 31, 2019, 2018 and 2017	F-5
Consolidated Statements of Comprehensive Income (Loss) – Years Ended December 31, 2019, 2018 and 2017	F-6
Consolidated Statements of Cash Flows – Years Ended December 31, 2018, 2017 and 2016	F-7
Consolidated Statement of Changes in Partners’ Equity – Years Ended December 31, 2019, 2018 and 2017	F-8
Notes to Consolidated Financial Statements	F-9
FINANCIAL STATEMENTS OF NORTHERN BORDER PIPELINE COMPANY
Independent Auditors' Report	F-37
Balance Sheets – December 31, 2019 and 2018	F-38
Statements of Income – Years Ended December 31, 2019, 2018 and 2017	F-39
Statements of Comprehensive Income – Years Ended December 31, 2019, 2018 and 2017	F-40
Statements of Cash Flows – Years Ended December 31, 2019, 2018 and 2017	F-41
Statements of Changes in Partners' Equity – Years Ended December 31, 2019, 2018 and 2017	F-42
Notes to Financial Statements	F-43
FINANCIAL STATEMENTS OF GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Independent Auditors' Report	F-53
Balance Sheets – December 31, 2019 and 2018	F-54
Statements of Income and Partners' Capital – Years Ended December 31, 2019, 2018 and 2017	F-55
Statements of Cash Flows – Years Ended December 31, 2019, 2018 and 2017	F-56
Notes to Financial Statements	F-57
FINANCIAL STATEMENTS OF IROQUOIS GAS TRANSMISSION SYSTEM, L.P
Independent Auditors' Report	F-66
Statements of Comprehensive Income – Years Ended December 31, 2019, 2018 and 2017	F-67
Balance Sheets – December 31, 2019 and 2018	F-68
Statements of Cash Flows – Years Ended December 31, 2019, 2018 and 2017	F-69
Statements of Changes in Partners' Equity – Years Ended December 31, 2019, 2018 and 2017	F-70
Notes to Financial Statements	F-71

TC PipeLines, LP Annual Report 2019    F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Partners
TC Pipelines GP, Inc. General Partner of TC Pipelines, LP:

Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated balance sheets of TC Pipelines, LP (a Delaware limited partnership) and subsidiaries (the Partnership) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income (loss), changes in partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements). We also have audited the Partnership’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019 based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Basis for Opinions

The Partnership’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s consolidated financial statements and an opinion on the Partnership’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control Over Financial Reporting

A Partnership’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A Partnership’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Partnership; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorizations of management and directors of the Partnership; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Partnership’s assets that could have a material effect on the financial statements.

F-2    TC PipeLines, LP Annual Report 2019

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Evaluation of the qualitative assessment over goodwill for the Tuscarora and North Baja reporting units

As discussed in Notes 2 and 4 to the consolidated financial statements, the Partnership performs goodwill impairment testing on an annual basis and whenever events and changes in circumstances indicate that the carrying value of goodwill might exceed the fair value of a reporting unit. The Partnership performed a qualitative assessment over goodwill for their identified reporting units to determine whether there was a greater than 50 percent likelihood that the fair value of the reporting unit was less than its carrying value. The goodwill balance at December 31, 2019 was $71 million and specifically the goodwill balances for the Tuscarora reporting unit and North Baja reporting unit were $23 million and $48 million, respectively.

We identified the determination and evaluation of the qualitative assessment over goodwill for the Tuscarora and North Baja reporting units as a critical audit matter. The qualitative assessments, specifically the market changes associated with the multiples and discount rates, required complex auditor judgment as minor changes to those considerations could have a significant impact on the assessment of the carrying value of goodwill.

The primary procedures we performed to address the critical audit matter included the following. We tested certain internal controls over the Partnership’s goodwill impairment process, including controls related to the development of the multiples and discount rates used in the qualitative assessment. We involved a valuation professional with specialized skill and knowledge who assisted in:

● Evaluating the Partnership’s determination of multiples by comparing to independently observed recent market transactions of comparable assets and using publicly available market data for comparable entities.

● Evaluating the Partnership’s determination of applicable discount rates by comparing management’s selected discount rate to a discount rate range that was independently developed using publicly available market data for comparable companies.

/s/ KPMG LLP

We have served as the Partnership’s auditor since 2011.

Houston, TX
February 20, 2020

TC PipeLines, LP Annual Report 2019    F-3

TC PIPELINES, LP

CONSOLIDATED BALANCE SHEETS

December 31 (millions of dollars)	2019	2018
ASSETS
Current Assets
Cash and cash equivalents	83	33
Accounts receivable and other (Note 21)	43	48
Distribution receivable from Iroquois (Note 5)	14	—
Inventories	10	8
Other	6	8
	156	97
Equity investments (Note 5)	1,098	1,196
Property, plant and equipment, net (Note 7)	1,528	1,529
Goodwill (Note 4)	71	71
Other assets	—	6
TOTAL ASSETS	2,853	2,899
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	28	36
Accounts payable to affiliates (Note 18)	8	6
Accrued interest	11	12
Current portion of long-term debt (Note 9)	123	36
	170	90
Long-term debt (Note 9)	1,880	2,072
Deferred state income taxes (Note 2)	7	9
Other liabilities (Note 10)	36	29
	2,093	2,200
Partners’ Equity (Note 11)
Common units	544	462
Class B units	103	108
General partner	14	13
Accumulated other comprehensive income (loss) (AOCI) (Note 12)	(5)	8
Controlling interests	656	591
Non–controlling interest	104	108
	760	699
TOTAL LIABILITIES AND PARTNERS' EQUITY	2,853	2,899

Contingencies (Note 22)

Variable Interest Entities (Note 23)

Subsequent Events (Note 24)

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

F-4    TC PipeLines, LP Annual Report 2019

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

Year ended December 31 (millions of dollars except per common unit amounts)	2019		2018		2017
Transmission revenues, net (Note 6)		403		549		422
Equity earnings (Note 5)		160		173		124
Impairment of long-lived assets (Note 7)		—		(537)		—
Impairment of goodwill (Note 4)		—		(59)		—
Operation and maintenance expenses		(71)		(67)		(67)
Property taxes		(26)		(28)		(28)
General and administrative		(8)		(6)		(8)
Depreciation		(78)		(97)		(97)
Financial charges and other (Note 13)		(83)		(92)		(82)
Net income (loss) before taxes		297		(164)		264
Income taxes (Note 2)		1		(1)		(1)
Net Income (loss)		298		(165)		263
Net income attributable to non-controlling interests		18		17		11
Net income (loss) attributable to controlling interests		280		(182)		252
Net income (loss) attributable to controlling interest allocation (Note 14)
Common units		267		(191)		219
General Partner		5		(4)		16
TC Energy and its subsidiaries		8		13		17
		280		(182)		252
Net income (loss) per common unit (Note 14) – basic and diluted	$	3.74	$	(2.68)	$	3.16
Weighted average common units outstanding (millions) – basic and diluted		71.3		71.3		69.2
Common units outstanding, end of year (millions)		71.3		71.3		70.6

TC PipeLines, LP Annual Report 2019    F-5

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Year ended December 31 (millions of dollars)	2019	2018	2017
Net income (loss)	298	(165)	263
Other comprehensive income (loss)
Change in fair value of cash flow hedges (Notes 12 and 20)	(13)	(2)	5
Reclassification to net income of gains and losses on cash flow hedges (Notes 12 and 20)	(1)	5	—
Amortization of realized loss on derivative instrument (Notes 12 and 20)	—	1	1
Other comprehensive income (loss) on equity investments (Note 12)	1	(1)	1
Comprehensive income (loss)	285	(162)	270
Comprehensive income attributable to non-controlling interests	18	17	11
Comprehensive income (loss) attributable to controlling interests	267	(179)	259

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

F-6    TC PipeLines, LP Annual Report 2019

TC PIPELINES, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31 (millions of dollars)	2019	2018	2017
Cash Generated from Operations
Net income (loss)	298	(165)	263
Depreciation	78	97	97
Impairment of long-lived assets (Note 7)	—	537	—
Impairment of goodwill (Note 4)	—	59	—
Amortization of debt issue costs reported as interest expense (Note 13)	2	2	2
Amortization of realized loss on derivative instrument (Note 20)	—	1	1
Equity earnings from equity investments (Note 5)	(160)	(173)	(124)
Distributions received from operating activities of equity investments (Note 5)	200	188	140
Change in other long-term liabilities	(1)	(2)	—
Equity allowance for funds used during construction	(2)	(1)	(1)
Change in operating working capital (Note 16)	(3)	(3)	(2)
	412	540	376
Investing Activities
Investment in Great Lakes (Note 5)	(10)	(9)	(9)
Investment in Iroquois (Note 5)	(4)	—	—
Investment in Northern Border (Note 5)	—	—	(83)
Distribution received from Northern Border as return of investment (Note 5)	50	—	—
Distribution received from Iroquois as return of investment (Note 5)	8	10	5
Acquisition of a 49.34 percent in Iroquois and an additional 11.81 percent in PNGTS (Note 8)	—	—	(646)
Capital expenditures	(75)	(40)	(29)
Other	(1)	4	1
	(32)	(35)	(761)
Financing Activities
Distributions paid (Note 15)	(189)	(218)	(284)
Distributions paid to Class B units (Notes 11 and 15)	(13)	(15)	(22)
Distributions paid to non-controlling interests	(22)	(14)	(5)
Distributions paid to former parent of PNGTS	—	—	(1)
Common unit issuance, net (Note 11)	—	40	176
Long-term debt issued, net of discount (Note 9)	30	219	802
Long-term debt repaid (Note 9)	(136)	(516)	(310)
Debt issuance costs	—	(1)	(2)
	(330)	(505)	354
Increase/(decrease) in cash and cash equivalents	50	—	(31)
Cash and cash equivalents, beginning of year	33	33	64
Cash and cash equivalents, end of year	83	33	33
Interest payments paid	87	94	79
State income taxes paid	2	1	2
Supplemental information about non-cash investing and financing activities
Accrued capital expenditures	12	7	9

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

TC PipeLines, LP Annual Report 2019    F-7

TC PIPELINES, LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

							Accumulated
							Other
	Limited			Partners		General	Comprehensive	Non-Controlling		Total
		Common Units		Class B Units		Partner	Income (Loss) (a)	Interest	PNGTS (b)	Equity
		(millions	(millions of	(millions	(millions of	(millions of	(millions of	(millions of	(millions of	(millions of
		of units)	dollars)	of units)	dollars)	dollars)	dollars)	dollars)	dollars)	dollars)
Partners’ Equity at December 31, 2016(c)		67.4	1,002	1.9	117	27	(2)	97	31	1,272
Net income		—	219	—	15	16	—	11	2	263
Other comprehensive income		—	—	—	—	—	7	—	—	7
ATM equity issuances, net (Note 11)		3.2	173	—	—	3	—	—	—	176
Reclassification of common units no longer subject to rescission (Note 11)		—	81	—	—	2	—	—	—	83
Acquisition of interests in PNGTS and Iroquois (Note 8)		—	(383)	—	—	(8)	—	—	(32)	(423)
Distributions		—	(268)	—	(22)	(16)	—	(3)	(1)	(310)
Partners' Equity at December 31, 2017		70.6	824	1.9	110	24	5	105	—	1,068
Net income (loss)		—	(191)	—	13	(4)	—	17	—	(165)
Other comprehensive income		—	—	—	—	—	3	—	—	3
ATM equity issuances, net (Note 11)		0.7	39	—	—	1	—	—	—	40
Distributions		—	(210)	—	(15)	(8)	—	(14)	—	(247)
Partners' Equity at December 31, 2018		71.3	462	1.9	108	13	8	108	—	699
Net income		—	267	—	8	5	—	18	—	298
Other comprehensive income		—	—	—	—	—	(13)	—	—	(13)
Distributions		—	(185)	—	(13)	(4)	—	(22)	—	(224)
Partners' Equity at December 31, 2019		71.3	544	1.9	103	14	(5)	104	—	760

(a) Gains (losses) related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $2 million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.

(b) Equity of Former Parent of PNGTS.

(c) Recast to consolidate PNGTS (Refer to Notes 2 and 8).

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

F-8    TC PipeLines, LP Annual Report 2019

TC PIPELINES, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 ORGANIZATION

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

At December 31, 2018, the Partnership owned its pipeline assets through an intermediate general partnership, TC PipeLines Intermediate GP, LLC (Intermediate GP) and three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership. During the fourth quarter of 2019, the Partnership initiated the dissolution of the ILPs and Intermediate GP. Effective October 31, 2019, the Intermediate GP and ILPs transferred 100 percent of the ownership of their pipeline assets to the Partnership. As a result, the Partnership owns its pipeline assets directly which creates a more efficient partnership structure with no economic impact to the general and limited partners of the Partnership.

Pipeline	Length	Description	Ownership
GTN	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison	303 miles	Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border	1,412 miles	Extends between 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 Rocky Mountain area for deliveries to the Midwest. ONEOK Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border.	50 percent
PNGTS	295 miles	Connects with the TQM 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 undivided ownership interest based on contractually agreed upon percentages. The Joint Facilities are maintained and operated by MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.	61.71 percent
Great Lakes	2,115 miles	Connects with the TC Energy Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TC Energy owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois	416 miles	Extends from the TC Energy Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by: TC Energy (0.66 percent), Dominion Energy (50 percent). Iroquois is maintained and operated by a subsidiary of Iroquois.	49.34 percent

The Partnership is managed by its General Partner, TC PipeLines GP, Inc. (General Partner), an indirect wholly-owned subsidiary of TC Energy. The General Partner provides management and operating services to the Partnership and is reimbursed for its costs and expenses. The General Partner owns 5,797,106 of our common units, 100 percent of our Incentive Distribution Rights (IDRs) and a two percent general partner interest in the Partnership at December 31, 2019. TC Energy also indirectly holds an additional 11,287,725 common units, for a total ownership of approximately 24 percent of our outstanding common units and 100 percent of our Classs B units at December 31, 2019 (Refer to Note 11).

TC PipeLines, LP Annual Report 2019    F-9

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements and related notes have been prepared in accordance with U.S. generally accepted accounting principles (GAAP) and amounts are stated in U.S. dollars. The financial statements and notes present the financial position of the Partnership as of December 31, 2019 and 2018 and the results of its operations, cash flows and changes in partners’ equity for the years ended December 31, 2019, 2018 and 2017.

(a)    Basis of Presentation

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

Acquisitions by the Partnership from TC Energy are considered common control transactions. When businesses that will be consolidated are acquired from TC Energy by the Partnership, the historical financial statements are required to be recast, with the exception of net income (loss) per common unit, to include the acquired entities for all periods presented.

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

On June 1, 2017, the Partnership acquired from a subsidiary of TC Energy an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 8). This acquisition was accounted for as transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TC Energy's carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TC Energy a 49.34 percent interest in Iroquois (Refer to Note 8). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to a pooling of interest, whereby the equity investment in Iroquois was recorded at TC Energy's carrying value and was accounted for prospectively.

(b)    Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

(c)    Cash and Cash Equivalents

The Partnership’s cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

(d)    Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method.

(e)    Natural gas imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines’ tariff.

Imbalances due from others are reported as trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. The determination of the asset or liability classification is based on the net position of the customer. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.

F-10    TC PipeLines, LP Annual Report 2019

(f)    Inventories

Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost and net realizable value.

(g)    Property, plant and Equipment

Property, plant and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from five to 77 years. Depreciation of our subsidiaries’ assets is based on rates approved by FERC from the pipelines’ last rate proceeding and is calculated on a straight-line composite basis over the assets’ estimated useful lives. Under the composite method, assets with similar lives and characteristics are grouped and depreciated as one asset. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized.

The Partnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long-lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based on the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of property, plant and equipment on the balance sheets. Amounts included in construction work in progress are not depreciated until transferred into service.

(h)    Impairment of Equity Method Investments

We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment.

If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.

(i)    Impairment of Long-lived Assets

The Partnership reviews long-lived assets, such as property, plant and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

(j)    Partners’ Equity

Costs incurred in connection with the issuance of units are deducted from the proceeds received.

(k)    Revenue Recognition

The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Partnership utilizes the practical expedient of recognizing revenue as invoiced. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is

TC PipeLines, LP Annual Report 2019    F-11

transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.

The Partnership's pipeline systems are subject to Federal Energy Regulatory Commission (FERC) regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management’s best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. Refer to Note 6 for detailed disclosures regarding the Partnership’s revenues.

(l)    Debt Issuance Costs

Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Consistent with debt discount, debt issuance costs are presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities. The amortization of debt issuance costs is reported as interest expense.

(m)    Income Taxes

U.S. federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of operations, is includable in the U.S. federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the partnership is not available.

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

State Income Taxes on PNGTS

The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire (NH). As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at December 31, 2019, 2018 and 2017 relate primarily to utility plant. The NH BPT effective tax rate was 2.6 percent for the year ended December 31, 2019 (2018 – 3.5 percent, 2017 - 3.8 percent) and was applied to PNGTS’ taxable income.

The state income taxes of PNGTS are broken out as follows:

Year ended December 31 (millions of dollars)	2019	2018	2017
State income tax benefit (expense)
Current	(1)	(2)	(1)
Deferred	2	1	—
	1	(1)	(1)

(n)    Acquisitions and Goodwill

The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill.

Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if any indicators of impairment are evident. The Partnership can initially assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired and if the Partnership concludes there is not a greater than 50 percent likelihood that the fair value of the reporting unit is greater than its carrying value, the Partnership will then perform the quantitative goodwill impairment test. The Partnership can also elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Partnership compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of

F-12    TC PipeLines, LP Annual Report 2019

a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value.

We calculate the estimated fair value of the reporting unit using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for of the reporting unit, estimates of the useful life over which cash flows will occur, and a determination of weighted average cost of capital. The estimates used to calculate the fair value of the reporting unit can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether the goodwill in the reporting unit has suffered an impairment.

The Partnership accounts for business acquisitions between itself and TC Energy, also known as “dropdowns,” as transactions between entities under common control. Using this approach, the assets and liabilities of the acquired entities are recorded at TC Energy’s carrying value. In the event recasting is required, the Partnership’s historical financial information will be recast, with the exception of net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners’ Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners’ Equity.

(o)    Fair Value Measurements

For cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Judgment is required in developing these estimates.

(p)    Derivative Financial Instruments and Hedging Activities

The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings.

The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). In a cash flow hedging relationship, the change in the fair value of the hedging derivative is reported as a component of other comprehensive income and reclassified into earnings as part of “financial charges and other” line in the Consolidated Statement of Operations in the same period or periods during which the hedged transaction affects earnings or is reclassified immediately to net income when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur.

In some instances, the derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change.

(q)    Asset Retirement Obligation

The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists, and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses.

The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system’s assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2019 and 2018.

TC PipeLines, LP Annual Report 2019    F-13

(r)    Government Regulation

The Partnership's subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated rate-making process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators' decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. At December 31, 2019, the Partnership had nil amount of regulatory assets reported as part of other current assets in the balance sheet and nil amount of regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities. At December 31, 2018, the Partnership had regulatory assets amounting to $2 million reported as part of other current assets in the balance sheet and $2 million regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities both representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually. Long-term regulatory liabilities that the Partnership has collected in its current rates related to future removal costs on its transmissions and gathering facilities are included in other long-term liabilities (refer to Note 10).

NOTE 3 ACCOUNTING PRONOUNCEMENTS

Changes in Accounting Policies effective January 1, 2019

Leases

In February 2016, the Financial Accounting Standards Board (FASB) issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than twelve months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the consolidated statements of income. The new guidance does not make extensive changes to lessor accounting.

Under the new guidance, the Partnership determines if an arrangement is a lease at inception. Operating leases are recognized as ROU assets and included in Property, plant and equipment while corresponding liabilities are included in "Accounts payable and other" and "Other long-term liabilities" on the consolidated balance sheet. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. As the Partnership’s leases do not provide an implicit rate, the Partnership uses an incremental borrowing rate that approximates its borrowing cost based on the information available at commencement date in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and initial direct costs incurred and excludes lease incentives. Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Partnership will exercise that option. Operating lease expense is recognized on a straight-line basis over the lease term and included in "Operation and maintenance expenses" in the consolidated statements of income.

The new guidance was effective January 1, 2019 and was applied using optional transition relief which allowed entities to initially apply the new lease standard at adoption and recognize a cumulative-effect adjustment to the opening balance of equity in the period of adoption. This transition option allowed us to not apply the new guidance, including disclosure requirements, to the comparative periods presented.

We elected available practical expedients and exemptions upon adoption which allowed us:

● not to reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard;

● to carry forward the historical lease classification and our accounting treatment for land easements on existing agreements;

● to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption;

● to not separate lease and non-lease components for all leases for which we are the lessee; and

● to use hindsight in determining the lease term and assessing ROU assets for impairment.

F-14    TC PipeLines, LP Annual Report 2019

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

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

● the discount rate for the lease.

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

The primary change as a result of the adoption was the recognition of ROU assets and lease liabilities for operating leases which was approximately $0.6 million at January 1, 2019 and $0.4 million at December 31, 2019. For the year ended December 31, 2019, the Partnership’s operating lease cost was not material to the Partnership’s consolidated results. At December 31, 2019, the weighted average remaining term and discount rate of the Partnership’s operating leases were approximately 1.96 years and 3.57 percent, respectively.

Fair Value Measurement

In August 2018, the FASB issued new guidance that amends certain disclosure requirements for the fair value measurements as part of its disclosure framework project. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Partnership elected to adopt this guidance effective first quarter 2019. The guidance was applied retrospectively and did not have a material effect on the Partnership’s consolidated financial statements.

Future accounting changes

Measurement of credit losses on financial instruments

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

Consolidation

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

NOTE 4 GOODWILL AND REGULATORY

During late 2018, the Partnership completed its regulatory filings to address the issues contemplated by the 2017 Tax Act and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by Master Limited Partnerships (MLPs):

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

● Option 1: make a limited NGA Section 4 filing to reduce its rates by the reduction in its cost of service shown in its FERC Form No. 501-G. For any pipeline electing this option, FERC guaranteed a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s FERC Form 501-G showed the pipeline’s estimated ROE as being 12 percent or less. Under the Final Rule and notwithstanding the Revised Policy Statement, a pipeline organized as an MLP is not required to eliminate its income tax allowance, but instead can reduce its rates to reflect the reduction in the maximum corporate tax rate. Alternatively, the MLP

TC PipeLines, LP Annual Report 2019    F-15

pipeline can eliminate its tax allowance, along with its ADIT used for rate-making purposes. In situations where the ADIT balance is a liability, this elimination would have the effect of increasing the pipeline’s rate base used for rate-making purposes;

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

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

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

Filings required by the Final Rule

Prior to the 2018 FERC Actions, the Partnership’s pipeline systems did not have 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 as summarized in the table below.

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

Rate settlements

As noted in the above table, new rate settlements were entered into by GTN, Tuscarora, Iroquois and Northern Border to address the issues that came out of the 2018 FERC Actions. Additional details of the settlements are outlined below:

F-16    TC PipeLines, LP Annual Report 2019

GTN

On November 30, 2018, FERC approved the rate settlement filed by GTN to address the changes proposed by the 2018 FERC Actions within its rates via an amendment to its prior settlement in 2015 (the 2018 GTN Settlement). In addition to the rate step downs described in the above table, the 2018 GTN Settlement will also reflect an elimination of tax allowance previously recovered in rates along with ADIT for rate-making purposes.

As part of the 2018 GTN Settlement, GTN has also agreed to issue a refund of approximately $10 million allocated amongst firm customers from January 1, 2018 to October 31, 2018 (the 2018 GTN Rate Refund). As a result of this, the Partnership established a $10 million provision for this revenue sharing as an offset against revenue in the income statement. The corresponding refund liability was paid by GTN before December 31, 2018.

Tuscarora

On December 6, 2018, Tuscarora elected to make a limited NGA Section 4 filing to reduce its maximum rates by approximately 1.7 percent and eliminate its deferred income tax balances previously used for rate setting (Option 1). On March 15, 2019, Tuscarora filed an uncontested settlement with FERC to address the issues contemplated by the 2017 Tax Act and 2018 FERC Actions via an amendment to its prior 2016 settlement (the 2019 Tuscarora Settlement). Among the terms of the 2019 Tuscarora Settlement, Tuscarora agreed to reduce its existing maximum system rates by 1.7 percent effective February 1, 2019 through to July 31, 2019 followed by an additional decrease of 10.8 percent for the period August 1, 2019 through the term of the settlement. Tuscarora is required to have new rates in effect on February 1, 2023. Tuscarora and its customers also agreed on a moratorium on rate changes until January 31, 2023. The 2019 Tuscarora Settlement, which was approved by FERC on May 2, 2019, will also reflect an elimination of the tax allowance previously recovered in rates along with ADIT for rate-making purposes.

Iroquois

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

Northern Border

On May 24, 2019, Northern Border's amended settlement agreement filed with the FERC for approval on April 4, 2019, was approved and its 501-G proceeding was terminated. Until superseded by a subsequent rate case or settlement, effective January 1, 2020, the amended settlement agreement extends the two percent rate reduction implemented on February 1, 2019 to July 1, 2024.

2018 Tuscarora Goodwill Impairment

As noted above, in the fourth quarter of 2018, Tuscarora initiated its regulatory approach in response to the 2018 FERC Actions, resulting in a reduction of its maximum rates. In connection with our annual goodwill impairment analysis, we evaluated Tuscarora’s future revenues as well as changes to other valuation assumptions responsive to Tuscarora’s commercial environment, which included estimates related to discount rates and earnings multiples. In doing so, we incorporated the expected impact of Tuscarora’s regulatory approach in response to the 2018 FERC Actions, in which it elected to make a limited NGA Section 4 filing to reduce its maximum rates and eliminate its deferred income tax balances previously used for rate setting. Additionally, for the year ended December 31, 2018, we have considered the outcome of the 2019 Tuscarora Settlement with its customers in our overall conclusion.

Our analysis resulted in the estimated fair value of Tuscarora not exceeding its carrying value, including goodwill. The fair value was measured using a discounted cash flow approach whereby the expected cashflows were discounted using a risk adjusted discount rate to determine fair value.

As a result, we recorded a goodwill impairment charge amounting to $59 million against Tuscarora’s goodwill balance of $82 million. The impairment charge was recorded in the Impairment of goodwill line on the Consolidated statement of operations and reduced our total consolidated goodwill balance from $130 million to $71 million.

TC PipeLines, LP Annual Report 2019    F-17

2019 Analysis

In 2019, based on our qualitative analysis of Tuscarora and North Baja’s current market conditions, which includes consideration of the potential qualitative impact of current year changes in the multiples and discount rate assumptions compared to multiples and discount rate assumptions used in the prior quantitative model, we believe there is a greater than 50 percent likelihood that Tuscarora and North Baja’s estimated fair value exceeded their carrying value. As a result, at December 31, 2019, we have not identified an impairment on the $71 million of goodwill related to Tuscarora ($23 million) and North Baja ($48 million) acquisitions.

There is a risk that adverse changes in our key assumptions could result in an additional future impairment on Tuscarora’s remaining goodwill of $23 million.

NOTE 5 EQUITY INVESTMENTS

The Partnership has equity interests in Northern Border, Great Lakes and, effective June 1, 2017, Iroquois. The pipeline systems owned by these entities are regulated by FERC. The pipeline systems of Northern Border and Great Lakes are operated by subsidiaries of TC Energy. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees.

	Ownership
	Interest at		Equity Earnings (b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2019		2019	2018	2017	2019	2018
Northern Border(a)	50.00	%	69	68	67	422	497
Great Lakes	46.45	%	51	59	31	491	489
Iroquois	49.34	%	40	46	26	185	210
			160	173	124	1,098	1,196

(a) Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent in April 2006. The fee was fully amortized in May 2018.

(b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here.

Distributions from Equity Investments

Distributions received from equity investments for the year ended December 31, 2019 were $258 million (2018 - $198 million; 2017 - $145 million) of which $58 million (2018 - $10 million and 2017 - $5 million) was considered a return of capital and is included in Investing activities in the Partnership’s consolidated statement of cash flows. The return of capital was related to our investment in Northern Border and Iroquois (see further discussion below).

Northern Border

During the year ended December 31, 2019, the Partnership received distributions from Northern Border amounting to $144 million (2018 - $83 million; 2017 – $83 million) The $144 million includes the Partnership's 50 percent share of the Northern Border $100 million distribution in June 2019. The $100 million distribution was 100 percent financed by borrowing on Northern Border's $200 million revolving credit facility. The $50 million of cash the Partnership received did not represent a distribution of operating cash flow during the period and, therefore, it was reported as a return of investment in the Partnership's consolidated statement of cash flows.

On September 1, 2017, the Partnership made an equity contribution to Northern Border amounting to $83 million. This amount represents the Partnership’s 50 percent share of a $166 million capital contribution request from Northern Border to reduce the outstanding balance of its revolving credit facility to increase its available borrowing capacity.

The Partnership recorded no undistributed earnings from Northern Border for the years ended December 31, 2019, 2018 and 2017. At December 31, 2019 the Partnership had a $115 million (December 31, 2018 - $115 million) difference between the carrying value of Northern Border and the underlying equity in the net assets primarily resulting from the recognition and inclusion of goodwill in the Partnership’s investment in Northern Border relating to the Partnership’s April 2006 acquisition of an additional 20 percent general partnership interest in Northern Border.

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

December 31 (millions of dollars)	2019	2018
Assets
Cash and cash equivalents	21	10
Other current assets	37	36
Property, plant and equipment, net	989	1,037
Other assets	12	13
	1,059	1,096
Liabilities and Partners’ Equity
Current liabilities	42	34
Deferred credits and other	39	35
Long-term debt, net (a)	364	264
Partners’ equity
Partners’ capital	615	764
Accumulated other comprehensive loss	(1)	(1)
	1,059	1,096

Year ended December 31 (millions of dollars)	2019	2018	2017
Transmission revenues	300	289	291
Operating expenses	(82)	(78)	(78)
Depreciation	(62)	(60)	(59)
Financial charges and other	(18)	(15)	(18)
Net income	138	136	136

(a) No current maturities as of December 31, 2019 or 2018.

Great Lakes

During the year ended December 31, 2019, the Partnership received distributions from Great Lakes amounting to $59 million (2018 - $58 million; 2017 - $35 million), all of which were reported as a return on investment in the Partnership's consolidated statement of cash flows.

The Partnership made equity contributions to Great Lakes of $5.1 million and $4.6 million in the first and fourth quarter of 2019, respectively. These amounts represent the Partnership’s 46.45 percent share of an $11 million and $10 million cash call from Great Lakes to make scheduled debt repayments.

The Partnership recorded no undistributed earnings from Great Lakes for the years ended December 31, 2019, 2018, and 2017.

At December 31, 2019, the equity method goodwill related to Great Lakes amounted to $260 million (December 31, 2018 - $260 million). The equity method goodwill relates to the Partnership’s February 2007 acquisition of a 46.45 percent general partner interest in Great Lakes and is the difference between the carrying value of our investment in Great Lakes and the underlying equity in Great Lakes’ net assets.

During the fourth quarter of 2018, Great Lakes finalized its regulatory approach in response to the 2018 FERC Actions and elected to make a limited NGA section 4 filing with FERC to reduce its maximum rates and eliminate its tax allowance and deferred income tax balances previously used for rate setting. As a result of this action, and because the estimated fair value of our investment in Great Lakes exceeded its carrying value by less than 10 percent in its 2017 valuation, we performed a quantitative test to determine if there was other than temporary decline in Great Lakes’ fair value.

The assumptions we used in our analysis related to the estimated fair value of our equity investment in Great Lakes included expected results from its limited NGA Section 4 filing with FERC, revenue opportunities on the system as well as changes to other valuation assumptions responsive to Great Lakes’ commercial environment, which includes estimates related to discount rates and earnings multiples. At December 31, 2018, we concluded the estimated fair value of our investment in Great Lakes exceeded its carrying value by more than 10 percent.

In 2019, Great Lakes current market conditions and other factors relevant to Great Lakes’ long-term financial performance have remained relatively stable during the year. There is a risk that reductions in future cash flow forecasts or adverse changes in other key assumptions could result in an additional future impairment of the carrying value of our investment in Great Lakes.

TC PipeLines, LP Annual Report 2019    F-19

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

December 31 (millions of dollars)	2019	2018
Assets
Current assets	72	75
Property, plant and equipment, net	685	689
	757	764
Liabilities and Partners’ Equity
Current liabilities	33	26
Long-term debt, net (a)	219	240
Other long-term liabilities	6	4
Partners’ equity	499	494
	757	764

Year ended December 31 (millions of dollars)	2019	2018	2017
Transmission revenues	238	246	181
Operating expenses	(79)	(68)	(66)
Depreciation	(32)	(32)	(29)
Financial charges and other	(16)	(18)	(20)
Net income	111	128	66

(a) Includes current maturities of $21 million as of December 31, 2019 and December 31, 2018.

Iroquois

For the year ended December 31, 2019, the Partnership received distributions from Iroquois amounting to $55 million (2018 - $56 million) which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $8 million (2018 - $10 million) (Refer to Note 8). This amount is reported as distributions received as return of investment in the Partnership’s consolidated statement of cash flows.

The Partnership made an equity contribution to Iroquois of $4 million in August 2019. This amount represents the Partnership’s 49.34 percent share of an $7 million cash call from Iroquois to cover costs of regulatory approvals related to their capital project.

The Partnership recorded no undistributed earnings for the years ended December 31, 2019 and 2018 and for the period from June 1, 2017, acquisition date, through December 31, 2017. At December 31, 2019 and 2018, the Partnership had a $40 million and $41 million difference, respectively, between the carrying value of Iroquois and the underlying equity in the net assets primarily from TC Energy’s carrying value and is due to their fair value assessment of Iroquois’ assets at the time of its acquisition of interests from third parties (refer to Note 2 - Acquisitions and Goodwill for our accounting policy on acquisitions from TC Energy).

Distribution receivable from Iroquois

Iroquois declared its third quarter 2019 distribution of $28 million on November 1, 2019, and the Partnership received its 49.34 percent share or $14 million on January 6, 2020.

F-20    TC PipeLines, LP Annual Report 2019

The summarized financial information provided to us by Iroquois for the period from the June 1, 2017 acquisition date through December 31, 2019 is as follows:

December 31 (millions of dollars)	2019	2018
ASSETS
Cash and cash equivalents	43	80
Other current assets	36	32
Property, plant and equipment, net	570	581
Other assets	16	8
	665	701
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	34	19
Net long-term debt, net (a)	317	325
Other non-current liabilities	20	14
Partners’ equity	294	343
	665	701

			Period of 7 months
	Year ended	Year ended	ended December 31,
(millions of dollars)	December 31, 2019	December 31, 2018	2017
Transmission revenues	180	194	110
Operating expenses	(58)	(57)	(32)
Depreciation	(29)	(29)	(17)
Financial charges and other	(11)	(14)	(9)
Net income	82	94	52

(a) Includes current maturities of $3 million as of December 31, 2019 (December 31, 2018 - $146 million).

NOTE 6 REVENUES

On January 1, 2018, the Partnership adopted new FASB guidance on revenue from contracts with customers using the modified retrospective transition method for all contracts that were in effect on the date of adoption. The reported results for 2019 and 2018 reflect the application of the new guidance, while the reported results for 2017 were prepared under previous revenue recognition guidance which is referred to herein as "legacy U.S. GAAP".

Disaggregation of Revenues

For the year ended December 31, 2019 and 2018, effectively all of the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed under Note 2 - Significant Accounting Policies.

During the fourth quarter of 2018, Bison received an unsolicited offer from Tenaska Marketing Ventures (Tenaska) regarding the termination of its contract. Also, during 2018, through a Permanent Capacity Release Agreement, Tenaska assumed Anadarko Energy Services Company’s (Anadarko) ship-or-pay contract obligation on Bison, which was the largest contract on Bison. Bison and Tenaska mutually agreed to terms which included a non-refundable payment to Bison of $95.4 million in December 2018 in exchange for the termination of all its contract obligations with Bison. Following the amendment of its tariff to enable this transaction, another customer executed a similar agreement to terminate its contract on Bison in exchange for a non-refundable payment to Bison of approximately $2.0 million in December 2018. At the termination of the contracts, Bison was released from performing any future services with the two customers and as such, the amounts received were recorded in revenue in 2018. Accordingly, the $97 million we received from contract terminations was considered as revenue from capacity and transportation contracts with customers and therefore no further disaggregation of revenue is needed (See also related discussion under Note 7 - Plant Property and Equipment).

As noted under Note 2 - Significant Accounting Policies, a portion of our revenues collected may be subject to refund when a rate proceeding is ongoing or as part of a rate case settlement with customers. We use our best estimate based on the facts and circumstances of the proceeding to provide for allowances for these potential refunds in the revenue we recognized. Accordingly, as part of the 2018 GTN Settlement, we have issued the 2018 GTN Rate Refund and recognized a $10 million offset against revenue in the income statement for the year ended December 31, 2018 (See also Note 4 for more information).

TC PipeLines, LP Annual Report 2019    F-21

Financial Statement Impact of Adopting Revenue from Contracts with Customers

The Partnership adopted the new guidance using the modified retrospective transition method. As a practical expedient under this transition method, the Partnership is not required to analyze completed contracts at the date of adoption. The adoption of the new guidance did not have a material impact on the Partnership’s previously reported consolidated financial statements at December 31, 2017.

Pro-forma Financial Statements under Legacy U.S. GAAP

At December 31, 2019 and 2018, had legacy U.S. GAAP been applied, there would be no change in the Partnership’s reported balance sheet and income statement line items.

Contract Balances

All of the Partnership’s contract balances pertain to receivables from contracts with customers amounting to $37 million at December 31, 2019 (December 31, 2018 - $44 million) and are recorded as Trade accounts receivable and reported as “Accounts receivable and other” in the Partnership’s consolidated balance sheet (Refer to Note 21).

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

Right to invoice practical expedient

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

NOTE 7  PROPERTY, PLANT AND EQUIPMENT

The following table includes property, plant and equipment of our consolidated entities:

	2019			2018
		Accumulated	Net Book		Accumulated	Net Book
December 31 (millions of dollars)	Cost	Depreciation	Value	Cost	Depreciation	Value
Pipeline	1,907	(929)	978	1,901	(876)	1,025
Compression	584	(202)	382	550	(182)	368
Metering and other	180	(56)	124	176	(52)	124
Construction in progress	44	-	44	12	—	12
	2,715	1,187	1,528	2,639	(1,110)	1,529

2018 Impairment of Bison’s long-lived assets

At December 31, 2018, the Partnership performed an impairment analysis on Bison’s long-lived assets in connection with the termination of certain customer transportation agreements (refer to Note 6 - Revenues).

With the loss of future cash flows resulting from the contract terminations described above and the persistence of unfavorable market conditions which inhibited systems flows on the pipeline during the fourth quarter of 2018, the Partnership recognized an impairment charge of $537 million relating to the remaining carrying value of Bison’s property, plant and equipment after determining that it was no longer recoverable. The impairment charge was recorded under Impairment of long-lived assets line on the Consolidated statement of operations.

The Partnership continues to explore alternative transportation-related options for Bison; however, management is currently unable to quantify the future cash flows of a viable, operating plan beyond the remaining customer contracts’ expiry in January 2021. The Partnership will continue to maintain Bison to stand ready for redevelopment and has concluded that the remaining obligations of Bison, primarily in the form of ad valorem tax obligations and operating and maintenance costs, exceed the net cash inflows that management currently considers probable and estimable.

F-22    TC PipeLines, LP Annual Report 2019

NOTE 8 ACQUISITIONS

2017 Acquisition

On June 1, 2017, the Partnership acquired from subsidiaries of TC Energy a 49.34 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (the 2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus final purchase price adjustments amounting to $50 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1, 2017), (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81 percent proportionate share in PNGTS’ outstanding debt on June 1, 2017) (iii) final working capital adjustments for Iroquois and PNGTS amounting to $19 million and $3 million, respectively and (iv) additional consideration of $28 million for the surplus cash on Iroquois’ balance sheet. Additionally, the Partnership paid $1,000 for the option to acquire TC Energy's remaining 0.66 percent interest in Iroquois, which expired on January 3, 2019. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 9) and borrowing under our senior facility under revolving credit agreement as amended and restated, dated September 29, 2017 (Senior Credit Facility).

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

Iroquois’ partners adopted a distribution resolution to address the surplus cash on its balance sheet post-closing of this acquisition transaction. The Partnership is expected to receive the $28.4 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of February 20, 2020, the Partnership has received $25.8 million , and the remaining balance is expected to be received by March 31, 2020.

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

Iroquois’ net purchase price was allocated as follows:

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

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

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

The acquisition of an additional 11.81 percent interest in PNGTS, which resulted in the Partnership owning 61.71 percent in PNGTS, was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby assets and liabilities of PNGTS were recorded at TC Energy's carrying value and the Partnership’s 2016 historical financial information, except net income per common unit, was recast to consolidate PNGTS for all periods presented.

TC PipeLines, LP Annual Report 2019    F-23

The PNGTS purchase price was recorded as follows:

(millions of dollars)
Current assets	25
Property, plant and equipment, net	294
Current liabilities	(4)
Deferred state income taxes	(10)
Long-term debt, including current portion	(41)
	264
Non-controlling interest	(100)
Carrying value of pre-existing Investment in PNGTS	(132)
TC Energy’s carrying value of the acquired 11.81 percent interest at June 1, 2017	32
Excess purchase price over net assets acquired (a)	21
Total cash consideration (b)	53

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

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

NOTE 9 DEBT AND CREDIT FACILITIES

			Weighted Average			Weighted Average
			Interest Rate for the			Interest Rate for the
			Year Ended			Year Ended
(millions of dollars)	2019		December 31, 2019		2018	December 31, 2018
TC PipeLines, LP
Senior Credit Facility due 2021	—		—		40	3.14	%
2013 Term Loan Facility due 2022	450		3.52	%	500	3.23	%
4.65% Unsecured Senior Notes due 2021	350		4.65	%(a)	350	4.65	%(a)
4.375% Unsecured Senior Notes due 2025	350		4.375	%(a)	350	4.375	%(a)
3.90 % Unsecured Senior Notes due 2027	500		3.90	%(a)	500	3.90	%(a)
GTN
5.29% Unsecured Senior Notes due 2020	100		5.29	%(a)	100	5.29	%(a)
5.69% Unsecured Senior Notes due 2035	150		5.69	%(a)	150	5.69	%(a)
Unsecured Term Loan Facility due 2019	—		—		35	2.93	%
PNGTS
Revolving Credit Facility due 2023	39		3.47	%	19	3.55	%
Tuscarora
Unsecured Term Loan due 2020	23		3.39	%	24	3.10	%
North Baja
Unsecured Term Loan due 2021	50		3.34	%	50	3.54	%
	2,012				2,118
Less:unamortized debt issuance costs and debt discount	9				10
Less: current portion	123	(b)			36
	1,880				2,072

(a) Fixed interest rate.

(b) Includes GTN’s 5.29% Unsecured Senior Notes due June 1, 2020 and Tuscarora’s Unsecured Term Loan due August 21, 2020.

TC PipeLines, LP

The Partnership’s Senior Credit Facility consists of a $500 million senior revolving credit facility with a banking syndicate, under which no borrowings were outstanding at December 31, 2019 (December 31, 2018 - $40 million), leaving $500 million available for future borrowing.

At the Partnership’s option, the interest rate on the outstanding borrowings under the Senior Credit Facility may be the lenders’ base rate or the London Interbank Offered Rate (LIBOR) plus, in either case, an applicable margin that is based on the Partnership’s long-term unsecured credit ratings. The Senior Credit Facility permits the Partnership to specify the portion of the borrowings to be covered by specific interest rate options and, for LIBOR-based borrowings, to specify the interest rate period. The Partnership is required to pay a commitment fee based on its credit rating and on the unused principal amount of the commitments under the Senior Credit Facility. The Senior Credit Facility has a feature whereby at

F-24    TC PipeLines, LP Annual Report 2019

any time, so long as no event of default has occurred and is continuing, the Partnership may request an increase in the Senior Credit Facility of up to $500 million, but no lender has an obligation to increase their respective share of the facility.

The LIBOR-based interest rate on the Senior Credit Facility was 3.77 percent at December 31, 2018.

On September 29, 2017, the Partnership’s term loan credit facility under a term loan agreement as amended on September 29, 2017 (2013 Term Loan Facility) was amended to extend the maturity period through October 2, 2022. The 2013 Term Loan Facility bears interest based, at the Partnership’s election, on the LIBOR or the base rate plus, in either case, an applicable margin. The base rate equals the highest of (i) SunTrust Bank’s prime rate, (ii) 0.50 percent above the U.S. federal funds rate and (iii) 1.00 percent above one-month LIBOR. The applicable margin for the term loan is based on the Partnership’s senior debt rating and ranges between 1.125 percent and 2.00 percent for LIBOR borrowings and 0.125 percent and 1.00 percent for base rate borrowings.

On June 26, 2019, the Partnership repaid $50 million of the principal balance under its 2013 Term Loan Facility using proceeds from Northern Border's additional distribution (see Note 5). Additionally, in conjunction with this repayment, the Partnership also terminated an equivalent amount in interest rate swaps that were used to hedge this facility at a rate of 2.81 percent. As of December 31, 2019, the variable interest rate exposure related to 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 3.26 percent (2018 – 3.26 percent). Prior to hedging activities, the LIBOR-based interest rate was 2.94 percent at December 31, 2019 (December 31, 2018 – 3.60 percent).

The Senior Credit Facility and the 2013 Term Loan Facility require the Partnership to maintain a debt to adjusted cash flow leverage ratio of no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 3.41 to 1.00 as of December 31, 2019.

The Senior Credit Facility and the 2013 Term Loan Facility contain additional covenants that include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurrence of additional debt by the Partnership’s subsidiaries and distributions to unitholders. Upon any breach of these covenants, amounts outstanding under the Senior Credit Facility and the 2013 Term Loan Facility may become immediately due and payable.

On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition (Refer to Note 8). The indenture for the notes contains customary investment grade covenants.

PNGTS

On April 5, 2018, PNGTS entered into a revolving credit agreement under which PNGTS has the ability to borrow up to $125 million with a variable interest rate based on LIBOR. The credit agreement matures on April 5, 2023 and requires PNGTS to maintain a leverage ratio not greater than 5.00 to 1.00. The leverage ratio was 0.70 to 1.00 as of December 31, 2019. The facility is being utilized by PNGTS primarily to fund the costs of its expansion projects and for general partnership purposes. As of December 31, 2019, $39 million was drawn on the Revolving Credit Facility and the LIBOR-based interest rate was 2.99 percent (December 31, 2018 - 3.60 percent).

GTN

GTN's Unsecured Senior Notes contain a covenant that limits total debt to no greater than 70 percent of GTN’s total capitalization. GTN’s total debt to total capitalization ratio at December 31, 2019 was 39.1 percent.

During the second quarter of 2019, GTN's Unsecured Term Loan Facility matured and was fully repaid using the Partnership's funds from operations. The LIBOR-based interest rate applicable to GTN's Unsecured Term Loan Facility was 3.30 percent at December 31, 2018.

GTN's $100 million 5.29% Unsecured Senior Notes due June 1, 2020 are expected to be refinanced in full or at an amount based on the Partnership's preferred capitalization levels.

Tuscarora

Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00 . As of December 31, 2019, the ratio was 8.72 to 1.00.

The LIBOR-based interest rate applicable to Tuscarora’s Unsecured Term Loan Facility was 2.82 percent at December 31, 2019 (December 31, 2018 - 3.47 percent).

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

TC PipeLines, LP Annual Report 2019    F-25

North Baja

On December 19, 2018, North Baja entered into a $50 million unsecured variable rate term loan facility, which matures on December 19, 2021. The net proceeds were used for general partnership purposes. The variable interest rate is based on LIBOR plus an applicable margin. The LIBOR-based interest rate on this term loan facility was 2.77 percent at December 31, 2019 (December 31, 2018 - 3.54 percent). North Baja’s Term Loan Facility contains a covenant that limits total debt to no greater than 70 percent of North Baja’s total capitalization. North Baja’s total debt to total capitalization ratio at December 31, 2019 is 39.8 percent.

Partnership (TC PipeLines, LP and its subsidiaries)

At December 31, 2019, the Partnership was in compliance with its financial covenants, in addition to the other covenants which include restrictions on entering into mergers, consolidations and sales of assets, granting liens, material amendments to the Partnership Agreement, incurring additional debt and distributions to unitholders.

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

(millions of dollars)
2020	123
2021	400
2022	450
2023	39
2024	—
Thereafter	1,000
	2,012

NOTE 10 OTHER LIABILITIES

December 31 (millions of dollars)	2019	2018
Regulatory liabilities	29	27
Other liabilities	7	2
	36	29

The Partnership collects estimated future removal costs related to its transmission and gathering facilities in its current rates (also known as “negative salvage”) and recognizes regulatory liabilities in this respect on the balance sheet. Estimated costs associated with the future removal of transmission and gathering facilities are collected through depreciation as allowed by FERC. These amounts do not represent asset retirement obligations as defined by FASB ASC 410, Accounting for Asset Retirement Obligations.

NOTE 11 PARTNERS’ EQUITY

At December 31, 2019, 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.

At-the-Market Equity Issuance Program (ATM Program)

In August 2014, we established an ATM Program that allowed the Partnership from time to time to offer and sell, through sales agents, common units representing limited partner interests. The ATM Program was initially established with an aggregate gross sales limit of $200 million.

In August 2016 we replenished the capacity available under the existing ATM Program to allow for the offer and sale of common units having an aggregate gross sales limit of up to $400 million.

In 2017, the Partnership issued 3.2 million common units under the ATM Program generating net proceeds of approximately $173 million, plus an additional $3 million from the General Partner to maintain its two percent interest. The commissions to our sales agents were approximately $2 million. The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility and for general partnership purposes.

F-26    TC PipeLines, LP Annual Report 2019

In 2018, the Partnership issued 0.7 million common units under the ATM Program generating net proceeds of approximately $39 million, plus an additional $1 million from the General Partner to maintain its two percent interest. The commissions to our sales agents were nil. The net proceeds were used to repay a portion of the borrowings under the Senior Credit Facility and for general partnership purposes.

In August 2019, the ATM Program expired with no common unit issuances in 2019.

Common unit issuance subject to rescission

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

No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. As a result of the expiration, the amount associated with these rights was reclassified back to partners’ equity. At December 31, 2019 and 2018, there were no outstanding common units subject to rescission on the Partnership’s consolidated balance sheet.

Issuance of Class B units

The Class B Units issued on April 1, 2015 to finance a portion of the Partnership’s acquisition of the remaining 30 percent interest of GTN from TC Energy represent a limited partner interest in us and entitle TC Energy to an annual distribution based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and (ii) 25 percent of distributions above $20 million thereafter. The Class B units contain no mandatory or optional redemption features and are also non-convertible, non-exchangeable, non-voting and rank equally with common units upon liquidation.

Additionally, the Class B Distribution was reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018. The Class B Reduction was implemented during the first quarter of 2018 following the Partnership’s common unit distribution reduction of 35 percent from its fourth quarter 2017 distribution level of $1.00 per common unit. 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.

The Class B units’ equity account is increased by the “Class B Distribution,” less the “Class B Reduction,” if any until such amount is declared for distribution and paid every first quarter of the subsequent year. For the years ended December 31, 2019, 2018 and 2017, the Class B units’ equity account was increased by $8 million, $13 million and $15 million, respectively. (Refer to Notes 14 and 15).

TC PipeLines, LP Annual Report 2019    F-27

NOTE 12 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The changes in accumulated other comprehensive income (loss) (AOCI) by component are as follows:

	Cash flow	Equity
(millions of dollars)	hedges	Investments	Total
Balance at December 31, 2016(a)	(2)	—	(2)
Change in fair value of cash flow hedges	5	—	5
Amounts reclassified from AOCI	—	—	—
PNGTS’ amortization of realized loss on derivative instrument (Note 20)	1	—	1
Other comprehensive income - effects of Iroquois’ retirement benefit plans	—	1	1
Net other comprehensive income	6	1	7
Balance at December 31, 2017	4	1	5
Change in fair value of cash flow hedges	(2)	—	(2)
Amounts reclassified from AOCI	5	—	5
PNGTS' amortization of realized loss on derivative instrument (Note 20)	1	—	1
Other comprehensive loss - effects of Iroquois’ retirement benefit plans	—	(1)	(1)
Net other comprehensive income (loss)	4	(1)	3
Balance as of December 31, 2018	8	—	8
Change in fair value of cash flow hedges	(13)	—	(13)
Amounts reclassified from AOCI	(1)	—	(1)
Other comprehensive income - effects of Iroquois’ retirement benefit plans	—	1	1
Net other comprehensive income (loss)	(14)	1	(13)
Balance as of December 31, 2019	(6)	1	(5)

(a) Recast to consolidate PNGTS (Refer to in Notes 2 and 8). Additionally, AOCI as presented here is net of non-controlling interest on PNGTS.

NOTE 13 FINANCIAL CHARGES AND OTHER

Year ended December 31 (millions of dollars)	2019	2018	2017
Interest expense(a)	88	95	83
Net realized gain related to the interest rate swaps	(1)	(2)	—
PNGTS’ amortization of realized loss on derivative instrument (Note 20)	—	1	1
Other	(4)	(2)	(2)
	83	92	82

(a) Interest expense includes amortization of debt issuance costs and discount costs.

NOTE 14 NET INCOME (LOSS) PER COMMON UNIT

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

The amounts allocable to the General Partner equals an amount based upon the General Partner’s two percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement (Refer to Note 15).

The amount allocable to the Class B units is based upon 30 percent of GTN’s distributable cash flow after certain annual thresholds and adjustments (Refer to Note 11).

F-28    TC PipeLines, LP Annual Report 2019

Net income (loss) per common unit was determined as follows:

(millions of dollars, except per common unit amounts)	2019		2018		2017
Net income (loss) attributable to controlling interests		280		(182)		252
Net income attributable to PNGTS' former parent (a)		—		—		(2)
Net income (loss) allocable to General Partner and Limited Partners		280		(182)		250
Incentive distributions attributable to the General Partner (b)		—		—		(12)
Net income attributable to the Class B units (c)		(8)		(13)		(15)
Net income (loss) allocable to the General Partner and common units		272		(195)		223
Net (income) loss allocable to the General Partner's two percent interest		(5)		4		(4)
Net income (loss) attributable to common units		267		(191)		219
Weighted average common units outstanding (millions) – basic and diluted		71.3		71.3		69.2
Net income (loss) per common unit – basic and diluted	$	3.74	$	(2.68)	$	3.16

(a) Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated to TC Energy and was not allocable to either the general partner, common units or Class B units.

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

(c) As discussed in Note 11, the Class B units entitle TC Energy to a distribution which is an amount based on 30 percent of GTN’s distributions after exceeding certain annual thresholds and Class B Reduction. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 – “Earnings per share,” the Partnership allocated the Class B units distribution in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2019 less the threshold level of $20 million (2018 and 2017 - less $20 million) and less the Class B Reduction (2019 - $4 million, 2018 - $7 million. The Class B Reduction did not apply during 2017).

NOTE 15 CASH DISTRIBUTIONS

The Partnership makes cash distributions to its partners with respect to each calendar quarter within 45 days after the end of each quarter. Distributions are based on available cash, as defined in the Partnership Agreement, which includes all cash and cash equivalents of the Partnership and working capital borrowings less reserves established by the General Partner.

Pursuant to the Partnership Agreement, the General Partner receives two percent of all cash distributions in regard to its general partner interest and is also entitled to incentive distributions as described below. The unitholders receive the remaining portion of the cash distribution.

The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and our General Partner after providing for Class B distributions based on the specified target distribution levels. The percentage interests set forth below for our General Partner include its IDRs and two percent general partner interest and assume our General Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The percentage interest distributions to the General Partner illustrated below that are in excess of its two percent general partner interest represent the IDRs.

		Marginal Percentage
		Interest in Distribution
	Total Quarterly Distribution	Common		General
	Per Unit Target Amount	Unitholders		Partner
Minimum Quarterly Distribution	$0.45	98	%	2	%
First Target Distribution	above $0.45 up to $0.81	98	%	2	%
Second Target Distribution	above $0.81 up to $0.88	85	%	15	%
Thereafter	above $0.88	75	%	25	%

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The following table provides information about our distributions (in millions, except per unit distributions amounts).

				Limited Partners				General Partner
		Per Unit		Common		Class B						Total Cash
Declaration Date	Payment Date	Distribution		Units		Units(b)		2%		IDRs(a)		Distribution
1/23/2017	2/14/2017	$	0.94	$	64	$	22	$	2	$	2	$	90
4/25/2017	5/15/2017	$	0.94	$	65	$	—	$	1	$	2	$	68
7/20/2017	8/11/2017	$	1.00	$	69	$	—	$	2	$	3	$	74
10/24/2017	11/14/2017	$	1.00	$	70	$	—	$	1	$	3	$	74
1/23/2018	2/13/2018	$	1.00	$	71	$	15	$	2	$	3	$	91
5/1/2018	5/15/2018	$	0.65	$	46	$	—	$	1	$	—	$	47
7/26/2018	8/15/2018	$	0.65	$	46	$	—	$	1	$	—	$	47
10/23/2018	11/14/2018	$	0.65	$	46	$	—	$	1	$	—	$	47
1/22/2019	2/11/2019	$	0.65	$	46	$	13	$	1	$	—	$	60
4/23/2019	5/13/2019	$	0.65	$	46	$	—	$	1	$	—	$	47
7/23/2019	8/14/2019	$	0.65	$	46	$	—	$	1	$	—	$	47
10/22/2019	11/14/2019	$	0.65	$	46	$	—	$	1	$	—	$	47
1/21/2020 (c)	2/14/2020 (c)	$	0.65	$	46	$	8	$	1	$	—	$	55

(a) The distributions paid during the year ended December 31, 2019 included no incentive distributions to the General Partner (2018 - $3 million, 2017 - $10 million).

(b) The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TC Energy to an annual distribution which is an amount based on 30 percent of GTN’s annual distributions after exceeding certain annual thresholds and adjustments (refer to Note 11)

(c) On February 14, 2020, we paid a cash distribution of $0.65 per unit on our outstanding common units to unitholders of record at the close of business on January 31, 2020 (refer to Note 24).

NOTE 16 CHANGE IN OPERATING WORKING CAPITAL

Year Ended December 31 (millions of dollars)	2019	2018	2017
Change in accounts receivable and other	9	(6)	4
Change in inventory	(2)	—	—
Change in other current assets	—	(1)	2
Change in accounts payable and accrued liabilities (a)	(11)	3	(7)
Change in accounts payable to affiliates	2	1	(3)
Change in accrued interest	(1)	—	2
Change in operating working capital	(3)	(3)	(2)

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

NOTE 17 TRANSACTIONS WITH MAJOR CUSTOMERS

For the year ended December 31, 2019, no customer accounted for more than 10 percent of our consolidated revenue and trade accounts receivable.

At December 31, 2018, Tenaska owed the Partnership approximately $4 million,which was approximately 10 percent of our consolidated trade accounts receivable. As noted under Note 6, in 2018, Tenaska assumed Anadarko’s ship-or-pay contract obligation on Bison. After assuming the transportation obligation, Bison accepted an offer from Tenaska to terminate its contract. For the year ended December 31, 2018, revenues from both Anadarko and Tenaska amounted to $144 million.

At December 31, 2017, Anadarko owed the Partnership approximately $4 million, which was approximately 10 percent of our consolidated trade accounts receivable. For the year ended December 31, 2017, revenues from Anadarko amounted to $48 million, which was approximately 10 percent of our consolidated revenue.

NOTE 18 RELATED PARTY TRANSACTIONS

The Partnership does not have any employees. The management and operating functions are provided by the General Partner. The General Partner does not receive a management fee in connection with its management of the Partnership.

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The Partnership reimburses the General Partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. Total costs charged to the Partnership by the General Partner was $4 million for the year ended December 31, 2019 (2018-$4 million; 2017-$4 million)

As operators of most of our pipelines (except Iroquois and the Pipeline facilities jointly owned with MNE on PNGTS (the Joint Facilities)), TC Energy’s subsidiaries provide capital and operating services to our pipeline systems. TC Energy’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Joint Facilities are operated by MNOC. Therefore, Iroquois and the Joint Facilities do not receive capital and operating services from TC Energy.

Capital and operating costs charged to our pipeline systems, except for Iroquois, for the years ended December 31, 2019, 2018 and 2017 by TC Energy's subsidiaries and amounts payable to TC Energy's subsidiaries at December 31, 2019 and 2018 are summarized in the following tables:

Year ended December 31 (millions of dollars)	2019	2018	2017
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes (a)	47	44	36
Northern Border(a)	39	36	43
PNGTS (a)	7	9	9
GTN	45	34	34
Bison	2	6	6
North Baja	5	4	4
Tuscarora	4	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	20	19	15
Northern Border	18	16	16
PNGTS	4	5	5
GTN	33	28	29
Bison	2	6	6
North Baja	4	4	4
Tuscarora	4	4	4

December 31 (millions of dollars)	2019	2018
Amount payable to TC Energy’s subsidiaries for costs charged in the year by:
Great Lakes (a)	5	3
Northern Border(a)	4	3
PNGTS (a)	1	1
GTN	5	4
Bison	—	1
North Baja	1	—
Tuscarora	—	1

(a) Represents 100 percent of the costs.

Great Lakes

Great Lakes earns significant transportation revenues from TC Energy and its affiliates. For the year ended December 31, 2019, Great Lakes earned 73 percent of its transportation revenues from TC Energy and its affiliates (2018 – 73 percent; 2017 – 57 percent). Additionally, included in Great Lakes’ other revenues were cost recovery charges to its affiliates for use of office space in the building it owns (which was sold to a third party in the third quarter of 2019) and comprised less than one percent of its total revenues in 2019 and 2018 (2017– 1 percent).

At December 31, 2019, $19 million was included in Great Lakes’ receivables in regard to the transportation contracts with TC Energy and its affiliates (December 31, 2018 – $18 million).

During 2017, Great Lakes operated under a FERC approved 2013 rate settlement that included a revenue sharing mechanism requiring Great Lakes to share with its customers certain percentages of any qualifying revenues earned above certain ROEs (the 2017 Great Lakes Settlement). During the second quarter of 2018, the refund was settled with customers and a significant portion was refunded to affiliates. Under the terms of the 2017 Great Lakes Settlement, beginning in 2018, the revenue sharing mechanism was eliminated.

TC PipeLines, LP Annual Report 2019    F-31

Great Lakes has a cash management agreement with TC Energy whereby Great Lakes’ funds are pooled with other TC Energy affiliates. The agreement also gives Great Lakes the ability to obtain short-term borrowings to provide liquidity for Great Lakes’ operating needs. At December 31, 2019 and 2018, Great Lakes had outstanding receivables from this arrangement amounting to $34 million and $36 million, respectively.

Great Lakes has a long-term transportation agreement with TC Energy's Canadian Mainline that commenced on November 1, 2017 for a ten-year period and allows TC Energy to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system. This contract, which contains volume reduction options up to full contract quantity beginning in year three, was a direct benefit from TC Energy’s long-term fixed price service on its Canadian Mainline that was launched in 2017. For the year ended December 31, 2019, the total revenue earned by Great Lakes on this contract was $76 million. (2018 - $76 million; 2017 - $13 million).

In 2018, Great Lakes executed long-term transportation capacity contracts with its affiliate, ANR Pipeline Company(ANR). The contracts are for a term of 15 years from November 2021 to October 31, 2036 with a total contract value of approximately $1.3 billion. The contracts contain reduction options (i) at any time on or before April 1, 2020 for any reason and (ii) any time before April 2021, if ANR is not able to secure the required regulatory approval related to anticipated expansion projects.

PNGTS

For the three years ended December 31, 2019, PNGTS provided transportation to TransCanada Energy Ltd., a subsidiary of TC Energy and earned revenues of less than $1 million in 2019 (2018-$1 million; 2017-$1 million). At December 31, 2019 and 2018, PNGTS had no outstanding receivables from TransCanada Energy Ltd. in the consolidated balance sheets.

In connection with the Portland XPress expansion project (PXP), which was designed to be phased in over a three-year time period, PNGTS has entered into an arrangement with its affiliates regarding the construction of certain facilities on their systems that will be required to fulfill future contracts on the PNGTS system. PXP Phases I and II were placed into service on November 1, 2018 and November 1, 2019, respectively. Phase III is estimated to be in service on November 1, 2020. In the event the expansions terminate prior to their in-service dates, PNGTS will be required to reimburse its affiliates for any costs incurred related to the development of these facilities, which was over $140 million prior to November 1, 2019. As a result of placing the TC Energy facilities associated with the Phase II volumes in service, PNGTS' obligation to reimburse development costs with respect to Phases I and II terminated.

Going forward, in the event the Phase III expansion terminates prior to its in-service date, PNGTS will only be obligated to reimburse costs incurred by TC Energy in relation to Phase III, which was $0.6 million at December 31, 2019 and estimated to be approximately $8.0 million by November 1, 2020, when Phase III goes into service.

NOTE 19 QUARTERLY FINANCIAL DATA (unaudited)

The following sets forth selected unaudited financial data for the four quarters in 2019 and 2018:

Quarter ended (millions of dollars except per common unit amounts)	Mar 31			Jun 30		Sept 30			Dec 31
2019
Transmission revenues		113			93		93			104
Equity earnings		54			30		31			45
Net income (loss)		100			57		59			82
Net income (loss) attributable to controlling interests		93			55		56			76
Net income (loss) per common unit	$	1.28		$	0.75	$	0.76		$	0.95
Cash distributions paid to common units		47			47		47			47
Cash distribution paid to Class B units		13			—		—			—
2018
Transmission revenues		115			111		103	(b)		220	(c)
Equity earnings		59			36		34			44
Net income		102			75		65			(406)
Net income attributable to controlling interests		96			73		62			(413)
Net income per common unit	$	1.32		$	1.00	$	0.79		$	(5.80)
Cash distributions paid to common units		76	(a)		47		47			47
Cash distribution paid to Class B units		15			—		—			—

(a) Distributions paid to common units includes our general partner’s two percent share and IDRs.

(b) Net of a $9 million provision for revenue sharing recognized as part of the 2018 GTN Settlement, in which GTN agreed to issue a refund of $10 million allocated amongst its firm customers from January 1, 2018 to October 31, 2018 (Refer to Note 4).

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(c) Net of a $1 million provision for revenue sharing recognized as part of the 2018 GTN Settlement, in which GTN agreed to issue a refund of $10 million allocated amongst its firm customers from January 1, 2018 to October 31, 2018 (Refer to Note 4). This amount also includes the $97 million proceeds received by Bison from the termination of certain customer contracts (Refer to Note 6).

NOTE 20 FAIR VALUE MEASUREMENTS

(a) Fair Value Hierarchy

Under ASC 820, Fair Value Measurements and Disclosures, fair value measurements are characterized in one of three levels based upon the input used to arrive at the measurement. The three levels of the fair value hierarchy are as follows:

● Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date.

● Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

● Level 3 inputs are unobservable inputs for the asset or liability.

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

(b) Fair Value of Financial Instruments

The carrying value of cash and cash equivalents, accounts receivable and other, accounts payable and accrued liabilities, accounts payable to affiliates, accrued interest and short-term debt are classified as Level 1 in fair value hierarchy. Accordingly, the carrying values approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s long-term debt is estimated by discounting the future cash flows of each instrument at estimated current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach which uses period-end market rates and applies a discounted cash flow valuation model.

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

Long-term debt is recorded at amortized cost and classified as a Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified as a Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership's debt as at December 31, 2019 and December 31, 2018 was $2,111 million and $2,101 million, respectively.

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

The Partnership’s interest rate swaps mature on October 2, 2022 and are structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The fixed weighted average interest rate on these instruments is 3.26 percent. On June 26, 2019, in conjunction with the Partnership's $50 million repayment on its 2013 Term Loan Facility , the Partnership also terminated an equivalent amount in interest rate swaps that were used to hedge this facility at an unwind rate of 2.81 percent (See also Note 9).

At December 31, 2019, the fair value of the interest rate swaps accounted for as cash flow hedges was a liability of $6 million (on both gross and net basis) (December 31, 2018 - asset of $8 million), the net change of which is recognized in other comprehensive income. For the year ended December 31, 2019, the net realized gain related to interest rate swaps was $1 million and was included in financial charges and other (2018 – $2 million,2017 –nil). Refer to Note 13 – Financial Charges and Other.

The Partnership has no master netting agreements; however, its contracts contain provisions with rights of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of December 31, 2019 and 2018.

In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its 5.90 % Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and

TC PipeLines, LP Annual Report 2019    F-33

Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in AOCI as of the termination date. At December 31, 2018, and as a result of the repayment of the 5.90% Senior Secured Notes, the remaining balance of the $20.9 million realized loss in AOCI included in other comprehensive income at the termination date was fully amortized against earnings. For the years ended December 31, 2018 and 2017, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was $1 million for each year.

Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as cash and cash equivalents and receivables, as well as the fair value of derivative financial assets. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At December 31, 2019, we had not incurred any significant credit losses and had no significant amounts past due or impaired. At December 31, 2019, no customer accounted for more than 10 percent of our consolidated revenues and accounts receivable, respectively (refer also to Note 17 for more details).

(c) Other

The estimated fair value measurements on Tuscarora’s goodwill, Bison’s long-lived assets and our equity investment in Great Lakes, are classified as Level 3. In the determination of fair value utilized in the recoverability assessments for the respective assets, we used internal forecasts on expected future cash flows and applied appropriate discount rates. The determination of expected future cash flows involved significant assumptions and estimates as discussed more fully in Notes 4 (Tuscarora), 5 (Great Lakes) and 7 (Bison).

NOTE 21 ACCOUNTS RECEIVABLE AND OTHER

December 31 (millions of dollars)	2019	2018
Trade accounts receivable, net of allowance of nil	37	44
Imbalance receivable from affiliates	—	2
Other	6	2
	43	48

NOTE 22 CONTINGENCIES

The Partnership and its pipeline systems are subject to various legal proceedings in the ordinary course of business. Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated in accordance with ASC 450, Contingencies. We base these estimates on currently available facts and the estimates of the ultimate outcome or resolution. Actual results may differ from estimates resulting in an impact, positive or negative, on earnings and cash flow. Contingencies that might result in a gain are not accrued in our consolidated financial statements.

At December 31, 2019, the Partnership is not aware of any contingent liabilities that would have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.

NOTE 23 VARIABLE INTEREST ENTITIES (VIEs)

In the normal course of business, the Partnership must re-evaluate its legal entities under the current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other GAAP. A variable interest entity (VIE) is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

As a result of its 2018 analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but

F-34    TC PipeLines, LP Annual Report 2019

has a variable interest in the entity, are accounted for as equity investments. Information related to the Partnership's VIEs are disclosed below:

Consolidated VIEs

The Partnership's consolidated VIEs consist of the intermediate partnerships and mainly the Partnership's ILPs that hold interests in the Partnership's pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability it absorbs from the ILPs' economic performance.

The assets and liabilities held through these VIEs that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership are held through GTN, Tuscarora, Northern Border, Great Lakes, PNGTS, Iroquois, and effective December 31, 2018, North Baja due to their third-party debt.

Beginning October 31, 2019, the Partnership owns its pipeline assets directly as a result of the dissolution of the three ILPs and Intermediate GP as disclosed under Note 1- Organization. As a result, the Partnership's remaining VIE pertains to its variable interest in Great Lakes, which is accounted as an equity investment since the Partnership is not the primary beneficiary.

The following table presents the total assets and liabilities of these entities that are included in the Partnership's consolidated balance sheets:

	December 31,		December 31,
(millions of dollars)	2019		2018(a)
ASSETS (LIABILITIES)
Cash and cash equivalents	—		16
Accounts receivable and other	—		39
Inventories	—		8
Other current assets	—		6
Equity investments	491	(b)	1,196
Property, plant and equipment	—		1,240
Other assets	—		1
Accounts payable and accrued liabilities	—		(33)
Accounts payable to affiliates, net	—		(40)
Distributions payable	—		—
Accrued interest	—		(2)
Current portion of long-term debt	—		(36)
Long-term debt	—		(341)
Other liabilities	—		(27)
Deferred state income tax	—		(9)

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

(b) Equity investment on Great Lakes (Refer to Note 5)

NOTE 24 SUBSEQUENT EVENTS

Management of the Partnership has reviewed subsequent events through February 20, 2020, the date the financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.

Partnership

On January 21, 2020, the board of directors of our General Partner declared the Partnership's fourth quarter 2019 cash distribution in the amount of $0.65 per common unit and was paid on February 14, 2020 to unitholders of record as of January 31, 2020. The declared distribution totaled $47 million and is payable in the following manner: $46 million to common unitholders (including $4 million to the General Partner as a holder of 5,797,106 common units and $7 million to another subsidiary of TC Energy as holder of 11,287,725 common units) and $1 million to the General Partner for its two percent general partner interest. The General Partner did not receive any distributions in respect of its IDRs for the fourth quarter 2019.

TC PipeLines, LP Annual Report 2019    F-35

On January 21, 2020, the board of directors of our General Partner declared its annual distribution to Class B units in the amount of $8 million which was paid on February 14, 2020. The Class B distribution represents an amount equal to 30 percent of GTN's distributable cash flow during the year ended December 31, 2019 less $20 million and the Class B Reduction.

Northern Border

Northern Border declared its December 2019 distribution of $18 million on January 10, 2020, of which the Partnership received its 50 percent share or $9 million on January 31, 2020.

Northern Border declared its January 2020 distribution of $19 million on February 11, 2020, of which the Partnership will receive its 50 percent share or $9 million on February 28, 2020.

Great Lakes

Great Lakes declared its fourth quarter 2019 distribution of $34 million on January 10, 2020, of which the Partnership received its 46.45 percent share or $16 million on January 31, 2020.

Iroquois

Iroquois declared its fourth quarter 2019 distribution of $27 million in February 2020, and the Partnership will receive its 49.34 percent share or $13 million on March 30, 2020. The $13 million includes our proportionate share of Iroquois’ unrestricted cash amounting to $2.6 million (refer to Note 8).

PNGTS

PNGTS declared its fourth quarter 2019 distribution of $ 18 million on January 15, 2020, of which $7 million was paid to its non-controlling interest owner on January 31, 2020.

F-36    TC PipeLines, LP Annual Report 2019

Independent Auditors’ Report

The Management Committee

Northern Border Pipeline Company:

We have audited the accompanying financial statements of Northern Border Pipeline Company, which comprise the balance sheets as of December 31, 2019 and 2018, and the related statements of income, comprehensive income, changes in partners’ equity, and cash flows for the years in the three-year period ended December 31, 2019, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northern Border Pipeline Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019 in accordance with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas
February 14, 2020

F-37    TC PipeLines, LP Annual Report 2019

NORTHERN BORDER PIPELINE COMPANY

BALANCE SHEETS

December 31, 2019 and 2018 (In thousands)	2019		2018
Assets
Current assets:
Cash and cash equivalents	$	20,667	9,599
Accounts receivable		24,418	25,641
Related party receivables		4,391	3,271
Materials and supplies		5,706	5,612
Prepaid expenses and other		2,783	2,132
Total current assets		57,965	46,255
Property, plant and equipment:
In-service natural gas transmission plant		2,633,800	2,638,014
Construction work in progress		1,601	2,866
Right of use asset		156	—
Total property, plant and equipment		2,635,557	2,640,880
Less: Accumulated provision for depreciation and amortization		1,646,711	1,604,566
Property, plant and equipment, net		988,846	1,036,314
Other assets:
Regulatory assets		12,436	13,215
Total assets	$	1,059,247	1,095,784
Liabilities and Partners' Equity
Current liabilities:
Accounts payable	$	3,663	3,298
Related party payables		4,421	3,680
Accrued taxes other than income		18,369	19,306
Accrued interest		4,986	4,731
Customer advances for construction		10,517	2,730
Other current liabilities		22	—
Total current liabilities		41,978	33,745
Long-term debt, net		364,352	264,455
Deferred credits and other liabilities
Regulatory liability		33,219	29,598
Other		5,280	4,740
Total deferred credits and other liabilities		38,499	34,338
Total liabilities		444,829	332,538
Partners' equity:
Partners' capital		615,052	764,209
Accumulated other comprehensive loss		(634)	(963)
Total partners' equity		614,418	763,246
Total liabilities and partners' equity	$	1,059,247	1,095,784

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

F-38    TC PipeLines, LP Annual Report 2019

NORTHERN BORDER PIPELINE COMPANY

STATEMENTS OF INCOME

Years ended December 31, 2019, 2018, and 2017 (In thousands)		2019	2018	2017
Operating revenue	$	300,221	289,418	291,396
Operating expenses:
Operations and maintenance		60,428	54,576	54,374
Depreciation and amortization		61,588	60,492	59,426
Taxes other than income		22,539	23,892	23,480
Operating expenses		144,555	138,960	137,280
Operating income		155,666	150,458	154,116
Interest expense:
Interest expense		21,727	19,943	22,257
Interest expense capitalized		(37)	(101)	(176)
Interest expense, net		21,690	19,842	22,081
Other income (expense):
Allowance for equity funds used during construction		318	623	573
Other income		3,805	4,505	3,936
Other expense		(357)	(37)	(238)
Other income, net		3,766	5,091	4,271
Net income to partners	$	137,742	135,707	136,306

F-39    TC PipeLines, LP Annual Report 2019

NORTHERN BORDER PIPELINE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME

Years ended December 31, 2019, 2018, and 2017 (In thousands)	2019		2018	2017
Net income to partners	$	137,742	135,707	136,306
Other comprehensive income:
Changes associated with hedging transactions		329	306	285
Total comprehensive income	$	138,071	136,013	136,591

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

F-40    TC PipeLines, LP Annual Report 2019

NORTHERN BORDER PIPELINE COMPANY

STATEMENTS OF CASH FLOWS

Years ended December 31, 2019, 2018, and 2017 (In thousands)	2019		2018	2017
Cash flows from operating activities:
Net income to partners	$	137,742	135,707	136,306
Adjustments to reconcile net income to partners to net cash provided by operating activities:
Depreciation and amortization		61,588	60,492	59,426
Allowance for equity funds used during construction		(318)	(623)	(573)
Changes in components of working capital		578	(5,909)	(1,411)
Amortization of debt expense		226	704	795
Other		1,708	2,208	(389)
Total adjustments		63,782	56,872	57,848
Net cash provided by operating activities		201,524	192,579	194,154
Cash flows used in investing activities:
Capital expenditures		(11,344)	(31,269)	(27,054)
Other		7,787	646	(722)
Net cash used in investing activities		(3,557)	(30,623)	(27,776)
Cash flows used in financing activities:
Equity contributions from partners		—	—	166,000
Distributions to partners		(286,899)	(166,367)	(165,903)
Proceeds from issuance of debt		100,000	—	—
Repayment of debt		—	—	(166,000)
Net cash used in financing activities		(186,899)	(166,367)	(165,903)
Net change in cash and cash equivalents		11,068	(4,411)	475
Cash and cash equivalents at beginning of year		9,599	14,010	13,535
Cash and cash equivalents at end of year	$	20,667	9,599	14,010
Supplemental disclosure for cash flow information:
Cash paid for interest, net of amount capitalized	$	20,857	19,098	21,301
Accruals for property, plant and equipment		635	1,479	2,592
Changes in components of working capital:
Accounts receivable	$	1,223	(903)	(1,254)
Related party receivables		(1,120)	(222)	454
Materials and supplies		(94)	(396)	511
Prepaid expenses and other		(699)	(167)	319
Accounts payable		1,209	(5,834)	(1,702)
Related party payables		741	2,119	709
Accrued taxes other than income		(937)	(303)	(676)
Accrued interest		255	40	(15)
Other current liabilities		—	(243)	243
Total	$	578	(5,909)	(1,411)

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

F-41    TC PipeLines, LP Annual Report 2019

NORTHERN BORDER PIPELINE COMPANY

Statements of Changes in Partners' Equity

			ONEOK
			Northern
			Border
			Pipeline	Accumulated
			Company	Other	Total
	TC PipeLines,		Holdings,	Comprehensive	Partners'
(In thousands)	LP		L.L.C.	Income (Loss)	Equity
Partners' equity at December 31, 2016	$	329,233	329,233	(1,554)	656,912
Net income to partners		68,153	68,153	—	136,306
Changes associated with
hedging transactions		—	—	285	285
Contributions from partners		83,000	83,000	—	166,000
Distributions to partners		(82,952)	(82,951)	—	(165,903)
Partners' equity at December 31, 2017	$	397,434	397,435	(1,269)	793,600
Net income to partners		67,854	67,853	—	135,707
Changes associated with
hedging transactions		—	—	306	306
Distributions to partners		(83,184)	(83,183)	—	(166,367)
Partners' equity at December 31, 2018	$	382,104	382,105	(963)	763,246
Net income to partners		68,871	68,871	—	137,742
Changes associated with
hedging transactions		—	—	329	329
Distributions to partners		(143,449)	(143,450)	—	(286,899)
Partners' equity at December 31, 2019	$	307,526	307,526	(634)	614,418

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

F-42    TC PipeLines, LP Annual Report 2019

NORTHERN BORDER PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

Years ended December 31, 2019 and 2018

1. DESCRIPTION OF BUSINESS

Northern Border Pipeline Company (the Partnership) is a Texas general partnership formed in 1978. The Partnership owns a 1,263-mile natural gas transmission pipeline system, which includes an additional 149 pipeline miles parallel to the original system, extending from the United States-Canadian border near Port of Morgan, Montana, to a terminus near North Hayden, Indiana. The partners and ownership percentages were as follows:

Partner	Ownership
ONEOK Northern Border Pipeline Company Holdings, L.L.C.	50	%
TC PipeLines, LP	50	%

Previously, TC PipeLines Intermediate Limited Partnership (TCILP) and ONEOK Partners Intermediate Limited Partnership (ONEOK LP) each held a 50 percent interest in the Partnership. Effective October 31, 2019, TCILP transferred 100 percent of its 50 percent interest in the Partnership to its affiliate TC PipeLines, LP (TCP). On November 19, 2019, ONEOK LP transferred 100 percent of its 50 percent interest in the Partnership to its affiliate ONEOK Northern Border Pipeline Company Holdings, L.L.C.

TC PipeLines, LP (TCP) is an indirect subsidiary of TC Energy Corporation (TC Energy), formerly known as TransCanada Corporation. ONEOK Northern Border Pipeline Company Holdings, L.L.C. (ONEOK) is an indirect subsidiary of ONEOK, Inc.

The Partnership is managed by a Management Committee that consists of four members. Each partner designates two members and TCP designates one of its members as chairman.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a)    Basis of Presentation

The Partnership’s financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles (GAAP). Certain prior year amounts have been reclassified to conform to the current year presentation.

(b)    Use of Estimates

The preparation of the financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities during the reported period. Although management believes these estimates are reasonable, actual results could differ from these estimates in the financial statements and accompanying notes.

(c)    Cash and Cash Equivalents

The Partnership’s cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

(d)     Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest, except for those receivables subject to late charges. The Partnership maintains an allowance for doubtful accounts for estimated losses on accounts receivable, if it is determined the Partnership will not collect all or part of the outstanding receivable balance. The Partnership regularly reviews its allowance for doubtful accounts and establishes or adjusts the allowance as necessary using the specific-identification method. Account balances are charged to the allowance after all means of collection have been exhausted and the potential for recovery is no longer considered probable. Accounts written off in 2019 and 2018 were not material to the Partnership’s financial statements.

(e)    Natural Gas Imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in-kind, subject to the terms of the Partnership’s tariff.

F-43    TC PipeLines, LP Annual Report 2019

Imbalances due from others are reported on the balance sheets as trade accounts receivable and related party receivables. Imbalances owed to others are reported on the balance sheets as trade accounts payable and related party payables. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.

(f)    Material and Supplies

The Partnership’s inventories primarily consist of materials and supplies and are carried at lower of weighted average cost and net realizable value.

(g)    Accounting for Regulated Operations

The Partnership’s natural gas pipeline is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 980, Regulated Operations, provides that rate regulated enterprises account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. The Partnership evaluates the continued applicability of regulatory accounting, considering such factors as regulatory charges, the impact of competition, and the ability to recover regulatory assets as set forth in ASC 980. Accordingly, certain assets and liabilities that result from the regulated ratemaking process are reflected on the balance sheets as regulatory assets and regulatory liabilities.

The following table presents regulatory assets and liability at December 31, 2019 and 2018:

				Remaining
				recovery/
	December 31,			settlement
	2019		2018	period
	(In thousands)			(Years)
Regulatory Assets
Fort Peck lease option	$	11,513	11,831	36
Pipeline extension project		923	1,384	2
Volumetric fuel tracker		139	182	(a)
Compressor usage surcharge		—	6	(b)
		12,575	13,403
Less: Current portion included in Prepaid expenses and other		139	188
	$	12,436	13,215
Regulatory Liabilities
Negative salvage	$	31,966	29,598	(c)
Compressor usage surcharge		1,253	—	(b)
	$	33,219	29,598

(a) Volumetric fuel tracker assets or liabilities are continuously settled with in-kind exchanges with customers

(b) Compressor usage surcharge is designed to track the recovery of the actual costs related to both electricity usage at the Partnership’s electric compressors and compressor fuel use taxes imposed on the consumption of natural gas powered stations along the Partnership’s pipeline system (refer to Note 4(b))

(c) Negative salvage accrued for estimated net costs of removal of transmission plant has a settlement period related to the estimated life of the assets (refer to Note 2(h))

(h)    Property, Plant and Equipment

Property, plant and equipment are recorded at their original cost of construction. For assets the Partnership constructs, direct costs, such as labor and materials, and indirect costs, such as overhead, interest, and an equity return component on regulated businesses as allowed by the FERC, are capitalized. The Partnership capitalizes major units of property replacements or improvements and expenses minor items.

The Partnership uses the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. The depreciation rate is applied to the total cost of the group until its net book value equals its salvage value. All asset groups are depreciated using depreciation rates approved in the Partnership’s last rate proceeding. Currently, the Partnership’s depreciation rates vary from 2% to 20% per year. Using these rates, the remaining depreciable life of these assets ranges from 1 to 35 years.

The Partnership collects estimated future removal costs related to its transmission and gathering facilities in its current rates (also known as “negative salvage”) and recognizes a regulatory liability in this respect in the balance sheets.

F-44    TC PipeLines, LP Annual Report 2019

Estimated costs associated with the future removal of transmission and gathering facilities are collected through depreciation as allowed by FERC. These amounts do not represent asset retirement obligations as defined by FASB ASC 410, Accounting for Asset Retirement Obligations. When property, plant and equipment are retired, the Partnership charges accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove, sell, or dispose of the assets, less their salvage value. The Partnership does not recognize a gain or loss unless an entire operating unit is sold or retired. The Partnership includes gains or losses on dispositions of operating units in income.

The Partnership capitalizes a carrying cost on funds invested in the construction of long-lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC). AFUDC is recorded based on the Partnership’s average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of the asset on the balance sheets.

(i)    Long-Lived Assets

Long-lived assets, such as property, plant and equipment, and purchased intangible assets subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group be tested for possible impairment, the Partnership first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values, and third-party independent appraisals, as considered necessary.

(j)    Revenue Recognition

The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Partnership utilizes the practical expedient of recognizing revenue as invoiced. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.

The Partnership's pipeline systems are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. As of December 31, 2019, and 2018, there are no refund provisions reflected in these financial statements.

(k)    Asset Retirement Obligations

The Partnership accounts for asset retirement obligations pursuant to the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires the Partnership to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long lived assets that result from the acquisition, construction, development, and/or normal use of the assets. ASC 410-20 also requires the Partnership to record a corresponding asset that is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is to be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation.

The fair value of a liability for an asset retirement obligation is recorded during the period in which the liability is incurred, if a reasonable estimate of fair value can be made. The Partnership has determined that asset retirement obligations exist for certain of its transmission assets; however, the fair value of the obligations cannot be determined because the end of the transmission system’s life is not determinable with the degree of accuracy necessary to currently establish a liability for the obligations.

The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2019 and 2018. The Partnership continues to evaluate its asset retirement obligations and future developments that could impact amounts it records.

F-45    TC PipeLines, LP Annual Report 2019

(l)    Derivative Instruments and Hedging Activities

The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings.

The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). In a cash flow hedging relationship, the change in the fair value of the hedging derivative is reported as a component of other comprehensive income and reclassified into earnings as part of “interest expense” in the same period or periods during which the hedged transaction affects earnings or is reclassified immediately to net income when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur.

In some instances, the derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change.

Prior to December 31, 2001, the Partnership terminated a series of interest rate derivatives in exchange for cash. These derivatives had previously been accounted for as hedges with $4.1 million recorded in accumulated other comprehensive loss (AOCL) as of the termination date. The previously recorded AOCL is currently being reclassified to “interest expense’ using the effective interest method over the remaining term of the related hedged instrument, the Partnership’s 2001 Senior Notes due 2021. At December 31, 2019, the remaining balance in AOCL that is left to be reclassified to earnings is $0.6 million, of which $0.4 million is expected to be reclassified in 2020.

The Partnership had no other derivative instruments during the year ended December 31, 2019.

(m)    Debt Issuance Costs

Costs related to the issuance of debt are deferred and amortized using the effective-interest rate method over the term of the related debt.

The Partnership amortizes premiums and discounts incurred in connection with the issuance of debt consistent with the terms of the respective debt instrument.

Debt issuance costs are presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount. In addition, amortization of debt issuance costs, premiums, and discounts are reported as part of interest expense.

(n)    Income Taxes

Income taxes are the responsibility of the partners and are not reflected in these financial statements.

(o)    Fair Value Measurements

For cash and cash equivalents, receivables, accounts payable and certain accrued expenses, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments, fair value is estimated based upon market values (if applicable) or on the current interest rates available to the Partnership for debt with similar terms and remaining maturities. Judgment is required in developing these estimates.

3. ACCOUNTING CHANGES

(a)    Changes in Accounting Policies effective January 1, 2019

Leases

In February 2016, the Financial Accounting Standards Board (FASB) issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the consolidated balance sheet for all leases with a term longer than twelve months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the consolidated statements of income. The new guidance does not make extensive changes to previous lessor accounting.

Under the new guidance, the Partnership determines if an arrangement is a lease at inception. Operating leases are recognized as ROU assets and included in Property, plant and equipment while corresponding liabilities are included in “Other current liabilities”, and “Other long-term liabilities” on the balance sheets.

F-46    TC PipeLines, LP Annual Report 2019

Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. If the Partnership’s leases do not have an implicate rate, the present value of future minimum payments, if any, will be determined using a rate that approximates the Partnership’s borrowing cost. Operating lease expense is recognized on a straight-line basis over the lease term and included in “Operation and maintenance” expenses” in the statements of income.

The new guidance was effective January 1, 2019 and was applied using optional transition relief which allowed entities to initially apply the new lease standard at adoption and recognize a cumulative-effect adjustment to the opening balance of equity in the period of adoption. This transition option allowed us to not apply the new guidance, including disclosure requirements, to the comparative periods presented.

The Partnership elected available practical expedients and exemptions upon adoption which allowed us:

● not to reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard

● to carry forward the historical lease classification and our accounting treatment for land easements on existing agreements

● to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption

● to not separate lease and non-lease components for all leases for which the Partnership is the lessee

● to use hindsight in determining the lease term and assessing ROU assets for impairment.

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

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

● the discount rate for the lease.

The standard did not impact the Partnership’s previously reported results and did not have material impact on its financial statements at the date of adoption.

The primary change as a result of the adoption was the recognition of ROU assets and lease liabilities for operating leases, which were approximately $0.2 million at January 1, 2019. At December 31, 2019, the ROU assets and corresponding net present value of the lease liabilities were both $0.2 million. For the year ended December 31, 2019, the Partnership’s operating lease costs were not material to the financial results. The weighted average remaining term and discount rate of the Partnership’s operating leases are approximately 6.25 years and 4.12 percent, respectively.

Fair Value Measurement

In August 2018, the FASB issued new guidance that amends certain disclosure requirements for the fair value measurements as part of its disclosure framework project. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Partnership elected to adopt this guidance effective first quarter 2019. The guidance was applied retrospectively and did not have a material effect on the Partnership’s financial statements.

(b)    Future Accounting Changes

Measurement of Credit Losses on Financial Instruments

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

F-47    TC PipeLines, LP Annual Report 2019

4. CONTINGENCIES AND COMMITMENTS

(a)    Contingencies

The Partnership is subject to various legal proceedings in the ordinary course of business. The accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated in accordance with ASC 450, Contingencies. The Partnership bases these estimates on currently available facts and the estimates of the ultimate outcomes or resolution. Actual results may vary from estimates resulting in an impact, positive or negative, on results of operations and cash flows. The Partnership is not aware of any contingent liabilities that would have a material adverse effect on the Partnership’s financial condition, results of operations, or cash flows.

(b)    Regulatory Matters

The FERC regulates the rates and charges for transportation of natural gas in interstate commerce. Natural gas companies may not charge rates that have been determined to be unjust and unreasonable by the FERC. Generally, rates for interstate pipelines are based on the cost of service, including recovery of and a return on the pipeline’s actual prudent historical cost investment. The rates and terms and conditions for service are found in each pipeline’s FERC-approved tariff. Under its tariff, an interstate pipeline is allowed to charge for its services on the basis of stated transportation rates. Transportation rates are established periodically in FERC proceedings known as rate cases. The tariff also allows the interstate pipeline to provide services under negotiated and discounted rates.

2018 FERC Actions

The Partnership has completed the regulatory filing that was required by FERC (see details below) to address the issues contemplated by Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act (2017 Tax Act) and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by Master Limited Partnerships (MLP), such as the Partnership:

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

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

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

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

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

2017 Rate Case, and subsequent limited section 4 rate reductions

The Partnership operates under a settlement approved by FERC effective January 1, 2018 (2017 Settlement). The 2017 Settlement provided for tiered rate reductions from January 1, 2018 to December 31, 2019 that equates to an overall rate reduction of 12.5% by January 1, 2020 when compared to the 2017 rates (10.5% by December 31, 2019 and additional 2% by January 1, 2020). The 2017 Settlement did not contain a moratorium and the Partnership is required to file new rates effective July 1, 2024. Effective February 1, 2019, FERC approved an additional 2% rate reduction and elimination of its tax allowance and ADIT liability from rate base pursuant to the Partnership’s limited NGA Section 4 filing. On April 4, 2019, the Partnership filed an amended settlement agreement that extended the 2% 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 the Partnership’s 501-G proceeding was terminated.

F-48    TC PipeLines, LP Annual Report 2019

Compressor Usage Surcharge

The compressor usage surcharge is designated to recover the actual costs of electricity at the Partnership’s electric compressors and any compressor fuel use taxes imposed on its pipeline system. Any difference between the compressor usage surcharge collected and the actual costs for electricity and compressor fuel use taxes is recorded as either an increase to expense for an over-recovery of actual costs or as a decrease to expense for an under-recovery of actual costs and is included in operations and maintenance expense on the income statement and reported as current asset or current liability on the balance sheets. The compressor usage surcharge rate is adjusted annually. The current asset or current liability will reflect the net over or under recovery of actual compressor usage related costs at the date of the balance sheet. As of December 31, 2019, and 2018, the Partnership had recorded $1.3 million and nil million as regulatory liability, respectively, on the accompanying balance sheets for the net under recoveries of compressor usage related costs.

(c)    Environmental Matters

The Partnership is not aware of any material contingent liabilities with respect to compliance with applicable environmental laws and regulations.

(d)    Commitments

The Partnership makes payments under its right-of-way commitments. The Partnership’s expense incurred for these commitments was $2.9 million for the year ended December 31, 2019, and $3.0 million for each of the years ended December 31, 2018, and 2017, respectively. The Partnership’s future minimum payments on its rights-of-way commitments are as follows:

Year Ending	Rights-of-Way
(In thousands)
2020		2,231
2021		2,565
2022		2,566
2023		2,566
2024		2,565
Thereafter		34,815
	$	47,308

Approximately 90 miles of Partnership's pipeline system is located within the boundaries of the Fort Peck Indian Reservation in Montana. The Partnership has a pipeline rights-of-way commitment with the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation, the term of which expires in 2061. In conjunction with obtaining right-of-way access across tribal lands located within the exterior boundaries of the Fort Peck Indian Reservation, the Partnership also obtained right-of-way access across allotted lands located within the reservation boundaries. With the exception of one tract subject to a right-of-way grant expiring in 2035, the allotted lands are subject to a perpetual easement granted by the Bureau of Indian Affairs (BIA) for and on behalf of the individual allottees.

5. CREDIT FACILITIES AND LONG-TERM DEBT

The Partnership’s long-term debt outstanding consisted of the following at December 31:

	2019		2018
	(In thousands)
2011 Credit Agreement – average interest rate of 3.226% at December 31, 2019; due 2024 (a)	$	115,500	15,500
2001 Senior Notes – 7.50%, due 2021		250,000	250,000
		365,500	265,500
Unamortized debt issuance costs		(94)	(143)
Unamortized debt expense		(1,054)	(902)
Total long-term debt, net	$	364,352	264,455

^(a) In June 2019, the Partnership borrowed an additional $100 million under its 2011 Credit Agreement to finance an additional cash distribution of $100 million, or $50 million to each partner.

On November 16, 2011, the Partnership entered into a $200 million amended and restated revolving credit agreement (2011 Credit Agreement) with certain financial institutions. The 2011 Credit Agreement is generally used by the Partnership to finance ongoing working capital needs and for other general business purposes, including capital

F-49    TC PipeLines, LP Annual Report 2019

expenditures. On October 1, 2019, the Partnership extended the 2011 Credit Agreement set to expire October 9, 2020 to October 1, 2024.

At December 31, 2019, the Partnership’s outstanding borrowings under the 2011 Credit Agreement were $115.5 million, leaving $84.5 million available for future borrowings. The 2011 Credit Agreement have accordion features for an additional capacity of $100 million, subject to lender consent. At the Partnership’s option, the interest rate on the outstanding borrowings may be the lenders' base rate or the London Interbank Offered Rate plus an applicable margin that is based on its long-term unsecured credit ratings.

Certain of the Partnership’s long-term debt arrangements contain covenants that restrict the incurrence of secured indebtedness or liens upon property by the Partnership. Under the 2011 Credit Agreement, the Partnership is required to comply with certain financial, operational and legal covenants. Among other things, the Partnership is required to maintain a leverage ratio of no more than 5.00 to 1.00. Pursuant to the 2011 Credit Agreement, if one or more specified material acquisitions are consummated, the permitted leverage ratio is increased to 5.50 to 1.00 for the first two full calendar quarters following the acquisition. Upon any breach of these covenants, amounts outstanding under the 2011 Credit Agreement may become immediately due and payable.

At December 31, 2019, the Partnership was in compliance with all of its financial covenants.

The Partnership’s long-term debt repayments consisted of the following at December 31, 2019 (in thousands of dollars):

Year Ending
2020		—
2021		250,000
2022		—
2023		—
2024		115,500
	$	365,500

6. FAIR VALUE MEASUREMENTS

(a)    Fair Value Hierarchy

Under ASC 820, Fair Value Measurement, fair value measurements are characterized in one of three levels based upon the input used to arrive at the measurement. The three levels of the fair value hierarchy are as follows:

● Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Partnership has the ability to access at the measurement date.

● Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

● Level 3 inputs are unobservable inputs for the asset or liability.

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

(b)    Fair Value of Financial Instruments

The carrying value of cash and cash equivalents, accrued interest, all current receivable and payable accounts, except for natural gas imbalances are classified as Level 1 in fair value hierarchy. Accordingly, the carrying values approximate their fair values because of the short maturity or duration of these instruments.

The Partnership’s natural gas imbalances, which are reported as part of accounts receivable, accounts payable and related party accounts, are classified as a Level 2 in the “Fair Value Hierarchy,” as the valuation approach includes quoted prices in the market index and observable volumes for the imbalance. Natural gas imbalances represent the difference between the amount of natural gas delivered to or received from a pipeline system and the amount of natural gas scheduled to be delivered or received at current market prices. The Partnership records these imbalances at fair value by applying the difference between the measured quantities of natural gas delivered to or received from its shippers and operators to the current average of the Northern Ventura index price and the Chicago city-gates index price. For the year ended December 31, 2019, the total estimated fair value of our natural gas imbalance was a net payable of approximately $1.5 million. (2018- net receivable of $0.2 million). For the year ended December 31, 2019, the total estimated fair value of our related party natural gas imbalance was a net receivable of approximately $0.6 million. (2018- net payable of $0.3 million).

For the year ended December 31, 2019, the fair value of the Partnership’s long term debt was $381.6 million (2018-$286.3 million) The fair value was estimated based on quoted market prices for the same or similar debt instruments with

F-50    TC PipeLines, LP Annual Report 2019

similar terms and remaining maturities, which is classified as Level 2 in the “Fair Value Hierarchy”, where the fair value is determined by using valuation techniques that refer to observable market data.

7. REVENUES

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

(a)    Disaggregation of Revenues

For the years ended December 31, 2019 and 2018, effectively all of the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed under Note 2(j).

(b)    Contract Balances

The Partnership’s contract balances consist primarily of receivables from contracts with customers reported under Accounts receivable in the balance sheet. Additionally, our accounts receivable represents the Partnership’s unconditional right to consideration for services completed which includes billed and unbilled accounts.

(c)    Right to invoice practical expedient

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

8. TRANSACTIONS WITH MAJOR CUSTOMERS

The following table represents the shippers providing significant operating revenues to the Partnership for the year ended December 31 (in thousands):

		2019	2018	2017
ONEOK Rockies (a)	$	39,549	29,425	31,501
Tenaska Marketing Ventures		42,032	38,744	28,747
Sequent Energy		20,297	27,806	34,558
BP Canada Energy Marketing Group		23,112	27,538	30,186

(a) ONEOK Rockies Midstream, L.L.C. (ONEOK Rockies), is a subsidiary of ONEOK Inc.

The following table represents the amounts in the Partnership’s trade or related party accounts receivable for shippers with accounts receivable balances greater than 10 percent of the Partnership’s accounts receivable (in thousands).

	2019		2018
ONEOK Rockies (a)	$	3,735	3,203
Tenaska Marketing Ventures		3,337	4,218

(a) ONEOK Rockies Midstream, L.L.C. (ONEOK Rockies), is a subsidiary of ONEOK Inc.

9. TRANSACTIONS WITH RELATED PARTIES

The day-to-day management of the Partnership’s affairs is the responsibility of TransCanada Northern Border, Inc., a wholly owned subsidiary of TC Energy, (TransCanada Northern Border) pursuant to an operating agreement between TransCanada Northern Border and the Partnership effective April 1, 2007 (as amended). TransCanada Northern Border utilizes the services of TC Energy and its affiliates for management services related to the Partnership. The Partnership is charged for the capital, salaries, benefits and expenses of TC Energy and its affiliates attributable to the Partnership’s operations. For the years ended December 31, 2019, 2018, and 2017, the Partnership’s charges from TC Energy and its affiliates totaled approximately $39.2 million, $35.6 million, and $43.3 million, respectively. The impact of these charges on the Partnership’s income was $36.3 million, $32.2 million, and $31.3 million, respectively. At December 31, 2019 and 2018, the Partnership owed $3.6 million and $3.3 million, respectively, to these affiliates classified to related party accounts on the balance sheets.

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For the years ended December 31, 2019, 2018, and 2017, the Partnership had contracted firm capacity held by one customer affiliated with one of the Partnership’s general partners. See Note 8 – Transactions with Major Customers for details regarding revenues and outstanding accounts receivable balances with ONEOK Rockies.

10. CASH DISTRIBUTION AND CONTRIBUTION POLICY

The Partnership’s General Partnership Agreement provides that distributions to its partners are to be made on a pro rata basis according to each partner’s capital account balance. The Partnership’s Management Committee has the responsibility to determine the amount and timing of the distributions to its partners including equity contributions and the funding of growth capital expenditures. In addition, any inability to refinance maturing debt will be funded by equity contributions. Any changes to, or suspension of, the Partnership’s cash distribution policy requires the unanimous approval of the Management Committee. The Partnership’s cash distributions are equal to 100 percent of its distributable cash flow as determined from its financial statements based upon earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. The Partnership paid monthly distributions approximately one month following the end of each reported month.

For the years ended December 31, 2019, 2018, and 2017, the Partnership paid distributions to its general partners of $286.9 million, including the distribution of $100 million from the proceeds of additional borrowings under the 2011 Credit Agreement (see Note 5), $166.4 million, and $165.9 million, respectively. In 2017, the Partnership received contributions from its partners of $166 million, $83 million each, which was used as a payment on the 2011 Credit Agreement.

11. SUBSEQUENT EVENTS

On January 10, 2020, the Partnership declared a cash distribution in the amount of $18.1 million. The distribution was paid on January 31, 2020.

On February 11, 2020, the Partnership declared a cash distribution in the amount of $18.8 million. The distribution will be paid on February 28, 2020.

Subsequent events have been assessed through February 14, 2020, which is the date the financial statements were issued, and we concluded there were no events or transactions during this period that would require recognition or disclosure in the financial statements other than those already reflected.

F-52    TC PipeLines, LP Annual Report 2019

Independent Auditors’ Report

The Partners and the Management Committee

Great Lakes Gas Transmission Limited Partnership:

We have audited the accompanying financial statements of Great Lakes Gas Transmission Limited Partnership, which comprise the balance sheets as of December 31, 2019 and 2018, and the related statements of income, partners’ capital, and cash flows for the years in the three-year period ended December 31, 2019, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Great Lakes Gas Transmission Limited Partnership as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019 in accordance with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas
February 14, 2020

F-53    TC PipeLines, LP Annual Report 2019

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

BALANCE SHEETS

December 31, 2019 and 2018 (In Thousands)	2019		2018
Assets
Current assets:
Cash and cash equivalents	$	39	49
Demand loan receivable from related party		34,262	35,934
Accounts receivable:
Trade		7,016	8,582
Related parties		19,262	18,754
Materials and supplies		9,850	9,951
Other		1,858	1,504
Total current assets		72,287	74,774
Property, plant, and equipment:
Property, plant, and equipment		2,130,615	2,116,001
Construction work in progress		3,129	7,741
		2,133,744	2,123,742
Less accumulated depreciation and amortization		(1,448,825)	(1,434,748)
Total property, plant, and equipment, net		684,919	688,994
Total assets	$	757,206	763,768
Liabilities and Partners' Capital
Current liabilities:
Accounts payable:
Trade	$	6,395	4,098
Related parties		5,108	3,815
Current maturities of long-term debt		21,000	21,000
Taxes payable (other than income)		7,989	8,184
Accrued interest		5,554	5,912
Other current liabilities		8,434	3,919
Total current liabilities		54,480	46,928
Long-term debt, net of current maturities		197,817	218,782
Regulatory liabilities		5,948	3,664
Other noncurrent liabilities		5	220
Partners' capital		498,956	494,174
Total liabilities and partners' capital	$	757,206	763,768

See accompanying notes to financial statements.

F-54    TC PipeLines, LP Annual Report 2019

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

STATEMENTS OF INCOME AND PARTNERS' CAPITAL

Years ended December 31, 2019, 2018, and 2017 (In Thousands)	2019		2018	2017
Operating revenues, net (Note 8)	$	237,894	245,646	181,487
Operating expenses:
Operation and maintenance		67,996	56,613	54,885
Depreciation and amortization		31,954	31,813	29,474
Taxes, other than income		10,848	11,651	10,830
Total operating expenses		110,798	100,077	95,189
Operating income		127,096	145,569	86,298
Interest and debt expense
Interest expense		17,747	19,378	20,916
Interest expense capitalized		(119)	(184)	(72)
Interest expense, net		17,628	19,194	20,844
Other income
Allowance for equity funds used during construction		411	308	116
Other income		1,203	979	749
Other income, net		1,614	1,287	865
Net income	$	111,082	127,662	66,319
Partners' capital:
Balance at beginning of year	$	494,174	473,112	462,293
Net income		111,082	127,662	66,319
Distributions to partners		(127,300)	(125,600)	(74,500)
Contributions from partners		21,000	19,000	19,000
Balance at end of year	$	498,956	494,174	473,112

See accompanying notes to financial statements.

F-55    TC PipeLines, LP Annual Report 2019

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

Statements of Cash Flows

Years ended December 31, 2019, 2018, and 2017 (In Thousands)	2019		2018	2017
Cash flows from operating activities:
Net income	$	111,082	127,662	66,319
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		31,954	31,813	29,474
Allowance for funds used during construction, equity		(411)	(308)	(116)
Gain on sale of property, plant and equipment		(780)	—	—
Amortization of debt issuance cost, reported as part of interest expense		35	29	41
Asset and liability changes:
Accounts receivable		1,058	309	(1,109)
Other current assets		(253)	3,590	(2,608)
Accounts payable		2,705	(3,207)	(1,792)
Provision for revenue sharing refund		—	(44,722)	32,401
Provision for rate refund		—	(2,851)	7,972
Other current liabilities		3,962	2,329	(3,144)
Noncurrent liabilities		(215)	8	(14)
Net cash provided by operating activities		149,137	114,652	127,424
Cash flows from (used in) investing activities:
Additions to property, plant, and equipment		(30,234)	(17,178)	(13,814)
Net change in demand loan receivable from related party		1,672	28,106	(36,896)
Proceeds from sale of property, plant and equipment		6,735	—	—
Other		(20)	25	(2,209)
Net cash provided by (used in) investing activities		(21,847)	10,953	(52,919)
Cash flows used in financing activities:
Contributions from partners		21,000	19,000	19,000
Payments for retirement of long-term debt		(21,000)	(19,000)	(19,000)
Distributions to partners		(127,300)	(125,600)	(74,500)
Net cash used in financing activities		(127,300)	(125,600)	(74,500)
Net change in cash and cash equivalents		(10)	5	5
Cash and cash equivalents at beginning of year		49	44	39
Cash and cash equivalents at end of year	$	39	49	44
Supplemental cash flow information:
Interest paid, net of capitalized interest	$	17,950	19,599	20,791
Accruals for property, plant and equipment	$	2,791	1,886	1,497

See accompanying notes to financial statements.

F-56    TC PipeLines, LP Annual Report 2019

GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP

NOTES TO FINANCIAL STATEMENTS

December 31, 2019 and 2018

(1) DESCRIPTION OF BUSINESS

Great Lakes Gas Transmission Limited Partnership (the Partnership) is a Delaware limited partnership that owns 2,115 miles of natural gas pipeline system, which transports natural gas for delivery to wholesale customers in the midwestern and northeastern United States (U.S.) and eastern Canada. The partners’ ownership percentages in the Partnership at December 31, 2019 were as follows:

	Ownership
	percentage
General Partners:
TransCanada GL, Inc.	46.45
TC Pipelines, LP (TCP)	46.45
Limited Partner:
Great Lakes Gas Transmission Company	7.10

Previously, TC GL Intermediate Limited Partnership held a 46.45 percent interest in the Partnership. Effective October 31, 2019, TC GL Intermediate Limited Partnership transferred 100 percent of its ownership of the Partnership to its related party, TC Pipelines, LP (TCP).

Great Lakes Gas Transmission Company (the Company), TransCanada GL Inc., and TCP) are wholly owned indirect subsidiaries of TC Energy Corporation (TC Energy), formerly known as TransCanada Corporation.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a)    Basis of Presentation

The Partnership’s financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles (GAAP). Certain prior year amounts have been reclassified to conform to the current year presentation.

(b)    Use of Estimates

The preparation of the financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

(c)    Cash and Cash Equivalents

The Partnership’s cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

(d)    Accounting for Regulated Operations

The Partnership’s natural gas pipeline is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Financial Accounting Standards Board Accounting Standards Codification (ASC) 980, Regulated Operations, provides that rate regulated enterprises account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. The Partnership evaluates the continued applicability of regulatory accounting, considering such factors as regulatory charges, the impact of competition, and the ability to recover regulatory assets as set forth in ASC 980. Accordingly, certain assets and liabilities that result from the regulated ratemaking process are reflected on the balance sheets as regulatory assets and regulatory liabilities. At December 31, 2019 and

F-57    TC PipeLines, LP Annual Report 2019

2018, the Partnership does not have any regulatory assets. The following table presents the Partnership’s regulatory liabilities at December 31, 2019 and 2018:

	December 31,
				Remaining
				recovery/
				settlement
	2019		2018	period
		(In thousands)		(Years)
Negative salvage	$	5,948	3,664	(a)
Volumetric fuel tracker		686	2,389	(b)
		6,634	6,053
Less: Current portion included in Other		686	2,389
	$	5,948	3,664

(a) Negative salvage accrued for estimated net costs of removal of transmission plant has a settlement period related to the estimated life of the assets (refer to Note 2(h)).

(b) Volumetric fuel tracker assets or liabilities are settled with in-kind exchanges with customers continually.

(e)    Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest, except for those receivables subject to late charges. The Partnership maintains an allowance for doubtful accounts for estimated losses on accounts receivable, if it is determined the Partnership will not collect all or part of the outstanding receivable balance. The Partnership regularly reviews its allowance for doubtful accounts and establishes or adjusts the allowance as necessary using the specific-identification method. Account balances are charged to the allowance after all means of collection have been exhausted and the potential for recovery is no longer considered probable. There were no accounts charged to the allowance in 2019 and 2018.

(f)    Natural Gas Imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in-kind, subject to the terms of the Partnership’s tariff.

Imbalances due from others are reported on the balance sheets as trade accounts receivable or accounts receivable from related parties. Imbalances owed to others are reported on the balance sheets as trade accounts payable or accounts payable to related parties. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.

(g)    Material and Supplies

The Partnership’s inventories primarily consist of materials and supplies and are carried at lower of weighted average cost and net realizable value.

(h)    Property, Plant, and Equipment

Property, plant, and equipment are recorded at their original cost of construction. For assets the Partnership constructs, direct costs are capitalized, such as labor and materials, and indirect costs, such as overhead and interest are also capitalized. The Partnership capitalizes major units of property replacements or improvements and expenses minor items.

The Partnership uses the composite (group) method to depreciate property, plant, and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. The depreciation rate is applied to the total cost of the group until its net book value equals its salvage value. All asset groups are depreciated using the depreciation rates approved by FERC in the Partnership’s last rate proceeding. A substantial portion of the Partnership’s principal operating assets are being depreciated at an annual rate of 1.27%. The remaining assets are depreciated at annual rates ranging from 2.33% to 10.00%. Using these rates, the remaining depreciable life of these assets ranges from 5 to 47years.

The Partnership collects estimated future removal costs related to its transmission and gathering facilities in its current rates (also known as “negative salvage”) and recognizes regulatory liabilities in this respect in the balance sheet. Estimated costs associated with the future removal of transmission and gathering facilities are collected through depreciation as allowed by FERC. These amounts do not represent asset retirement obligations as defined by FASB ASC 410, Accounting for Asset Retirement Obligations. When property, plant, and equipment are retired, the Partnership charges accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove,

F-58    TC PipeLines, LP Annual Report 2019

sell, or dispose of the assets, less their salvage value. The Partnership does not recognize a gain or loss unless an entire operating unit is sold or retired. The Partnership includes gains or losses on dispositions of operating units in income.

The Partnership capitalizes a carrying cost on funds invested in the construction of long-lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC). AFUDC is recorded based on the Partnership’s average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of the asset on the balance sheets.

(i)    Long-Lived Assets

Long-lived assets, such as property, plant, and equipment, and purchased intangible assets subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group be tested for possible impairment, the Partnership first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values, and third-party independent appraisals, as considered necessary.

(j)    Revenue Recognition

The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas. These are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Partnership utilizes the practical expedient of recognizing revenue as invoiced. Revenues are invoiced and paid monthly. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.

The Partnership's pipeline systems are subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. As of December 31, 2019 and 2018, there are no refund provisions reflected in these financial statements.

(k)    Accounting for Asset Retirement Obligations

The Partnership accounts for asset retirement obligations pursuant to the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires the Partnership to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and/or normal use of the assets. ASC 410-20 also requires the Partnership to record a corresponding asset that is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is to be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation.

The fair value of a liability for an asset retirement obligation is recorded during the period in which the liability is incurred and if a reasonable estimate of fair value can be made. The Partnership has determined that asset retirement obligations exist for certain of its transmission assets; however, the fair value of the obligations cannot be determined because the end of the transmission system life is not determinable with the degree of accuracy necessary to establish a liability for the obligations.

The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system and intends to do so long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2019 and 2018. The Partnership continues to evaluate its asset retirement obligations and future developments that could impact amounts it records.

(i)    Income Taxes

Income taxes are the responsibility of the partners and are not reflected in these financial statements.

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(m)    Debt Issuance Costs

Costs related to the issuance of debt are deferred and amortized using the effective-interest rate method over the term of the related debt.

The Partnership amortizes premiums and discounts incurred in connection with the issuance of debt consistent with the terms of the respective debt instrument.

Debt issuance costs are presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities, consistent with debt discount. In addition, amortization of debt issuance costs, premiums, and discounts are reported as part of interest expense.

(n)    Fair Value Measurements

For cash and cash equivalents, receivables, accounts payable and certain accrued expenses, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments, fair value is estimated based upon market values (if applicable) or on the current interest rates available to the Partnership for debt with similar terms and remaining maturities. Judgment is required in developing these estimates.

(3) ACCOUNTING CHANGES

Effective January 1, 2019

Leases

In February 2016, the Financial Accounting Standards Board (FASB) issued new guidance on the accounting for leases. The new guidance amends the definition of a lease such that, in order for an arrangement to qualify as a lease, the lessee is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the consolidated balance sheet for all leases with a term longer than twelve months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the consolidated statements of income. The new guidance does not make extensive changes to previous lessor accounting.

Under the new guidance, the Partnership determines if an arrangement is a lease at inception. Operating leases are recognized as ROU assets and included in Property, plant and equipment while corresponding liabilities are included in “Other current liabilities”, and “Other long-term liabilities” on the balance sheets.

Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. If the Partnership’s leases do not have an implicate rate, the present value of future minimum payments, if any, will be determined using a rate that approximates the Partnership’s borrowing cost. Operating lease expense is recognized on a straight-line basis over the lease term and included in “Operation and maintenanceexpenses” in the Statements of Income.

The new guidance was effective January 1, 2019 and was applied using optional transition relief which allowed entities to initially apply the new lease standard at adoption and recognize a cumulative-effect adjustment to the opening balance of equity in the period of adoption. This transition option allowed the Partnership to not apply the new guidance, including disclosure requirements, to the comparative periods presented.

The Partnership elected available practical expedients and exemptions upon adoption which allowed the Partnership:

● not to reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard

● to carry forward the historical lease classification and our accounting treatment for land easements on existing agreements

● to not recognize ROU assets or lease liabilities for leases that qualify for the short-term lease recognition exemption

● to not separate lease and non-lease components for all leases for which the Partnership is the lessee

● to use hindsight in determining the lease term and assessing ROU assets for impairment.

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

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

F-60    TC PipeLines, LP Annual Report 2019

Partnership is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor; and

● the discount rate for the lease.

Upon review of our existing arrangements, no contracts qualified as a lease therefore the standard did not impact the Partnership’s previously reported results and did not have material impact on its financial statements at the date of adoption.

Fair Value Measurement

In August 2018, the FASB issued new guidance that amends certain disclosure requirements for the fair value measurements as part of its disclosure framework project. This new guidance is effective January 1, 2020, however, early adoption of certain or all requirements is permitted. The Partnership elected to adopt this guidance effective first quarter 2019. The guidance was applied retrospectively and did not have a material effect on the Partnership’s financial statements.

Future Accounting Changes

Measurement of Credit Losses on Financial Instruments

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

(4) COMMITMENTS AND CONTINGENCIES

(a)    Contingencies

The Partnership is subject to various legal proceedings in the ordinary course of business. The accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. The Partnership accrues for these contingencies when the assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated in accordance with ASC 450, Contingencies. The Partnership bases these estimates on currently available facts and the estimates of the ultimate outcomes or resolution. Actual results may vary from estimates resulting in an impact, positive or negative, on results of operations and cash flows. The Partnership is not aware of any contingent liabilities that would have a material adverse effect on the Partnership’s financial condition, results of operations, or cash flows.

(b)    Legal Proceedings

The Partnership is not a party in any material legal proceedings as of December 31, 2019.

(c)    Environmental Matters

The Partnership is not aware of any material contingent liabilities with respect to compliance with applicable environmental laws and regulations.

(d)    Rights-of-Way Agreements with Native American Tribes

The majority of the land on which the Partnership operates 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 agreement 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.

During the second quarter of 2018, rights-of-way expired for approximately 7.6 miles of the Partnership’s pipeline system on tribal land located within the Fond du Lac Reservation and Leech Lake Reservation in Minnesota and the Bad River Reservation in Wisconsin. As a result, beginning the second quarter of 2018, the Partnership started accruing the estimated costs and associated liability related to these pending agreements.

The Partnership cannot predict the outcome of these negotiations. If the Partnership is unable to obtain new easements or rights-of-way across all or a portion of the tribal lands at reasonable rates, or at all, the Partnership may be required to acquire the necessary rights at significant cost or remove and re-route portions of the pipeline at significant capital costs and disruption to operations that could have a material adverse effect on its financial condition, results of operations and cash flows.

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(e)    Regulatory Matters

2018 FERC Actions

The Partnership has completed the regulatory filing that was required by FERC (see details below) to address the issues contemplated by Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act (2017 Tax Act)and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form No. 501-G, that quantified the rate impact of the 2017 Tax Act on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by Master Limited Partnerships (MLP), such as the Partnership:

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

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

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

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

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

2017 Rate Case and subsequent limited section 4 rate reduction

The Partnership operates under a settlement approved by FERC effective January 1, 2018 (2017 Settlement). The 2017 Settlement did not contain a moratorium and eliminated its revenue sharing mechanism with customers. The Partnership is required to file new rates effective October 1, 2022. Additionally, the Partnership’s annual depreciation rates remain materially unchanged but for regulatory purposes, the Partnership is required to reflect a negative salvage at an annual rate of 0.15% of transmission plant.

Beginning October 1, 2017, the Partnership was still charging customers rates in effect prior to the 2017 Settlement but was only recognizing revenue up to the amount of the new rates in the 2017 Settlement. The difference between these two amounts was recognized as a provision for rate refund on the balance sheet and refunded in the first quarter of 2018.

Effective February 1, 2019, FERC approved an additional 2 percent rate reduction to the 2017 Settlement approved rates, and eliminated its tax allowance and ADIT liability from rate base pursuant to the Partnership’s filing of Form 501-G electing a limited Section 4 (Option 1). The Partnership’s 501-G docket remains open.

(f) Other Commercial Commitments

The Partnership has easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of the Partnership’s pipeline system. The Partnership’s future minimum payments on its rights-of-way commitments are as follows:

Year Ending	Rights-of-Way
(In thousands)
2020		101
2021		61
2022		63
2023		65
2024		67
Thereafter		1,095
	$	1,452

F-62    TC PipeLines, LP Annual Report 2019

(5) LONG-TERM DEBT

The Partnership’s outstanding long-term debt consisted of the following at December 31:

	2019		2018
	(In thousands)
9.09% series Senior Notes due 2016 to 2021	$	20,000	30,000
6.95% series Senior Notes due 2019 to 2028		99,000	110,000
8.08% series Senior Notes due 2021 to 2030		100,000	100,000
		219,000	240,000
Less: Unamortized debt issuance costs		183	218
Less: current maturities		21,000	21,000
Total long-term debt, net	$	197,817	218,782

The Partnership’s long-term debt repayments consisted of the following at December 31, 2019 (in thousands of dollars):

Year Ending
2020		21,000
2021		31,000
2022		21,000
2023		21,000
2024		21,000
Thereafter		104,000
	$	219,000

The Partnership is required to comply with certain financial, operational, and legal covenants. Under the most restrictive covenants in the Senior Notes Agreements, approximately $118.0 million of partners’ capital was restricted as to distributions as of December 31, 2019. As of December 31, 2019, Partnership was in compliance with all of its financial covenants.

(6) FAIR VALUE MEASUREMENTS

(a)     Fair Value Hierarchy

Under ASC 820, Fair Value Measurement, fair value measurements are characterized in one of three levels based upon the input used to arrive at the measurement. The three levels of the fair value hierarchy are as follows:

● Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Partnership has the ability to access at the measurement date.

● Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

● Level 3 inputs are unobservable inputs for the asset or liability.

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

(b)    Fair Value of Financial Instruments

The carrying value of cash and cash equivalents, accrued interest, all current receivable and payable accounts, except for natural gas imbalances are classified as Level 1 in fair value hierarchy. Accordingly, the carrying values approximate their fair values because of the short maturity or duration of these instruments. The Partnership’s natural gas imbalances, which are reported as part of accounts receivable, accounts payable and related party accounts, are classified as a Level 2 in the “Fair Value Hierarchy,” as the valuation approach includes quoted prices in the market index and observable volumes for the imbalance. Natural gas imbalances represent the difference between the amount of natural gas delivered to or received from a pipeline system and the amount of natural gas scheduled to be delivered or received at current market prices. The Partnership values these imbalances by applying the difference between the measured quantities of natural gas delivered to or received from our shippers and operators to the current Emerson Viking GL index price. For the year ended December 31, 2019, the total estimated fair value of our natural gas imbalance was a net payable of approximately $1.2 million. (2018- net receivable of $1.8 million). For the year ended December 31, 2019, the total estimated fair value of our related party natural gas imbalance was a net receivable of approximately $1.3 million. (2018- net receivable of $0.4 million).

F-63    TC PipeLines, LP Annual Report 2019

For the year ended December 31, 2019, the fair value of the Partnership’s long term debt was $287 million (2018-$288 million) The fair value was estimated based on quoted market prices for the same or similar debt instruments with similar terms and remaining maturities, which is classified as Level 2 in the “Fair Value Hierarchy”, where the fair value is determined by using valuation techniques that refer to observable market data.

(7) TRANSACTIONS WITH RELATED PARTIES

(a)    Cash Management Program

The Partnership participates in TC Energy’s cash management program, which matches short-term cash surpluses and needs of participating related parties, thus minimizing total borrowings from outside sources. Monies advanced under the program are considered loans, accruing interest and repayable on demand. The Partnership receives interest on monies advanced to TC Energy at the rate of interest earned by TC Energy on its short-term cash investments. The Partnership pays interest on monies advanced from TC Energy based on TC Energy’s short-term borrowing costs. For the years ended December 31, 2019, 2018 and 2017, the net interest income on this arrangement is immaterial. At December 31, 2019 and 2018, the Partnership had a demand loan receivable from TC Energy of $34.3 million and $35.9 million, respectively.

(b)    Related Party Revenues and Expenses

The Partnership earns significant transportation revenues from TC Energy and its related parties under contracts, which provide for negotiated, discounted and maximum recourse rates. The contracts are on the same terms as would be available to other shippers and the majority of the Partnership’s related party revenue is derived from both short-haul and long-haul transportation services.

Pursuant to the Partnership’s Operating Agreement, day-to-day operation of partnership activities is the responsibility of the Company. The Partnership is charged by the Company and related parties for services such as legal, tax, treasury, human resources, other administrative functions, and for other costs incurred on its behalf. These include, but are not limited to, employee benefit costs and property and liability insurance costs. These costs are based on direct assignment to the extent practicable, or by using allocation methods that are reasonable reflections of the utilization of services provided to or for the benefits received by the Partnership.

The following table shows revenues and charges from the Partnership’s related parties for the years ended December 31:

	2019		2018	2017
	(In thousands)
Transportation revenues from related parties(a)	$	176,021	178,366	130,165
Cost recovery from related parties(b)		740	1,332	1,556
Costs charged from related parties		47,421	43,737	35,381

(a) Transportation revenues from related parties represent the amount recognized by the Partnership before any allowance on revenue sharing and provision for rate refund, which represent 73%, 73% and 57%, of the Partnership’s total revenues for the year ended December 31, 2019, 2018 and 2017, respectively.

(b) Cost recovery from related parties represents the Partnership’s recovery of a portion of the costs of the facility it owns by charging its related parties for use of office space in Troy, Michigan. The building in Troy, Michigan was sold in August 2019 for a gain of approximately $780 thousand.

The Partnership has a 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 TransCanada to transport up to 0.711 billion of cubic feet of natural gas per day. This contract, which contains volume reduction options up to full contract quantity beginning in year three, was a direct benefit from TC Energy’s long-term fixed price service on its Canadian Mainline that was launched in 2017. During the year ended December 31, 2019 the Partnership recognized transportation revenue of $75.8 million related to this contract (2018-$75.8 million, 2017-$13 million)

During the year-ended December 31, 2019, the Partnership’s remaining $99.5 million of transportation revenues from related parties was associated with its other transportation contracts with Canadian Mainline amounting to $48.1 million and another related party, TC Energy’s ANR Pipeline Company (ANR) amounting to $51.4 million.

In 2018, the Partnership executed a long-term transportation capacity contracts with its related party, ANR Pipeline Company. The contracts are for a term of 15 years from November 2021 to October 31, 2036 with a total contract value of approximately $1.3 billion. The contracts contain reduction options (i) at any time on or before April 1, 2020 for any reason and (ii) any time before April 2021, if TC Energy is not able to secure the required regulatory approval related to anticipated expansion projects.

F-64    TC PipeLines, LP Annual Report 2019

(8) REVENUES

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

(a)    Disaggregation of Revenues

For the year ended December 31, 2019 and 2018, effectively all the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed under Note 2- Significant Accounting Policies.

(b)    Revenues Subject to Refund

Also noted under Note 2- Significant Accounting Policies, a portion of our revenues collected may be subject to refund when a rate proceeding is ongoing or as part of a rate case settlement with customers. The Partnership uses its best estimate based on the facts and circumstances of the proceeding to provide for allowances for these potential refunds in the revenue the Partnership recognized.

During the year ended December 31, 2017, the Partnership operated under a FERC approved 2013 rate settlement that included a revenue sharing mechanism that requires the Partnership to share with its shippers 50% of any qualifying revenues earned during the year that result in a return on equity (ROE) above 13.25%. Qualifying revenues above a 20% ROE are returned to shippers at 100%. The Partnership establishes a provision for this revenue sharing as an offset against revenue in the income statement and recognizes an estimated refund liability classified as provision for revenue sharing refund in the balance sheet. Accordingly, the revenues presented in the statement of income for the years ended December 31, 2017 were net of $39.6 million estimated revenue sharing provision, settled in 2018. As discussed under Note 4(b), beginning in 2018, the revenue sharing mechanism was eliminated as part of the 2017 Settlement.

(c)    Contract Balances

The Partnership’s contract balances consist primarily of receivables from contracts with customers reported under Accounts receivable in the balance sheet. Additionally, our accounts receivable represents the Partnership’s unconditional right to consideration for services completed which includes billed and unbilled accounts.

(d)    Right to invoice practical expedient

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

(9) DISTRIBUTIONS

The Partnership’s distribution policy generally results in a quarterly cash distribution equal to 100 percent of distributable cash flow based upon earnings before income taxes, depreciation, AFUDC less capital expenditures and debt repayments not funded with cash calls to its partners. The resulting distribution amount and timing are subject to Management Committee modification and approval after considering business risks as well as ensuring minimum cash balances, equity balances, and ratios are maintained.

On January 10, 2020, the Management Committee of the Partnership declared a cash distribution in the amount of $34.4 million to the partners. The distribution was paid on January 31, 2020.

(10) SUBSEQUENT EVENTS

Subsequent events have been assessed through February 14, 2020, which is the date the financial statements were issued, and the Partnership concluded there were no events or transactions during this period that would require recognition or disclosure in the financial statements other than those already reflected.

F-65    TC PipeLines, LP Annual Report 2019

Independent Auditors’ Report

TO THE PARTNERS OF IROQUOIS GAS TRANSMISSION SYSTEM, L.P.:

We have audited the accompanying consolidated financial statements of Iroquois Gas Transmission System, L.P., and its subsidiaries (the Partnership), which comprise the consolidated balance sheets as of December 31, 2019 and 2018, and the related consolidated statements of comprehensive income, changes in partners’ equity and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Iroquois Gas Transmission System, L.P., and its subsidiaries as of December 31, 2019 and 2018, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2019, in accordance with accounting principles generally accepted in the United States of America.

Changes in Accounting Principle

As discussed in Note 2, during the year ended December 31, 2019, Iroquois Gas Transmission System, L.P. and its subsidiaries adopted Accounting Standards Update No. 2016-02, Leases (Topic 842) and Accounting Standards Update No. 2018-11, Targeted Improvements to ASC 842, Leases. Our opinion is not modified with respect to this matter.

Blum, Shapiro & Company, P.C.

West Hartford, Connecticut

February 19, 2020

F-66    TC PipeLines, LP Annual Report 2019

IROQUOIS GAS TRANSMISSION SYSTEM, L.P.

Consolidated Statements of Comprehensive Income

For the years ended December 31
(thousands of dollars)	2019		2018		2017
Operating Revenues (Notes 7, 8, and 9)	$	179,615	$	193,780	$	193,460
Operating Expenses:
Operation and maintenance (Note 13)		28,872		29,158		27,900
Depreciation and amortization (Note 3)		29,486		29,177		28,849
Taxes other than income taxes		28,297		27,628		27,348
Total Operating Expenses		86,655		85,963		84,097
Operating Income		92,960		107,817		109,363
Other Income / (Expenses):
Interest income		859		911		332
Allowance for equity funds used during construction		2,244		2,098		2,210
Other, net (Note 13)		1,688		1,216		(714)
		4,791		4,225		1,828
Interest Expense:
Interest expense		16,701		19,203		19,522
Allowance for borrowed funds used during construction		(988)		(1,009)		(924)
		15,713		18,194		18,598
Net Income	$	82,038	$	93,848	$	92,593
Other comprehensive income/(loss) - effects of retirement benefit plans (Note 10)		2,308		(2,521)		1,830
Comprehensive Income	$	84,346	$	91,327	$	94,423

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

F-67    TC PipeLines, LP Annual Report 2019

IROQUOIS GAS TRANSMISSION SYSTEM, L.P.

Consolidated Balance Sheets

At December 31 (thousands of dollars)	2019		2018
Assets
Current Assets:
Cash and temporary cash investments	$	43,351	$	80,393
Accounts receivable – trade		20,239		17,106
Prepaid property taxes		11,100		10,722
Other current assets		4,422		4,164
Total Current Assets	$	79,112	$	112,385
Natural Gas Transmission Plant:
		1,310,465		1,296,895
Natural gas plant in service
Construction work in progress		59,003		55,495
		1,369,468		1,352,390
Accumulated depreciation and amortization		(799,876)		(771,344)
Net Natural Gas Transmission Plant (Note 3)		569,592		581,046
Other Assets and Deferred Charges:
Other assets and deferred charges		15,914		6,405
Total Other Assets and Deferred Charges		15,914		6,405
Total Assets	$	664,618	$	699,836
LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities:
Accounts payable	$	3,696	$	3,483
Distribution payable to partner (Note 2)		13,616		—
Accrued interest		1,745		1,953
Current portion of long-term debt (Note 4)		3,000		146,000
Customer deposits		9,064		11,091
Other current liabilities		6,206		2,742
Total Current Liabilities	$	37,327	$	165,269
Long-Term Debt, net (Note 4)		313,617		178,069
Other Non-Current Liabilities:
Other non-current liabilities		19,824		13,607
Other Non-Current Liabilities		19,824		13,607
Commitments and Contingencies (Note 7)
Total Liabilities		370,768		356,945
Partners’ Equity		293,850		342,891
Total Liabilities and Partners’ Equity	$	664,618	$	699,836

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

F-68    TC PipeLines, LP Annual Report 2019

IROQUOIS GAS TRANSMISSION SYSTEM, L.P.

Consolidated Statements of Cash Flows

For the years ended December 31 (thousands of dollars)	2019		2018		2017
Cash Flows From Operating Activities:
Net Income	$	82,038	$	93,848	$	92,593
Adjusted for the following:
Depreciation and amortization		29,486		29,177		28,849
Allowance for equity funds used during construction		(2,244)		(2,098)		(2,210)
Other assets and deferred charges		(1,815)		1,317		(1,490)
Other non-current liabilities		1,932		1,331		4,814
Amortization of debt issuance costs		450		231		390
Changes in working capital:
Accounts receivable		(3,133)		3,614		(1,884)
Prepaid property taxes		(378)		(272)		20
Other current assets		(340)		(168)		(259)
Accounts payable		1,301		381		(1,367)
Customer deposits		(2,027)		407		151
Accrued interest		(208)		(40)		(60)
Other current liabilities		2,445		556		(231)
Net Cash Provided by Operating Activities		107,507		128,284		119,316
Cash Flows From Investing Activities:
Capital expenditures		(16,876)		(15,238)		(14,067)
Net Cash Used For Investing Activities		(16,876)		(15,238)		(14,067)
Cash Flows From Financing Activities:
Partner contributions		7,000		—		—
Partner distributions		(126,771)		(114,248)		(100,476)
Long-term debt borrowing		140,000		—		—
Repayments of long-term debt		(146,000)		(4,000)		(5,500)
Payments for debt issuance costs		(1,902)		—		—
Net Cash Used For Financing Activities		(127,673)		(118,248)		(105,976)
Net Decrease in Cash and Temporary Cash Investments		(37,042)		(5,202)		(727)
Cash and Temporary Cash Investments at Beginning of Year		80,393		85,595		86,322
Cash and Temporary Cash Investments at End of Year	$	43,351	$	80,393	$	85,595
Supplemental Disclosure of Cash Flow Information:
Cash paid for interest	$	16,596	$	18,874	$	19,192
Accruals for capital expenditures	$	1,073	$	2,161	$	314

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

F-69    TC PipeLines, LP Annual Report 2019

IROQUOIS GAS TRANSMISSION SYSTEM, L.P.

Consolidated Statements of Changes in Partners’ Equity

							Accumulated
							Other		Total
	Net		Distributions		Contributions		Comprehensive		Partners’
(thousands of dollars)	Income		to Partners		from Partners		(Loss)/Income		Equity
December 31, 2016
Balance	$	1,502,244	$	(1,406,544)	$	279,381	$	(3,216)	$	371,865
Net Income		92,593		—		—		—		92,593
Equity Distributions to Partners (Note 1)		—		(100,476)		—		—		(100,476)
Other Comprehensive Loss (Note 10)		—		—		—		1,830		1,830
December 31, 2017
Balance	$	1,594,837	$	(1,507,020)	$	279,381	$	(1,386)	$	365,812
Net Income		93,848		—		—		—		93,848
Equity Distributions to Partners (Note 1)		—		(114,248)		—		—		(114,248)
Other Comprehensive Income (Note 10)		—		—		—		(2,521)		(2,521)
December 31, 2018
Balance	$	1,688,685	$	(1,621,268)	$	279,381	$	(3,907)	$	342,891
Net Income		82,038		—		—		—		82,038
Equity Distributions to Partners (Note 1)		—		(140,387)		—		—		(140,387)
Equity Contributions from Partners (Note 1)		—		—		7,000		—		7,000
Other Comprehensive Income (Note 10)		—		—		—		2,308		2,308
December 31, 2019
Balance	$	1,770,723	$	(1,761,655)	$	286,381	$	(1,599)	$	293,850

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 DESCRIPTION OF PARTNERSHIP:

Iroquois Gas Transmission System, L.P., (the Partnership or Iroquois) is a Delaware limited partnership that owns and operates a natural gas transmission pipeline from the Canada-United States border near Waddington, NY, to South Commack, Long Island, NY and Hunt's Point, Bronx, New York. In accordance with the limited partnership agreement, the Partnership shall continue in existence until October 31, 2089, and from year to year thereafter, until the partners elect to dissolve the Partnership and terminate the limited partnership agreement.

On June 1, 2017, TCPL Northeast Ltd. and TransCanada Iroquois Ltd. sold their 21.00% and 28.34% interest in the Partnership, respectively, to their affiliate, TC PipeLines Intermediate Limited Partnership (TCILP) for a total 49.34% interest in the Partnership. TC Energy’s Master Limited Partnership, TC PipeLines, LP (TCP) is TCILP’s parent.

On January 28, 2019, Dominion Energy Midstream Partners became an indirect, wholly owned subsidiary of Dominion Energy.

On October 31, 2019, TCILP assigned 100.0% of its interest in the Partnership to its parent TCP.

As of December 31, 2019, the partners consist of TCP (TC Energy), (49.34%), Iroquois GP Holding Company, LLC (Dominion Energy) (25.93%), Dominion Iroquois, Inc. (Dominion Energy) (24.07%), and TransCanada Iroquois Ltd. (TC Energy) (0.66%). TransCanada Iroquois Ltd. and TCP’s ultimate parent is TC Energy Corporation (TC Energy), formerly known as TransCanada Corporation. Iroquois Pipeline Operating Company, a wholly owned subsidiary, is the administrative operator of the pipeline. IGTS, Inc. of Connecticut is an additional wholly owned subsidiary formed to hold title to certain Connecticut property interests.

Income and expenses are allocated to the partners and credited to their respective equity accounts in accordance with the partnership agreements and their respective percentage interests. Distributions to partners are made concurrently to all partners in proportion to their respective partnership interests.

NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Basis of Presentation

The consolidated financial statements of the Partnership are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The Partnership’s natural gas pipeline is subject to regulation by the Federal Energy Regulatory Commission (FERC). Generally accepted accounting principles for regulated entities allow the Partnership to give accounting recognition to the actions of regulatory authorities. In accordance with GAAP, the Partnership has deferred recognition of costs (a regulatory asset) or has recognized obligations (a regulatory liability) if it is probable that such costs will be recovered or an obligation relieved in the future through the rate-making process.

Principles of Consolidation

The consolidated financial statements include the accounts of the Partnership, Iroquois Pipeline Operating Company and IGTS, Inc. of Connecticut. Intercompany transactions have been eliminated in consolidation.

Cash and Temporary Cash Investments

The Partnership considers all highly liquid temporary cash investments purchased with an original maturity date of three months or less to be cash equivalents.

Natural Gas Plant in Service

Natural gas plant in service is carried at original cost. The majority of the natural gas plant in service is categorized as natural gas transmission plant. Effective September 1, 2016, as a result of the rate case (refer to Note 7) natural gas transmission plant assets are depreciated at a range of 1.7% to 2.95%. The rate for general plant assets which includes primarily vehicles, leasehold improvements and computer equipment are depreciated at a range of 1.9% to 12.0%. The rates for intangible plant assets are depreciated at a range of 0.35% to 2.0%.

Construction Work in Progress/ Commitments

At December 31, 2019 and December 31, 2018 construction work in progress primarily included preliminary construction costs relating to the Wright Interconnect (WIP) Project and Enhancement by Compression (ExC) Project. The Partnership also has commitments of approximately $2.5 million relating to the WIP Project at December 31, 2019 (Refer to Note 2- Subsequent Events).

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Allowance for Funds Used During Construction

The allowance for funds used during construction (AFUDC) represents the cost of funds used to finance natural gas transmission plant under construction. The AFUDC rate includes a component for borrowed funds as well as equity. The AFUDC is capitalized as an element of natural gas plant in service.

Revenue Recognition

The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Partnership utilizes the practical expedient of recognizing revenue as invoiced. The Partnership’s pipeline system does not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.

The Partnership's pipeline system is subject to FERC regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. As of December 31, 2019, and 2018, there are no refund provisions reflected in these financial statements. Refer to Note 9 for detailed disclosures regarding the Partnership’s revenues.

Income Taxes

Income taxes are the responsibility of the partners and are not reflected in these financial statements.

CT Pass-Through Entity Tax

On May 31, 2018, Connecticut passed legislation establishing a new pass-through entity tax.  The Partnership elected to utilize the alternative tax base which excludes any income attributable to publicly traded partnerships or corporations and therefore does not owe any tax.

Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The key estimates include determining the economic useful lives of the Partnership's assets, the fair values used to determine possible asset impairment charges, exposures under contractual indemnifications, calculations of pension expense and various other recorded or disclosed amounts. The Partnership believes that its estimates for these items are reasonable but cannot assure that actual amounts will not vary from estimated amounts.

Asset Retirement Obligations

The Partnership accounts for asset retirement obligations in accordance with GAAP, which requires entities to record the fair value of a liability for an asset retirement obligation during the period in which the liability is incurred, if a reasonable estimate of fair value can be made. The Partnership has determined that asset retirement obligations exist for certain of its transmission assets; however, the fair value of the obligations cannot be determined because the end of the transmission system life is not determinable with the degree of accuracy necessary to establish a liability for the obligations.

Debt Issuance Costs

Costs related to the issuance of debt are deferred and amortized using the straight-line method over the term of the related debt.

Debt issuance costs are presented in the consolidated balance sheet as a direct deduction from the carrying amount of debt liabilities. In addition, amortization of debt issuance costs are reported as part of interest expense. Debt issuance costs in prior years were immaterial, but the amounts have been reclassified to conform to the current year presentation.

Accounting Pronouncements

Changes Effective January 1, 2019

Leases

In February 2016, the Financial Accounting Standards Board (FASB) issued new guidance Accounting Standards Update (ASU) ASU 2016-02, Leases (Topic 842). The new guidance amends the definition of a lease such that, in order for an

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arrangement to qualify as a lease, the lessee, throughout the period of use, is required to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the consolidated balance sheet for all leases with a term longer than twelve months. Leases will be classified as finance or operating, with classification affecting the pattern of expense recognition in the consolidated statements of comprehensive income. The new guidance does not make extensive changes to previous lessor accounting.

Under the new guidance, the Partnership determines if an arrangement is a lease at inception. Operating leases are recognized as ROU assets and included in Other assets and deferred charges while corresponding liabilities are included in Other current liabilities, and Other non-current liabilities on the consolidated balance sheets.

Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease term at commencement date. If the Partnership’s leases do not have an implied rate, the present value of future minimum payments, if any, will be determined using a rate that approximates the Partnership’s incremental borrowing cost. Operating lease expense is recognized on a straight-line basis over the lease term and is included in Operation and maintenance expenses in the consolidated statements of comprehensive income.

The new guidance is effective January 1, 2021, with early adoption permitted. The Partnership early adopted the new standard ASU 2018-11, Leases-Target Improvements, on January 1, 2019. Under ASU 2018-11, the Partnership utilized the optional transition relief which allows entities to report comparative periods presented in the period of adoption under Accounting Standard Codification (ASC) ASC Topic 840. Consequently, financial information was not recast and the Partnership will recognize the effects of applying the guidance required under the new standard as of January 1, 2019.

The Partnership elected available practical expedients and exemptions upon adoption which permits entities (1) not to reassess prior conclusions on existing leases regarding lease identification, lease classification and initial direct costs under the new standard; (2) to carry forward the historical lease classification and accounting treatment for land easement on existing agreements; (3) to not recognize ROU assets or liabilities for leases that qualify for the short-term lease recognition exemption; (4) to not separate lease and non-lease components for all leases for which the Partnership is the lessee; and (5) to use hindsight in determining the lease term and assessing ROU assets for impairment.

In the application of the new guidance, assumptions and judgements are used to determine (1) whether a contract contains a lease and the duration of the lease term including exercising lease renewal options. The lease term for all of the Partnership’s leases includes the non-cancellable period of the lease plus any additional periods covered by either the Partnership’s option to extend (or not to terminate) the lease that the Partnership is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor; and (2) the discount rate for the lease. Refer to Note 11 for further information regarding lease disclosures.

Reclassification

Certain prior year amounts have been reclassified to conform with current year classifications.

Subsequent Events

Wright Interconnect Project (WIP)

Subsequent to year end, Iroquois has received notice of termination of the Precedent Agreement (PA) between Iroquois and Constitution effective February 10, 2020. That PA sets forth, among other things, Iroquois’ obligation to construct the WIP project facilities. The parties are working to finalize closure of the project pursuant to the terms of the PA.

As of December 31, 2019, Iroquois had incurred approximately $52.2 million of expenditures related to primarily engineering and procurement of materials and had made approximately $2.5 million in additional project related commitments. Due to contractual agreements in place, including a guarantee from Williams Partners, L.P., a 41% owner of Constitution, Iroquois will be exercising its contractual right to seek reimbursement for the total of these expenditures. While total expenditures might exceed the guarantee, the Iroquois believes it is not at material financial risk for recovery of these expenditures (refer to Note 7 – Wright Interconnect Project).

Enhancement by Compression Project (ExC)

During 2019 the Partnership entered into precedent agreements with Con Edison and KeySpan Gas East Corporation d/b/a National Grid to develop and permit incremental pipeline delivery capacity to transport additional volumes of natural gas along Iroquois’ system.  The project optimizes the Iroquois system to meet current and future gas supply needs of utility customers while minimizing environmental impact through compressor enhancements at existing compressor stations along the pipeline. The project’s total capacity is approximately 125,000 Dth/day and it is 100% underpinned by 20-year term contracts. On February 3, 2020, Iroquois filed for FERC approval of the project. The new facilities are scheduled to be in service by November 2023 with an estimated cost of $250.0 million.

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Distributions

On January 6, 2020, the Partnership paid $13.6 million to TCP, relating to the distribution declared on December 30, 2019.

In February 2020, the Partnership approved a distribution in the amount of $26.5 million. The distribution, which will be paid on March 30, 2020, includes its eleventh and final surplus cash distribution in the amount of $5.2 million as discussed in Note 7- Distributions.

The Partnership has evaluated all subsequent events through February 19, 2020, which is the date on which the financial statements were available to be issued.

NOTE 3 NATURAL GAS TRANSMISSION PLANT:

	Balances at December 31,
(thousands of dollars)	2019		2018
Classification
Transmission Plant	$	1,284,248	$	1,273,929
General Plant		26,217		22,966
		1,310,465		1,296,895
Less Accumulated Depreciation		(799,876)		(771,344)
Construction Work in Progress		59,003		55,495
Net Natural Gas Transmission Plant	$	569,592	$	581,046

Depreciation and amortization expense was $29.5 million in 2019, $29.2 million in 2018 and $28.8 million in 2017.

NOTE 4 LONG TERM DEBT:

On May 9, 2019, the Partnership refinanced its 6.63% $140.0 million and 4.48% $150.0 million senior notes due 2019 and 2020, respectively by issuing a new 15-year 4.12% $140.0 million, non-amortizing senior notes due 2034, and new 10-year 4.07% $150.0 million, non-amortizing senior notes due 2030*.

Detailed information on long-term debt is as follows (thousands of dollars):

At December 31	2019	2018
Senior Notes – 6.10% due August 2027	29,000	35,000
Senior Notes – 6.63% due May 2019	—	140,000
Senior Notes – 4.84% due April 2020*	150,000	150,000
Senior Notes – 4.12% due May 2034	140,000	—
Total	319,000	325,000
Less Current Maturities of Long-Term Debt	3,000	146,000
Long-Term portion	316,000	179,000
Less unamortized debt issuance costs	2,383	931
Long-term debt, net	313,617	178,069

*The refinancing agreement for the 4.07% $150.0 million senior notes, which is a firm commitment, has a delay draw feature where the Partnership will not be paying any interest on the new 4.07% $150.0 million senior notes until the funds are drawn to repay the existing 4.84% $150.0 million senior notes in 2020. As a result, the $150.0 million due 2020 is classified as long term debt. The Partnership will continue to pay the current interest rate 4.84% until April 27, 2020 when the interest rate of 4.07% becomes effective.

The combined schedule of repayments at December 31, 2019 is as follows (thousands of dollars):

Year	Scheduled Repayment
2020	$	3,000
2021	$	4,500
2022	$	3,000
2023	$	4,500
2024	$	4,000
Thereafter	$	300,000

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The above loans and facilities require the Partnership to maintain compliance with certain restrictive covenants relating to, among other things, certain ratios of indebtedness to total capitalization must be below 75 percent, and debt service coverage ratio must be at least 1.25 times for the four preceding quarters, as defined in the credit agreements and bond indentures. The Partnership is in compliance with these covenants as of and for the years ended December 31, 2019, December 31, 2018 and December 31, 2017.

On June 13, 2019, the $10.0 million revolving credit facility was renewed for 364 days. As of December 31, 2019, there are no amounts outstanding under the revolving credit facility.

NOTE 5 CONCENTRATIONS OF CREDIT RISK:

The Partnership's cash and temporary cash investments and trade accounts receivable represent concentrations of credit risk. Management believes that the credit risk associated with cash and temporary cash investments is mitigated by its practice of limiting its investments primarily to commercial paper rated P-1 or higher by Moody's Investors Services and A-1 or higher by Standard and Poor's, and its cash deposits to large, highly-rated financial institutions. Management also believes that the credit risk associated with trade accounts receivable is mitigated by the restrictive terms of the FERC gas tariff that require customers to pay for service within 20 days after the end of the month of service delivery. Also, the Partnership’s FERC-approved tariff provides that, subject to certain exceptions, the Partnership has the right to require that shippers have an investment grade rating or obtain a written shipper guarantee from a third party with an investment grade rating, or provide other financial assurances before service can be provided.

NOTE 6 FAIR VALUE OF FINANCIAL INSTRUMENTS:

The fair value amounts disclosed below have been reported to meet the disclosure requirements of GAAP and are not necessarily indicative of the amounts that the Partnership could realize in a current market exchange.

Under ASC 820, Fair Value Measurement, fair value measurements are characterized in one of three levels based upon the input used to arrive at the measurement. The three levels of fair value hierarchy are as follows; (1) Level 1 inputs are quoted market process for identical assets on an active market to which an entity has access at the measurement date; (2) Level 2 inputs are inputs from other than quoted market prices that are observable for the asset or liability, either directly or indirectly (i.e. quoted market prices for similar assets or liabilities); (3) Level 3 inputs are unobservable inputs for the asset or liability.

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

As of December 31, 2019, and December 31, 2018, the carrying amounts of cash and temporary cash investments, accounts receivable, accounts payable and accrued expenses are classified as Level 1 in the fair value hierarchy. Accordingly, the carrying values approximate fair values because of the short maturity or duration of these instruments.

The fair value of long-term debt, which is classified as Level 2 in the fair value hierarchy is estimated by the Partnership’s underwriter based on treasury rates and comparable spreads at fiscal year-end. As of December 31, 2019, and December 31, 2018, the carrying amounts and estimated fair values of the Partnership's long-term debt including current maturities were as follows (in thousands of dollars):

	Carrying
Year	Amount		Fair Value
2019	$	319,000	$	334,865
2018	$	325,000	$	332,372

NOTE 7 COMMITMENTS AND CONTINGENCIES:

Regulatory Proceedings

Mainline and Eastchester Rate Case Settlement

On January 21, 2016, the FERC opened Docket RP 16-301-000 to examine the appropriateness of the recourse rates charged by the Partnership for both its mainline and Eastchester shippers (2016 Rate Case). On April 5, 2016, the Partnership filed an analysis of its existing revenues and costs with the FERC as required by the January 21, 2016 order. Settlement conferences occurred on April 28, 2016, May 18, 2016, June 1, 2016 and June 16, 2016 which culminated in an agreement in principal resolving the 2016 Rate Case issues (Settlement). On August 18, 2016, as agreed to by the Parties, the Settlement was filed with the FERC concurrent with a motion for interim rates to be placed into effect on September 1, 2016. On August 26, 2016, the Chief Administrative Law Judge issued an order approving the interim rates effective September 1, 2016.

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On October 20, 2016, the FERC issued an order approving the Settlement reached between the Partnership and the other parties. Pursuant to the Settlement, there will be a rate moratorium wherein no new firm recourse rates can be placed into effect on the Partnership’s mainline or Eastchester facilities until September 1, 2020. Following the conclusion of the moratorium, if no rate case is filed or if no new rate settlement is reached, the Partnership must file a Section 4 rate case no later than September 1, 2022. During the period of the moratorium, Iroquois will reduce its 100% load factor interzone rate by approximately $0.075 per dekatherm (approximately $0.02 beginning September 1, 2016, an additional $0.02 beginning September 1, 2017, and an additional $0.035 beginning September 1, 2018). Also during the moratorium period, Iroquois will reduce its 100% load factor Eastchester rate by approximately $0.24 per dekatherm (approximately $0.18 beginning September 1, 2016, and an additional $0.06 beginning September 1, 2018).

Based on long-term firm service contracts in place on September 1, 2016, the approved settlement has resulted in reductions in long-term firm revenue of $2.5 million in 2016, $6.4 million in 2017, $6.6 million in 2018, and $9.3 million in 2019. The settlement also required a modification to the Partnership’s depreciation rates which is described in Natural Gas Plant in service in Note 2.

2018 FERC Actions

During 2018, the Partnership has completed the regulatory filing that was required by FERC (see details below) to address the issues contemplated by Public Law No. 115-97, commonly known as the Tax Cuts and Jobs Act (2017 Tax Act) and certain FERC actions that began in March of 2018, namely FERC’s Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and a Final Rule that established a schedule by which interstate pipelines must have either (i) filed a new uncontested rates settlement or (ii) filed 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. In addition to filing the one-time report, each pipeline had four options: (1) Each pipeline may simultaneously make a limited section 4 filing to reduce its rates by the percentage reduction in its cost of service shown in its FERC Form No. 501-G; (2) Each pipeline may simultaneously commit to file either a prepackaged uncontested rate settlement or a general NGA section 4 rate case if it believes that using the limited section 4 option will not result in a just and reasonable rate. If the pipeline commits to file either by December 31, 2018, FERC will not initiate a section 5 investigation of its rates prior to that date; (3) Alternatively, each pipeline that does not believe it has to change its rates may choose to file a statement explaining why; (4) Finally, a pipeline may file the one-time report without taking any other action. At that point, FERC would consider whether to initiate a section 5 investigation of any pipeline that has not submitted a limited section 4 rate reduction filing or committed to file a general section 4 rate case.

Action taken by the Partnership to address the 2018 FERC Actions

Iroquois filed its FERC Form No. 501-G on December 6, 2018, in Docket No. RP19-445-000. Iroquois’ Form No. 501-G filing reflected the elimination of its income tax allowance and ADIT balances in accordance with the 2018 FERC Actions. Iroquois stated that no rate adjustments were appropriate in light of its RP16-301 Settlement moratorium. Shippers and other interested parties filed comments and protests and, following negotiations, Iroquois and interested parties reached a settlement in principle pursuant to which Iroquois would reduce its rates by 6.5 percent in two phases to reflect the reduction in income taxes indicated in its Form No. 501-G filing, but otherwise to leave the RP16-301 Rate Settlement in place. This additional rate reduction will be implemented equally in two step-downs. The first step down is effective March 1, 2019, and the second is effective April 1, 2020. Iroquois filed the settlement with FERC on February 28, 2019 (RP19-445 Settlement). On May 2, 2019, FERC issued an order approving the RP19-445 Settlement

Brookfield, Connecticut Site Clean Up

On June 27, 2003, the Partnership purchased real property in Brookfield, Connecticut upon which it constructed its Brookfield compressor station (Brookfield Site or Site). On November 3, 2004, the Connecticut Department of Energy and Environmental Protection (DEEP) approved the Site’s remediation plan and scope of work schedule. After the major clean-up, re-grading, and seeding work at the Brookfield Site was completed (with the exception of buried tires on the property which is discussed below), Iroquois received a Letter of No Audit (LNA) from the DEEP dated November 13, 2014.  The LNA states that the DEEP agrees with Iroquois’ Licensed Environmental Professional (LEP) that the site is now clean (with the exception of the buried tires on the property) and closes the Environmental Condition Assessment Form (ECAF) for the Brookfield Voluntary Cleanup. For the remaining buried tires on the Brookfield site, Iroquois has entered into the state Stewardship Program. The stewardship program authorization expires in May of 2022 at which time Iroquois will file for an additional 10-year extension. The program requires monitoring of the tire area until 2041 and remediation of any erosion, subsidence, or tires that have worked their way to the surface. It is not anticipated that the ongoing monitoring of this site will have a material adverse effect on the Partnership’s financial condition or results of operations.

Wright Interconnect Project

In December of 2012, the Partnership entered into a Precedent Agreement (PA) with Constitution Pipeline Company, LLC (Constitution). The PA requires the Partnership to expand its current compression station located in Wright, New York. The project, which consists of constructing two new compressor units in addition to new metering facilities, and other

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minor facility modifications, would enable the Partnership to accept up to 650,000 Dth/d of gas from the proposed Constitution pipeline and deliver this gas into either the Partnership’s currently existing mainline or into the Tennessee Gas Pipeline. Pursuant to the PA, Constitution and the Partnership will enter into a capacity lease agreement in which Constitution leases the transmission capacity made available by the new compressor units. This lease agreement is for a period of fifteen years with an option for Constitution to extend the lease an additional five years. This project will require FERC and other regulatory approvals. On June 13, 2013, the Partnership and Constitution filed for FERC approval of the project. On December 2, 2014, the Partnership received its 7(c) Certificate Order from FERC granting approval for the project (as well as Constitution’s pipeline project), with the approval conditioned on the Partnership obtaining all outstanding permits. The Partnership continues to work with State and Local authorities to obtain all required permits. On November 5, 2018, FERC granted a 2-year extension to complete construction of the project to the Partnership and Constitution.

On April 22, 2016, the New York State Department of Environmental Conservation (DEC) denied Constitution’s application for a water quality certification (WQC) under Section 401 of the Clean Water Act. Constitution had applied for the 401 WQC in order to construct its 124 mile pipeline. On May 16, 2016, Constitution filed a petition for review of the denial to the U. S. Court of Appeals for the Second Circuit (Second Circuit), arguing that the DEC’s denial was arbitrary and capricious. On August 18, 2017, the Second Circuit issued its opinion denying in part and dismissing in part Constitution’s petition. The Second Circuit declined to rule on Constitution’s argument that DEC’s long-delayed decision on Constitution’s Section 401 application triggered a waiver of the DEC’s WQC authority under Section 401. The Second Circuit determined that it lacked jurisdiction to address that issue, as jurisdiction lay exclusively with the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit) under the Natural Gas Act (NGA). On Constitution’s merit arguments, the Second Circuit upheld the DEC’s denial of the WQC. Constitution’s petition for rehearing of the Second Circuit’s decision, and its petition for a writ of certiorari to the U.S. Supreme Court, were both denied. On October 11, 2017, Constitution petitioned the FERC for a declaratory order finding that the DEC failed to act within the statutorily prescribed period of time on Constitution’s WQC Application and that such failure to act constitutes a waiver of the DEC’s Section 401 authority. FERC issued an Order on January 11, 2018, denying Constitution’s petition, and denied rehearing of that order on July 19, 2018.

On September 14, 2018, Constitution filed a petition for review with the D.C. Circuit, requesting review and reversal of FERC’s two orders denying Constitution’s petition requesting a finding of agency waiver. The D.C. Circuit granted FERC’s motion to hold that case in abeyance pending the court’s further action in Hoopa Valley Tribe v. FERC, D.C. Circuit Case No. 14-1271 (argued October 1, 2018). On January 25, 2019, the D.C. Circuit issued its decision in Hoopa Valley Tribe v. FERC, concluding that on the basis of the facts presented there, “the withdrawal-and-resubmission of water quality certification requests does not trigger new statutory periods of review.”

On February 25, 2019, FERC filed in the Constitution Pipeline Company, LLC v. FERC, D.C. Circuit Case No. 18-1251 proceeding, an unopposed motion for voluntary remand so that it might consider the implications of the Hoopa Valley decision on the FERC Orders under review in that case. The D.C. Circuit granted FERC’s motion on February 28, 2019. On August 28, 2019, FERC issued its “Order on Voluntary Remand” finding that in light of the Hoopa Valley decision, that the DEC had waived its WQC authority with respect to the Constitution Pipeline Project (Constitution Waiver Order). The FERC further denied the DEC’s request for a stay of effectiveness of its decision, or alternatively, a stay of any further FERC action to authorize construction of the pipeline project pending further review of the matter or the DEC’s issuance of a WQC to Constitution. The DEC and several other parties sought rehearing of this Order. On December 13, 2019, FERC issued its Order denying rehearing and stay of this Order. The DEC filed a petition for review of the above FERC orders on December 30, 2019 with the U.S. Court of Appeals for the Second Circuit. The matter is pending.

The Partnership is required to obtain a Title V Facility Permit (Permit), under the Clean Air Act, for the construction and operations of the WIP facilities. On July 26, 2013, the Partnership filed a Permit application with the DEC, and the DEC subsequently published a Notice of Complete Application (NOCA) on December 24, 2014. The DEC and the Environmental Protection Agency (EPA) regulations implementing the Clean Air Act, state that final action on a Title V Permit must be taken within eighteen months of publishing the NOCA. However, the DEC failed to submit the Permit to the Environmental Protection Agency on or before June 24, 2016, thus violating the eighteen month requirement of the Clean Air Act. The Partnership filed a petition with the DC Circuit on July 13, 2016, pursuant to the NGA, regarding the DEC’s failure to timely submit the Permit to the EPA. On October 6, 2016, as amended February 15, 2018, the Partnership and the DEC entered into and filed a Stipulation of Settlement and a Joint Motion to Hold Petition in Abeyance Pending Performance of Stipulation of Settlement. Among other provisions, the Stipulation requires the DEC to submit the Permit to the EPA in the event that Constitution prevails in its litigation regarding the DEC WQC, or is otherwise able to resolve the matter and obtain authority from FERC to commence construction.

By letter dated September 27, 2019, Iroquois requested that the DEC confirm the status of its compliance with the remaining terms of the Stipulation of Settlement filed in this proceeding. Iroquois stated that, under the Stipulation of Settlement, the issuance by FERC of the Constitution Waiver Order was the triggering event for the DEC to release Iroquois’ Title V air permit to the EPA to commence a statutory 45-day comment period within 15 business days, assuming DEC had not, during that same time period, sought a stay of such order. Iroquois further stated that, as no stay

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request had been filed during that period (which expired on September 19, 2019), the Stipulation of Settlement requires the DEC to fulfill its responsibilities and release Iroquois’ permit to the EPA. After negotiations, Iroquois and the DEC agreed to a second amendment of the Stipulation of Settlement (Second Amendment) wherein the DEC is required to complete the processing of Iroquois’ Title V Permit upon the receipt by Constitution of authority from FERC to commence construction of its pipeline project (referred to as a Notice to Proceed). The DEC’s obligation to complete the processing of Iroquois’ Title V Permit would be stayed in the event and for so long as FERC or a court with jurisdiction stays Constitution’s construction of the pipeline.

As discussed in Note 2 – Subsequent Events, Constitution terminated the Precedent Agreement subsequent to December 31, 2019.

Litigation Proceedings

The Partnership is a party to various legal matters incidental to its business. However, the Partnership believes that the outcome to these proceedings will not have a material adverse effect on the Partnership’s financial condition or results of operations.

No liabilities have been recorded by the Partnership in conjunction with any legal matters.

Distributions

The Partnership is restricted under the terms of its note purchase agreement from making cash distributions to its partners unless certain conditions are met. Before a distribution can be made, the debt/capitalization ration must be below 75 percent and the debt service coverage ratio must be at least 1.25 times for the four preceding quarters. At December 31, 2019, the debt/capitalization ratio was 52.1 percent and the debt service coverage ratio was 5.38 times, therefore, the Partnership was not restricted from making cash distributions.

The Partnership adopted a distribution resolution to distribute surplus cash to its partners of $57.4 million to be paid as part of its quarterly distributions over 11 quarters. Under the terms of the resolution an additional $5.2 million will be paid per quarter, which began with the second quarter 2017 distributions. As of December 31, 2019, the Partnership made ten surplus cash distributions, in accordance with the resolution, totaling $52.2 million.

The Partnership adopted an additional distribution resolution to distribute surplus cash to its partners of $30.0 million to be paid in lump sum. The Partners approved a resolution effective May 13, 2019 to contribute to the Partnership $7.0 million for the purpose of acquiring the necessary regulatory approvals for the new ExC project. Effective August 27, 2019 resolutions were signed to distribute the $30.0 million distribution and the $7.0 contribution which was paid on August 30, 2019.

NOTE 8 MAJOR CUSTOMERS:

For the years ended December 31, 2019, December 31, 2018 and December 31, 2017, two customers provided significant operating revenues totaling $50.3 million, $49.1 million and $46.7 million, respectively.

NOTE 9 REVENUES:

On January 1, 2018, the Partnership adopted new FASB guidance on revenue from contracts with customers using the modified retrospective transition method for all contracts that were in effect on the date of adoption. The reported results for 2019 and 2018 reflect the application of the new guidance, while the reported results for all periods in 2017 were prepared under previous revenue recognition guidance which is referred to herein as legacy U.S. GAAP.

Disaggregation of Revenues

For the year ended December 31, 2019 and 2018, effectively all the Partnership’s revenues were from capacity arrangements and transportation contracts with customers as discussed under Note 2- Significant Accounting Policies.

Also noted under Note 2 - Significant Accounting Policies, a portion of the Partnership’s revenues collected may be subject to refund when a rate proceeding is ongoing or as part of a rate case settlement with customers. The Partnership uses its best estimate based on the facts and circumstances of the proceeding to provide for allowances for these potential refunds in the revenue we recognized.

During the year ended December 31, 2019, 2018 and 2017, the Partnership operated under a FERC approved 2016 rate settlement and as such, no revenues were subject to refund.

Financial Statement Impact of Adopting Revenue from Contracts with Customers

The Partnership adopted the new guidance using the modified retrospective transition method. As a practical expedient under this transition method, the Partnership is not required to analyze completed contracts at the date of adoption.  The

F-78    TC PipeLines, LP Annual Report 2019

adoption of the new guidance did not have a material impact on the Partnership’s previously reported financial statements at December 31, 2017.

Pro-forma Financial Statements under Legacy U.S. GAAP

At December 31, 2019 and 2018, had legacy U.S. GAAP been applied, there would be no change in the Partnership’s reported consolidated balance sheet and consolidated statements of comprehensive income line items.

Contract Balances

The Partnership’s contract balances consist primarily of receivables from contracts with customers reported under accounts receivable trade on the consolidated balance sheet. Additionally, the accounts receivable represents the Partnership’s unconditional right to consideration for services completed which includes billed and unbilled accounts.

Right to invoice practical expedient

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

NOTE 10 OTHER COMPREHENSIVE LOSS:

For the years ended December 31, 2019, 2018 and 2017, the accumulated balances related to other comprehensive (loss) / income consisted of the following (thousands of dollars):

	Adjustment to Retirement Benefit Plans		Other Adjustments		Accumulated Other Comprehensive (Loss)/Income
Balance as of 12/31/18	$	(3,974)	$	67	$	(3,907)
Current-period other comprehensive income		2,146		162		2,308
Balance as of 12/31/19	$	(1,828)	$	229	$	(1,599)

	Adjustment to Retirement Benefit Plans		Other Adjustments		Accumulated Other Comprehensive (Loss)/Income
Balance as of 12/31/17	$	(1,517)	$	131	$	(1,386)
Current-period other comprehensive (loss)		(2,457)		(64)		(2,521)
Balance as of 12/31/18	$	(3,974)	$	67	$	(3,907)

	Adjustment to Retirement Benefit Plans		Other Adjustments		Accumulated Other Comprehensive (Loss)/Income
Balance as of 12/31/16	$	(3,264)	$	48	$	(3,216)
Current-period other comprehensive income		1,747		83		1,830
Balance as of 12/31/17	$	(1,517)	$	131	$	(1,386)

NOTE 11 LEASES:

The Partnership’s consolidated balance sheet beginning January 1, 2019 was impacted by the new lease accounting through the recognition of ROU assets and liabilities for operating leases. Amounts recognized at January 1, 2019 for operating were as follows (in millions):

At January 1	2019
ROU assets	$	8,283
Short-term lease liability	$	1,086
Long-term lease liability	$	7,197

No impact was recorded to the beginning partners equity.

The Partnership leases its corporate office and one field office space under operating lease arrangements. The leases expire at various dates through 2022 and have the options to extend or terminate the leases. For purposes of calculating ROU asset and operating lease liabilities, the Partnership deemed that it was reasonable that they would exercise the 5 year extension of the agreement that is present in both lease contracts and included the 5 year extensions in the ROU assets and liabilities calculation.

F-79    TC PipeLines, LP Annual Report 2019

Beginning January 1, 2019, ROU assets and lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. The following are the components of lease costs (in millions, except for lease terms and discount rate):

At December 31	2019
Operating lease costs	$	1,085
Weighted average remaining lease term		7.97	years
Discount Rate		4.08	%

Amounts recognized in the accompanying consolidated balance sheet are as follows (in millions):

Lease activity	Balance sheet location	2019
ROU assets	Other assets and deferred charges	$	7,520
Short-term liability	Other current liabilities	$	1,101
Long-term liability	Other liabilities	$	6,435

Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2019 (in millions):

Year	Amount
2020	$	1.1
2021	$	1.1
2022	$	1.1
2023	$	1.2
2024	$	1.2
Thereafter	$	3.3
Total lease payments	$	9
Less: Interest	$	(1.5)
Present value of lease liabilities	$	7.5

Undiscounted future gross minimum operating lease payments as of December 31, 2018 were as follows (in millions):

Year	Amount
2019	$	1.1
2020	$	1.1
2021	$	1.1
2022	$	1.2
2023	$	1.2
Thereafter	$	4.5

NOTE 12 NON CASH INVESTING AND FINANCING ACTIVITIES:

ROU assets and operating lease obligations totaling $8,283 were recognized during the year ending December 31, 2019 (Refer to Note 11).

NOTE 13 RETIREMENT BENEFIT PLANS:

The Partnership has established a noncontributory cash balance retirement plan (the Plan) covering substantially all employees. Pension benefits are based on years of credited service and employees’ career earnings, as defined in the Plan. The Partnership’s funding policy is to contribute, annually, an amount at least equal to that which will satisfy the minimum funding requirements of the Employee Retirement Income Security Act (ERISA) plus such additional amounts, if any, as the Partnership may determine to be appropriate from time to time.

The Partnership also has adopted an excess benefit plan (EBP) that provides retirement benefits to executive officers. The EBP recognizes total compensation and service that would otherwise be disregarded due to Internal Revenue Code limitations on compensation in determining benefits under the regular retirement plan. The EBP is not considered to be funded for ERISA purposes and benefits are paid when due from general corporate assets. A Rabbi Trust, which is included in other assets and deferred charges on the Partnership’s consolidated balance sheets, has been established to partially cover this obligation. The Rabbi Trust is an irrevocable trust which can be used to satisfy creditors.

F-80    TC PipeLines, LP Annual Report 2019

The consolidated net cost for pension benefit plans included in the consolidated statements of comprehensive income for the years ending December 31 (which is the measurement date for each year), includes the following components (thousands of dollars):

	2019		2018		2017
Service cost	$	1,477	$	1,544	$	1,553
Interest cost		998		843		885
Expected return on plan assets		(1,817)		(1,749)		(1,680)
Recognition of net actuarial loss		140		187		201
Net periodic benefit cost	$	798	$	825	$	959

In the consolidated statements of operations, service cost is included in operation and maintenance expenses and the other components of net periodic benefit cost are included in other, net.

The following tables represent the Plans’ combined funded status reconciled to amounts included in the consolidated balance sheets as of December 31, 2019 and 2018 (thousands of dollars):

Change in benefit obligation	2019		2018
Benefit obligation at beginning of year	$	24,746	$	24,814
Service cost		1,477		1,544
Interest cost		998		843
Actuarial loss/(gain)		1,891		(1,043)
Benefits Paid		(230)		(1,412)
Benefit obligation at end of year	$	28,882	$	24,746
Change in plan assets
Fair value of plan assets at beginning of year	$	26,419	$	28,549
Actual return on plan assets		5,714		(1,939)
Employer contribution		1,221		1,221
Benefits Paid		(230)		(1,412)
Fair value of plan assets at end of year	$	33,124	$	26,419
Funded Status	$	4,242	$	1,673
Amount Recognized in Consolidated Balance Sheets Consisted of:		2019		2018
Non-current asset	$	5,656	$	2,770
Current liability		(80)		(50)
Non-current liability		(1,334)		(1,047)
Net amount recognized	$	4,242	$	1,673

	Plan Assets						Benefit Obligations
	2019		2018		2017		2019		2018		2017
Plans in overfunded status	$	33,124	$	26,419	$	28,549	$	27,468	$	23,649	$	23,790
Plans in underfunded status		—		—		—		1,414		1,097		1,024

The accumulated benefit obligation for the Partnership’s retirement benefit plans was $26.1 million, $24.7 million, and $24.8 million at December 31, 2019, 2018 and 2017, respectively.

Amounts recognized in accumulated other comprehensive income at December 31 (thousands of dollars):

	2019		2018		2017
Transition obligation		—		—		—
Prior service cost		—		—		—
Net loss	$	1,828	$	3,974	$	1,517
Total Recognized in Accumulated Other Comprehensive Income	$	1,828	$	3,974	$	1,517

Estimated net periodic benefit cost amortizations for the periods January 1 - December 31 (thousands of dollars):

	2020
Amortization of transition obligation		—
Amortization of prior service cost		—
Amortization of net loss	$	238
Total Estimated Net Periodic Benefit Cost Amortizations	$	238

F-81    TC PipeLines, LP Annual Report 2019

The following table summarizes the weighted average assumptions used to determine benefit obligations as of December 31 (rates shown are rates at end of measurement period):

	Cash Balance
	Retirement Plan						Excess Benefit Plans
	2019		2018		2017		2019		2018		2017
Discount rate	3.15	%	4.15	%	3.50	%	3.00	%	4.05	%	3.45	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%

The following table summarizes the weighted average assumptions used to determine the net periodic benefit cost for years ended December 31 (rates shown are rates at beginning of measurement period)

	Cash Balance
	Retirement Plan						Excess Benefit Plans
	2019		2018		2017		2019		2018		2017
Discount rate	4.15	%	3.50	%	4.00	%	4.05	%	3.45	%	3.85	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%	4.00	%
Expected long-term return on	6.75	%	7.00	%	7.00	%
plan assets

The expected long-term rate of return assumption was developed using a variety of factors including long-term historical return information, the current level of expected returns and general industry expectations. Adjustments are made to the expected long-term rate of return assumption when deemed necessary based upon revised expectations of future investment performance of the overall capital markets. The building block methodology was used to generate the capital market assumptions, to the extent that the expected return has not shifted the long term expected rate will not be adjusted.

The discount rate was selected to reflect the rates of return currently available on high quality fixed income securities whose cash flows match the timing and amount of future benefit payments of the plan. In particular, the discount rate takes into consideration the population of our pension plan and the anticipated payment stream as compared to the FTSE Pension Liability Index (formerly called the Citi Pension Discount Curve).

The following table summarizes the expected future benefit payments over the next five years and aggregate five years thereafter (thousands of dollars):

Year		Benefit Payment
2020	$	2,226
2021	$	1,801
2002	$	1,777
2023	$	1,443
2024	$	2,881
2025-2029	$	11,162

Plan Assets

The following table sets forth the Partnership’s pension plans weighted average asset allocations and target asset allocations, and fair value of the plan assets at December 31, 2019 and December 31, 2018.

	Weighted Average				Plan Target				Fair Value of Plan Assets
	Asset Allocation				Asset Allocation				(thousands of dollars)
	2019		2018		2019		2018		2019		2018
Mutual Funds
U.S. Equities	38	%	36	%	38	%	35	%	$	12,580	$	9,457
International Equities	17	%	22	%	17	%	22	%		5,652		5,787
Real Estate	5	%	3	%	5	%	3	%		1,643		931
U.S. Fixed Income	39	%	36	%	39	%	37	%		12,910		9,479
Other	1	%	3	%	1	%	3	%		339		765
							Total		$	33,124	$	26,419

The Partnership’s investment goal is to obtain a competitive risk adjusted return on the pension plan assets commensurate with prudent investment practices and the plan’s responsibility to provide retirement benefits for its

F-82    TC PipeLines, LP Annual Report 2019

participants, retirees and their beneficiaries. The Plan’s asset allocation targets are strategic and long term in nature and are designed to take advantage of the risk reducing impacts of asset class diversification.

Plan assets are periodically rebalanced to their asset class targets to reduce risk and to retain the portfolio’s strategic risk/return profile. Investments within each asset category are further diversified with regard to investment style and concentration of holdings.

The Plan's investments are diversified to minimize the risk of a large loss. The Plan is constructed and maintained to provide prudent diversification among the asset classes in accordance with the asset allocation objectives. Within each asset class, there is prudent diversification with regard to investment styles and concentration of holdings.

Under the plans investment guidelines, the portfolio may contain mutual funds which are managed in accordance with the diversification and industry concentration restrictions set forth in the Investment Company Act of 1940, as amended (the 1940 Act). Pursuant to the provisions of the 1940 Act, a mutual fund may not, with respect to 75% of its assets, (i) purchase securities of any issuer (except securities issued or guaranteed by the United States Government, its agencies or instrumentalities) if, as a result, more than 5% of its total assets would be invested in the securities of such issuer; or (ii) acquire more than 10% of the outstanding voting securities of any one issuer.

In addition, no mutual fund may purchase any securities which would cause more than 25% of its total assets to be invested in the securities of one or more issuers conducting their principal business activities in the same industry, provided that this limitation does not apply to investments in securities issued or guaranteed by the United States Government, its agencies or instrumentalities.

All but one of the assets within Iroquois’ Pension Plan are valued using Level 1 inputs in accordance with GAAP. As of December 31, 2019, one of the Plan’s assets totaling $1.64 million is valued using Level 2 inputs, and the Partnership has the ability to redeem the asset or liability in the near term subsequent to the measurement date.

Contributions

Iroquois expects to contribute approximately $1.4 million to its pension plan in 2020.

F-83    TC PipeLines, LP Annual Report 2019

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dei:EntityCentralIndexKey#	0001075607
dei:CurrentFiscalYearEndDate	--12-31
dei:DocumentFiscalYearFocus	2019
deiDocumentFiscalPeriodFocus	FY
dei:AmendmentFlag	false
dei:TradingSymbol	TCP

F-84    TC PipeLines, LP Annual Report 2019

EX-3.2

Exhibit 3.2

CONFORMED COPY OF FOURTH AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

TC PIPELINES, LP

(INCORPORATING AMENDMENT NO. 1 THERETO, ENTERED INTO ON
FEBRUARY 4, 2020 AND EFFECTIVE AS OF DECEMBER 31, 2018)

TABLE OF CONTENTS

ARTICLE I DEFINITIONS		2
SECTION 1.1	DEFINITIONS.	2
SECTION 1.2	CONSTRUCTION.	19
ARTICLE II ORGANIZATION		19
SECTION 2.1	FORMATION.	19
SECTION 2.2	NAME.	20
SECTION 2.3	REGISTERED OFFICE; REGISTERED AGENT; PRINCIPAL OFFICE; OTHER OFFICES.	20
SECTION 2.4	PURPOSE AND BUSINESS.	20
SECTION 2.5	POWERS.	21
SECTION 2.6	POWER OF ATTORNEY.	21
SECTION 2.7	TERM.	22
SECTION 2.8	TITLE TO PARTNERSHIP ASSETS.	22
ARTICLE III RIGHTS OF LIMITED PARTNERS		23
SECTION 3.1	LIMITATION OF LIABILITY.	23
SECTION 3.2	MANAGEMENT OF BUSINESS.	23
SECTION 3.3	OUTSIDE ACTIVITIES OF THE LIMITED PARTNERS.	23
SECTION 3.4	RIGHTS OF LIMITED PARTNERS.	23
ARTICLE IV CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS		24
SECTION 4.1	CERTIFICATES.	24
SECTION 4.2	MUTILATED, DESTROYED, LOST OR STOLEN CERTIFICATES.	25
SECTION 4.3	RECORD HOLDERS.	25
SECTION 4.4	TRANSFER GENERALLY.	26
SECTION 4.5	REGISTRATION AND TRANSFER OF LIMITED PARTNER INTERESTS.	26
SECTION 4.6	TRANSFER OF THE GENERAL PARTNER’S GENERAL PARTNER INTEREST.	27
SECTION 4.7	TRANSFER OF INCENTIVE DISTRIBUTION RIGHTS.	28
SECTION 4.8	RESTRICTIONS ON TRANSFERS.	28
SECTION 4.9	CITIZENSHIP CERTIFICATES; NON-CITIZEN ASSIGNEES.	29
SECTION 4.10	REDEMPTION OF PARTNERSHIP INTERESTS OF NON-CITIZEN ASSIGNEES.	29
ARTICLE V CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS		31

i

SECTION 5.1	[INTENTIONALLY OMITTED.]	31
SECTION 5.2	CONTRIBUTIONS TO THE PARTNERSHIP.	31
SECTION 5.3	[INTENTIONALLY OMITTED.]	31
SECTION 5.4	INTEREST AND WITHDRAWAL.	31
SECTION 5.5	CAPITAL ACCOUNTS.	31
SECTION 5.6	ISSUANCES OF ADDITIONAL PARTNERSHIP SECURITIES.	34
SECTION 5.7	LIMITATIONS ON ISSUANCE OF FRACTIONAL PARTNERSHIP SECURITIES.	35
SECTION 5.8	[INTENTIONALLY OMITTED.]	35
SECTION 5.9	LIMITED PREEMPTIVE RIGHT.	35
SECTION 5.10	SPLITS AND COMBINATION.	35
SECTION 5.11	FULLY PAID AND NON-ASSESSABLE NATURE OF LIMITED PARTNER INTERESTS.	36
ARTICLE VI ALLOCATIONS AND DISTRIBUTIONS		36
SECTION 6.1	ALLOCATIONS FOR CAPITAL ACCOUNT PURPOSES.	36
SECTION 6.2	ALLOCATIONS FOR TAX PURPOSES.	43
SECTION 6.3	REQUIREMENT AND CHARACTERIZATION OF DISTRIBUTIONS; DISTRIBUTIONS TO RECORD HOLDERS.	45
SECTION 6.4	DISTRIBUTIONS OF AVAILABLE CASH FROM OPERATING SURPLUS.	46
SECTION 6.5	DISTRIBUTIONS OF AVAILABLE CASH FROM CAPITAL SURPLUS.	46
SECTION 6.6	ADJUSTMENT OF MINIMUM QUARTERLY DISTRIBUTION AND TARGET DISTRIBUTION LEVELS.	46
SECTION 6.7	[INTENTIONALLY OMITTED.]	47
SECTION 6.8	SPECIAL PROVISIONS RELATING TO THE HOLDERS OF INCENTIVE DISTRIBUTION RIGHTS.	47
SECTION 6.9	ENTITY-LEVEL TAXATION.	47
ARTICLE VII MANAGEMENT AND OPERATION OF BUSINESS		48
SECTION 7.1	MANAGEMENT.	48
SECTION 7.2	CERTIFICATE OF LIMITED PARTNERSHIP.	49
SECTION 7.3	RESTRICTIONS ON GENERAL PARTNER’S AUTHORITY.	50
SECTION 7.4	REIMBURSEMENT OF THE GENERAL PARTNER.	50
SECTION 7.5	OUTSIDE ACTIVITIES.	51
SECTION 7.6	LOANS FROM THE GENERAL PARTNER; LOANS OR CONTRIBUTIONS FROM THE PARTNERSHIP; CONTRACTS WITH AFFILIATES; CERTAIN RESTRICTIONS ON THE GENERAL PARTNER.	52
SECTION 7.7	INDEMNIFICATION.	54
SECTION 7.8	LIABILITY OF INDEMNITEES.	56

ii

SECTION 7.9	RESOLUTION OF CONFLICTS OF INTEREST.	56
SECTION 7.10	OTHER MATTERS CONCERNING THE GENERAL PARTNER.	58
SECTION 7.11	PURCHASE OR SALE OF PARTNERSHIP SECURITIES.	58
SECTION 7.12	REGISTRATION RIGHTS OF THE GENERAL PARTNER AND ITS AFFILIATES.	59
SECTION 7.13	RELIANCE BY THIRD PARTIES.	61
ARTICLE VIII BOOKS, RECORDS, ACCOUNTING AND REPORTS		61
SECTION 8.1	RECORDS AND ACCOUNTING.	61
SECTION 8.2	FISCAL YEAR.	61
SECTION 8.3	REPORTS.	62
ARTICLE IX TAX MATTERS		62
SECTION 9.1	TAX RETURNS AND INFORMATION.	62
SECTION 9.2	TAX ELECTIONS.	62
SECTION 9.3	TAX CONTROVERSIES.	63
SECTION 9.4	WITHHOLDING.	64
ARTICLE X ADMISSION OF PARTNERS		65
SECTION 10.1	CURRENT PARTNERS.	65
SECTION 10.2	ADMISSION OF SUBSTITUTED LIMITED PARTNER.	65
SECTION 10.3	ADMISSION OF SUCCESSOR GENERAL PARTNER.	65
SECTION 10.4	ADMISSION OF ADDITIONAL LIMITED PARTNERS.	66
SECTION 10.5	AMENDMENT OF AGREEMENT AND CERTIFICATE OF LIMITED PARTNERSHIP.	66
ARTICLE XI WITHDRAWAL OR REMOVAL OF PARTNERS		66
SECTION 11.1	WITHDRAWAL OF THE GENERAL PARTNER.	66
SECTION 11.2	REMOVAL OF THE GENERAL PARTNER.	68
SECTION 11.3	INTEREST OF DEPARTING PARTNER AND SUCCESSOR GENERAL PARTNER.	68
SECTION 11.4	[INTENTIONALLY OMITTED.]	70
SECTION 11.5	WITHDRAWAL OF LIMITED PARTNERS.	70
ARTICLE XII DISSOLUTION AND LIQUIDATION		70
SECTION 12.1	DISSOLUTION.	70
SECTION 12.2	CONTINUATION OF THE BUSINESS OF THE PARTNERSHIP AFTER DISSOLUTION.	71
SECTION 12.3	LIQUIDATOR.	71
SECTION 12.4	LIQUIDATION.	72
SECTION 12.5	CANCELLATION OF CERTIFICATE OF LIMITED PARTNERSHIP.	73

iii

SECTION 12.6	RETURN OF CONTRIBUTIONS.	73
SECTION 12.7	WAIVER OF PARTITION.	73
SECTION 12.8	CAPITAL ACCOUNT RESTORATION.	73
ARTICLE XIII AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE		73
SECTION 13.1	AMENDMENT TO BE ADOPTED SOLELY BY THE GENERAL PARTNER.	73
SECTION 13.2	AMENDMENT PROCEDURES.	75
SECTION 13.3	AMENDMENT REQUIREMENTS.	75
SECTION 13.4	SPECIAL MEETINGS.	76
SECTION 13.5	NOTICE OF A MEETING.	76
SECTION 13.6	RECORD DATE.	77
SECTION 13.7	ADJOURNMENT.	77
SECTION 13.8	WAIVER OF NOTICE; APPROVAL OF MEETING; APPROVAL OF MINUTES.	77
SECTION 13.9	QUORUM.	77
SECTION 13.10	CONDUCT OF A MEETING.	78
SECTION 13.11	ACTION WITHOUT A MEETING.	78
SECTION 13.12	VOTING AND OTHER RIGHTS.	79
ARTICLE XIV MERGER		79
SECTION 14.1	AUTHORITY.	79
SECTION 14.2	PROCEDURE FOR MERGER OR CONSOLIDATION.	80
SECTION 14.3	APPROVAL BY LIMITED PARTNERS OF MERGER OR CONSOLIDATION.	81
SECTION 14.4	CERTIFICATE OF MERGER.	81
SECTION 14.5	EFFECT OF MERGER.	81
ARTICLE XV RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS		82
SECTION 15.1	RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS.	82
ARTICLE XVI GENERAL PROVISIONS		84
SECTION 16.1	ADDRESSES AND NOTICES.	84
SECTION 16.2	FURTHER ACTION.	84
SECTION 16.3	BINDING EFFECT.	85
SECTION 16.4	INTEGRATION.	85
SECTION 16.5	CREDITORS.	85
SECTION 16.6	WAIVER.	85
SECTION 16.7	COUNTERPARTS.	85
SECTION 16.8	APPLICABLE LAW.	85
SECTION 16.9	INVALIDITY OF PROVISIONS.	85
SECTION 16.10	CONSENT OF PARTNERS.	85

iv

EXHIBIT A –	CERTIFICATE EVIDENCING COMMON UNITS REPRESENTING LIMITED PARTNER INTERESTS IN TC PIPELINES, LP	A-1
EXHIBIT B –	CLASS B UNIT SUPPLEMENT	B-1

v

FOURTH AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

TC PIPELINES, LP

THIS FOURTH AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF TC PIPELINES, LP dated as of December 31, 2018, is entered into by and among TC PipeLines GP, Inc., a Delaware corporation, as the General Partner, and other Persons who are or who become Partners in the Partnership or parties hereto as provided herein.  In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

RECITALS

WHEREAS, TC PipeLines GP, Inc., as the general partner of the Partnership, and TransCan Northern Ltd., as the organizational limited partner, organized the Partnership as a Delaware limited partnership pursuant to the Delaware Act by filing a certificate of limited partnership of the Partnership with the Secretary of State of the State of Delaware.

WHEREAS, the General Partner, TransCan Northern Ltd. and certain other parties as limited partners entered into that certain Amended and Restated Agreement of Limited Partnership of the Partnership dated as of May 28, 1999, as amended (the “ORIGINAL AGREEMENT”  providing for the operation of the Partnership upon the terms and conditions set forth therein.  The Original Agreement was subsequently amended as of November 14, 2007.  The Original Agreement was then amended and restated as of July 1, 2009 (the “SECOND RESTATED AGREEMENT”).  The Second Restated Agreement was then amended and restated as of April 1, 2015, which was amended on December 13, 2017  (as so amended, the “THIRD RESTATED AGREEMENT”).

WHEREAS, as of the date hereof, the General Partner is transferring its 100% membership interest in TC PipeLines Intermediate GP, LLC, which owns 1.0101% general partnership interest in TC GL Intermediate Limited Partnership, a Delaware limited partnership, TC PipeLines Intermediate Limited Partnership, a Delaware limited partnership and TC Tuscarora Intermediate Limited Partnership, a Delaware limited partnership (collectively, the “INTERMEDIATE PARTNERSHIPS”), to the Partnership in exchange for the issuance of a 1.0% general partner interest in the Partnership, and thereby the Intermediate Partnerships will become wholly-owned subsidiaries of the Partnership;

WHEREAS, pursuant to Section 13.1(d) of the Third Restated Agreement, the General Partner has the authority to adopt amendments to the Third Restated Agreement that, in the discretion of the General Partner, do not adversely affect the Limited Partners in any material respect without the approval of any Limited Partner or Assignee.

WHEREAS, the General Partner is adopting this Agreement pursuant to Section 13.1(d) of the Third Restated Agreement to remove references to the Intermediate Partnerships to reflect the contribution described above and to make certain associated changes and corrections.

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NOW, THEREFORE, in consideration of the covenants and agreements made herein, the Second Restated Agreement is hereby amended and restated in its entirety as follows:

ARTICLE I

DEFINITIONS

SECTION 1.1      DEFINITIONS.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“ACQUISITION”  means (a) any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or substantially all of the assets, properties or business of another Person (or a division or line of business of such Person) for the purpose of increasing the operating capacity or revenues of the Partnership Group from the operating capacity or revenues of the Partnership Group existing immediately prior to such transaction, (b) any similar transaction entered into by a JV Entity as a result of which a Group Member becomes obligated to make a capital contribution or similar payment to such JV Entity; and (c) any similar transaction entered into by a JV Entity as a result of which a Group Member is requested, but not obligated, to make a capital contribution or similar payment to such JV Entity and such Group Member reasonably believes such capital contribution or similar payment to be necessary to protect or enhance its investment in the JV Entity.

“ADDITIONAL BOOK BASIS”  means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events.  For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(i)         Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to ally prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(ii)       If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (ii) to such Book-Down Event).

“ADDITIONAL BOOK BASIS DERIVATIVE ITEMS”  means any Book Basis Derivative Items that are computed with reference to Additional Book Basis.  To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the

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beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “EXCESS ADDITIONAL BOOK BASIS”),  the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

“ADDITIONAL LIMITED PARTNER”  means a Person admitted to the Partnership as a Limited Partner after the date of this Agreement pursuant to Section 10.4 and who is shown as such on the books and records of the Partnership.

“ADJUSTED CAPITAL ACCOUNT”  means the Capital Account maintained for each Partner as of the end of each taxable period of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all losses and deductions that, as of the end of such period, are reasonably expected to be allocated to such Partner in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (ii) the amount of all distributions that, as of the end of such period, are reasonably expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or 6.1(d)(ii)).  The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith.  The “Adjusted Capital Account” of a Partner in respect of a General Partner Interest, a Common Unit or an Incentive Distribution Right or any other specified interest in the Partnership shall be the amount which such Adjusted Capital Account would be if such General Partner Interest, Common Unit, Incentive Distribution Right or other interest in the Partnership were the only interest in the Partnership held by a Partner from and after the date on which such General Partner Interest, Common Unit, Incentive Distribution Right or other interest was first issued.

“ADJUSTED PROPERTY”  means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d)(i) or 5.5(d)(ii).

“AFFILIATE”  means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question.  As used herein, the term “CONTROL”  means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“AGGREGATE REMAINING NET POSITIVE ADJUSTMENTS”  means, as of the end of any taxable period of the Partnership, the sum of the Remaining Net Positive Adjustments of all the Partners.

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“AGREED ALLOCATION”  means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including, without limitation, a Curative Allocation (if appropriate to the context in which the term “AGREED ALLOCATION”  is used).

“AGREED VALUE”  of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the General Partner using such reasonable method of valuation as it may adopt.  The General Partner shall, in its discretion, use such method as it deems reasonable and appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“AGREEMENT”  means this Fourth Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP, as it may be amended, supplemented or restated from time to time.

“ASSIGNEE”  means a Non-citizen Assignee or a Person to whom one or more Limited Partner Interests have been transferred in a manner permitted under this Agreement and who has executed and delivered a Transfer Application as required by this Agreement, but who has not been admitted as a Substituted Limited Partner.

“ASSOCIATE”  means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“AVAILABLE CASH”  means, with respect to any Quarter ending prior to the Liquidation Date,

(a)        the stun of (i) all cash and cash equivalents of the Partnership on hand at the end of such Quarter, and (ii) all additional cash and cash equivalents of the Partnership on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter, less

(b)        the amount of any cash reserves that is necessary or appropriate in the reasonable discretion of the General Partner to (i) provide for the proper conduct of the business of the Partnership (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group or any JV Entity) subsequent to such Quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a patty or by which it is bound or its assets are subject (iii) provide funds for distributions under Section 6.4 or 6.5 in respect of any one or more of the next four Quarters or (iv) provide funds for the distribution of the Class B Distribution amount to the Class B Unitholders; provided, however, that the General Partner may

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not establish cash reserves pursuant to clause (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units with respect to such Quarter; and, provided further, that disbursements made by the Partnership or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing, “AVAILABLE CASH”  with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“BOOK BASIS DERIVATIVE ITEMS”  means any item of income, deduction, gain or loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, gain or loss with respect to an Adjusted Property).

“BOOK-DOWN EVENT”  means an event which triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“BOOK-TAX DISPARITY”  means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date.  A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“BOOK-UP EVENT”  means an event which triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“BUSINESS DAY”  means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America, the State of New York, Canada or the Province of Alberta shall not be regarded as a Business Day.

“CAPITAL ACCOUNT”  means the capital account maintained for a Partner pursuant to Section 5.5.  The “CAPITAL ACCOUNT”  of a Partner in respect of a General Partner Interest, a Common Unit, a Class B Unit, an Incentive Distribution Right or any other Partnership Interest shall be the amount which such Capital Account would be if such General Partner Interest, Common Unit, Incentive Distribution Right or other Partnership Interest were the only interest in the Partnership held by a Partner from and after the date on which such General Partner Interest, Common Unit, Class B Unit, Incentive Distribution Right or other Partnership Interest was first issued.

“CAPITAL CONTRIBUTION”  means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership.

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“CAPITAL IMPROVEMENT”  means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition of existing, or the construction of new, capital assets (including, without limitation, pipeline systems, terminalling and storage facilities and related assets), in each case made to increase the operating capacity or revenues of the Partnership Group from the operating capacity or revenues of the Partnership Group existing immediately prior to such addition, improvement, acquisition or construction, (c) any similar addition, improvement, acquisition or construction by a JV Entity as a result of which a Group Member becomes obligated to make a capital contribution or similar payment to such JV Entity; and (d) any similar addition, improvement, acquisition or construction by a JV Entity as a result of which a Group Member is requested, but not obligated, to make a capital contribution or similar payment to such JV Entity and such Group Member reasonably believes such capital contribution or similar payment to be necessary to protect or enhance its investment in the JV Entity.

“CAPITAL SURPLUS”  has the meaning assigned to such term in Section 6.3(a).

“CARRYING VALUE”  means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination.  The Carrying Value of any property shall be adjusted from time to time in accordance with Sections 5.5(d)(i) and 5.5(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“CAUSE”  means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as general partner of the Partnership.

“CERTIFICATE”  means a certificate or a record from an uncertificated electronic registration system (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the General Partner in its discretion, such as a record evidencing ownership of one or more Common Units or a certificate, in such form as may be adopted by the General Partner in its discretion, evidencing ownership of one or more other Partnership Securities.

“CERTIFICATE OF LIMITED PARTNERSHIP”  means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 2.1, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“CITIZENSHIP CERTIFICATION”  means a properly completed certificate in such form as may be specified by the General Partner by which an Assignee or a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen.

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“CLAIM”  has the meaning assigned to such term in Section 7.12(c).

“CLASS B DISTRIBUTION”  has the meaning assigned to such term in the Class B Unit Supplement.

“CLASS B UNIT”  means a Unit having the rights and obligations set forth in the Class B Unit Supplement.

“CLASS B UNIT SUPPLEMENT”  means the Supplement relating to the Class B Units attached hereto as Exhibit B.

“CLASS B UNITHOLDER”  means the holders of Class B Units.

“CLOSING DATE”  means the first date on which Common Units were sold by the Partnership to the underwriters in the Initial Offering.

“CLOSING PRICE”  has the meaning assigned to such term in Section 15.1(a).

“CODE”  means the Internal Revenue Code of 1986, as amended and in effect from time to time.  Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of successor law.

“COMBINED INTEREST”  has the meaning assigned to such term in Section 11.3(a).

“COMMISSION”  means the United States Securities and Exchange Commission.

“COMMON UNIT”  means a Unit representing a fractional part of the Partnership Interests of all Limited Partners and Assignees (other than holders of Incentive Distribution Rights and Class B Units) and having the rights and obligations specified with respect to Common Units in this Agreement.

“COMMON UNITHOLDERS”  means the holders of Common Units.

“CONFLICTS COMMITTEE”  means a committee of the Board of Directors of the General Partner composed entirely of two or more directors who are neither security holders, officers nor employees of the General Partner nor officers or employees of any Affiliate of the General Partner.

“CONTRIBUTED PROPERTY”  means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership.  Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“CURATIVE ALLOCATION”  means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

“CURRENT MARKET PRICE”  has the meaning assigned to such term in Section 15.1(a).

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“DELAWARE ACT”  means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Sections 17-01, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“DEPARTING PARTNER”  means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or 11.2.

“DEPOSITARY”  means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

“DISPOSED OF ADJUSTED PROPERTY”  has the meaning assigned to such term in Section 6.1(d)(xii)(B).

“ECONOMIC RISK OF LOSS”  has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“ELIGIBLE CITIZEN”  means a Person qualified to own interests in real property in jurisdictions in which any Group Member or JV Entity does business or proposes to do business from time to time, and whose status as a Limited Partner or Assignee does not or would not subject such Group Member or JV Entity to a significant risk of cancellation or forfeiture of any of its properties or any interest therein.

“EVENT OF WITHDRAWAL”  has the meaning assigned to such term in Section 11.1(a).

“EXCHANGE AGREEMENT”  has the meaning assigned to such term in the Recitals.

“FIRST TARGET DISTRIBUTION”  means $0.81 per Unit per Quarter, subject to adjustment in accordance with Sections 6.6 and 6.9.

“FOREIGN AFFILIATE”  has the meaning assigned to such term in Section 6.2(i).

“FOREIGN AFFILIATE DIVIDEND”  has the meaning assigned to such term in Section 6.2(i).

“GENERAL PARTNER”  means TC PipeLines GP, Inc., a Delaware corporation, and its successors and permitted assigns as general partner of the Partnership.

“GENERAL PARTNER INTEREST”  means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

“GROUP”  means a Person that with or through any of its Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons) or disposing of any Partnership Securities with

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any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Securities.

“GROUP MEMBER”  means a member of the Partnership Group.

“GTN”  has the meaning assigned to such term in the Recitals.

“GTN INTEREST”  has the meaning assigned to such term in the Recitals.

“HOLDER”  as used in Section 7.12, has the meaning assigned to such term in Section 7.12(a).

“INCENTIVE DISTRIBUTION RIGHT”  means a non-voting Limited Partner Interest initially held by the General Partner, which Partnership Interest will confer upon the holder thereof only the rights and obligations specifically provided in this Agreement with respect to Incentive Distribution Rights (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest).  Notwithstanding anything in this Agreement to the contrary, the holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter except as may otherwise be required by law.

“INCENTIVE DISTRIBUTIONS”  means any amount of cash distributed to the holders of the Incentive Distribution Rights pursuant to Sections 6.4(b) and 6.4(c).

“INDEMNIFIED PERSONS”  has the meaning assigned to such term in Section 7.12(c).

“INDEMNITEE”  means (a) the General Partner, (b) any Departing Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing Partner, (d) any Person who is or was a member, partner, officer, director, employee, agent or trustee of any Group Member, the General Partner or any Departing Partner or any Affiliate of any Group Member, the General Partner or any Departing Partner, and (e) any Person who is or was serving at the request of the General Partner or any Departing Partner or any Affiliate of the General Partner or any Departing Partner as an officer, director, employee, member, partner, agent or trustee of another Person; provided, that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services.

“INITIAL OFFERING”  means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

“INITIAL UNIT PRICE”  means (a) with respect to the Common Units, the initial public offering price per Common Unit at which the underwriters offered the Common Units to the public for sale in the Initial Offering as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

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“INTERIM CAPITAL TRANSACTIONS”  means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than Working Capital Borrowings and other than for items purchased on open account in the ordinary course of business) by any Group Member or JV Entity; (b) sales of equity interests by any Group Member or JV Entity (other than the Common Units sold to the Underwriters pursuant to the exercise of their over-allotment option); and (c) sales, exchanges or other voluntary or involuntary dispositions of any assets of any Group Member or JV Entity other than (i) sales, exchanges or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales, exchanges or other dispositions of assets as part of normal retirements or replacements.

“INTERMEDIATE PARTNERSHIPS”  ” has the meaning assigned to such term in the Recitals.

“ITA”  has the meaning assigned to such term in Section 6.2(i).

“JV ENTITY”  means a Person other than an individual in which a Group Member holds an interest but which does not constitute a Subsidiary, including, without limitation, Northern Border PipeLine.

“LIMITED PARTNER”  means, unless the context otherwise requires, (a) each limited partner as of the date of this Agreement, each Substituted Limited Partner, each Additional Limited Partner and any Partner upon the change of its status front General Partner to Limited Partner pursuant to Section 11.3 or (b) solely for purposes of Articles V,  VI,  VII and IX and Sections 12.3 and 12.4, each Assignee; provided, however, that when the term “LIMITED PARTNER”  is used herein in the context of any vote or other approval, including without limitation Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right except as may otherwise be required by law.

“LIMITED PARTNER INTEREST”  means the ownership interest of a Limited Partner or Assignee in the Partnership, which may be evidenced by Common Units, Class B Units, Incentive Distribution Rights or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner or Assignee is entitled as provided in this Agreement, together with all obligations of such Limited Partner or Assignee to comply with the terms and provisions of this Agreement; provided, however, that when the term “LIMITED PARTNER INTEREST”  is used herein in the context of any vote or other approval, including without limitation Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right except as may otherwise be required by law.

“LIQUIDATION DATE”  means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to reconstitute the Partnership and continue its business has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

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“LIQUIDATOR”  means one or more Persons selected by the General Partner to perform the functions described in Section 12.3 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“MERGER AGREEMENT”  has the meaning assigned to such term in Section 14.1.

“MINIMUM QUARTERLY DISTRIBUTION”  means $0.45 per Common Unit per Quarter, subject to adjustment in accordance with Sections 6.6 and 6.9.

“NATIONAL SECURITIES EXCHANGE”  means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor to such statute, or the Nasdaq Stock Market or any successor thereto.

“NET AGREED VALUE”  means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Partner or Assignee by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any liabilities either assumed by such Partner or Assignee upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.

“NET INCOME”  means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period.  The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

“NET LOSS”  means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period.  The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

“NET POSITIVE ADJUSTMENTS”  means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

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“NET TERMINATION GAIN”  means, for any taxable period, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Partnership (a) after the Liquidation Date, or (b) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or series of related transactions (excluding any disposition to a member of the Partnership Group).  The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain, loss or deduction specially allocated under Section 6.1(d).

“NET TERMINATION LOSS”  means, for any taxable period, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Partnership (a) after the Liquidation Date, or (b) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or series of related transactions (excluding any disposition to a member of the Partnership Group).  The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain, loss or deduction specially allocated under Section 6.1(d).

“NON-CITIZEN ASSIGNEE”  means a Person whom the General Partner has determined in its discretion does not constitute an Eligible Citizen and as to whose Partnership Interest the General Partner has become the Substituted Limited Partner, pursuant to Section 4.9.

“NONRECOURSE BUILT-IN GAIN”  means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage, pledge or other lien securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Sections 6.2(b)(i)(A),  6.2(b)(ii)(A) and 6.2(b)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“NONRECOURSE DEDUCTIONS”  means any and all items of loss, deduction or expenditures (including, without limitation, any expenditures described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“NONRECOURSE LIABILITY”  has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“NORTHERN BORDER PIPELINE”  means Northern Border PipeLine Company, a Texas general partnership.

“NOTICE OF ELECTION TO PURCHASE”  has the meaning assigned to such term in Section 15.1(b).

“OPERATING EXPENDITURES”  means all Partnership expenditures, including, but not limited to, operating expenses, taxes, reimbursements of the General Partner, debt service payments, and capital expenditures, subject to the following:

(a)        Payments (including prepayments) of principal of and premium on indebtedness shall not be an Operating Expenditure if the payment is (i) required in connection with the sale or

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other disposition of assets or made in connection with the refinancing or refunding of indebtedness with the proceeds from new indebtedness or from the sale of equity interests.  For purposes of the foregoing, at the election and in the reasonable discretion of the General Partner, any payment of principal or premium shall be deemed to be refunded or refinanced by any indebtedness incurred or to be incurred by the Partnership within 180 days before or after such payment to the extent of the principal amount of such indebtedness.

(b)        Operating Expenditures shall not include (i) capital expenditures made for Acquisitions or for Capital Improvements, (ii) payment of transaction expenses relating to Interim Capital Transactions or (iii) distributions to Partners.  Where capital expenditures are made in part for Acquisitions or for Capital Improvements and in part for other purposes, the General Partner’s good faith allocation between the amounts paid for each shall be conclusive.

“OPERATING SURPLUS”  means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

(a)        the sum of (i) $20 million plus all cash and cash equivalents of the Partnership on hand as of the close of business on the Closing Date, (ii) all cash receipts of the Partnership for the period beginning on the Closing Date and ending with the last day of such period, other than cash receipts from Interim Capital Transactions (except to the extent specified in Section 6.5) and (iii) all cash receipts of the Partnership after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings, less

(b)        the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending with the last day of such period and (ii) the amount of cash reserves that is necessary or advisable in the reasonable discretion of the General Partner to provide funds for future Operating Expenditures; provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines, and less

(c)        the cumulative amount of all Class B Distribution amounts accrued in respect of the Class B Units for the entire period they have been outstanding, as determined in accordance with the Class B Unit Supplement (but treating any reductions in “Available Cash” under subsection (b)(iv) of the definition of such term for any Quarter, as determined by the General Partner, as a Class B Distribution amount accrued for such Quarter).

Notwithstanding the foregoing, “OPERATING SURPLUS”  with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“OPINION OF COUNSEL”  means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner in its reasonable discretion.

“ORIGINAL AGREEMENT”  has the meaning assigned to such term in the Recitals.

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“OUTSTANDING”  means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of any Outstanding Partnership Securities of any class then Outstanding, all Partnership Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Common Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Common Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement); provided, further, that the foregoing limitation shall not apply (i) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates or (ii) to any Person or Group who acquired 20% or more of any Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply.

“PARTNER NONRECOURSE DEBT”  has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

“PARTNER NONRECOURSE DEBT MINIMUM GAIN”  has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

“PARTNER NONRECOURSE DEDUCTIONS”  means any and all items of loss, deduction or expenditure (including, without limitation, any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

“PARTNERS”  means the General Partner and the Limited Partners.

“PARTNERSHIP”  means TC PipeLines, LP, a Delaware limited partnership, and any successors thereto.

“PARTNERSHIP GROUP”  means the Partnership and any Subsidiary of the Partnership, treated as a single consolidated entity.

“PARTNERSHIP INTEREST”  means an interest in the Partnership, which shall include the General Partner Interest and Limited Partner Interests.

“PARTNERSHIP MINIMUM GAIN”  means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

“PARTNERSHIP SECURITY”  means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership), including without limitation, Common Units, Class B Units and Incentive Distribution Rights.

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“PERCENTAGE INTEREST”  means as of any date of determination (a) as to the General Partner (with respect to its General Partner Interest), an aggregate 2%, (b) as to any Common Unitholder or Assignee of Common Units, the product obtained by multiplying (i) 98% less the percentage, if any, applicable to paragraph (c) by (ii) the quotient obtained by dividing (A) the number of Common Units held by such Common Unitholder or Assignee by (B) the total number of all Outstanding Common Units, and (c) as to the holders of additional Partnership Securities issued by the Partnership in accordance with Section 5.6, the percentage, if any, established as a part of such issuance.  The Percentage Interest with respect to an Incentive Distribution Right and the Class B Units shall at all times be zero.

“PERSON”  means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“PER UNIT CAPITAL AMOUNT”  means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

“PRO RATA”  means (a) when used in reference to the Common Unitholders or their Assignees, apportioned equally among the Common Unitholders and their Assignees in accordance with their relative Percentage Interests, (b) when used in reference to the Class B Unitholders or any other class or series of Units (or their Assignees), as prescribed in the applicable Supplement in respect of such Units and (c) when used in reference to the holders of Incentive Distribution Rights, apportioned equally among all holders of Incentive Distribution Rights in accordance with the relative number of Incentive Distribution Rights held by each such holder.

“PURCHASE DATE”  means the date determined by the General Partner as the date for purchase of all Outstanding Units of a certain class (other than Units held by the General Partner and its Affiliates) pursuant to Article XV.

“QUARTER”  means, unless the context requires otherwise, a fiscal quarter of the Partnership.

“RECAPTURE INCOME”  means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“RECORD DATE”  means the date established by the General Partner for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

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“RECORD HOLDER”  means the Person in whose name a Common Unit or a Class B Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Partnership Securities, the Person in whose name any such other Partnership Security is registered on the books which the General Partner has caused to be kept as of the opening of business on such Business Day.

“REDEEMABLE INTERESTS”  means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.

“REGISTRATION STATEMENT”  means the Registration Statement on Form S-1 (Registration No. 333 69947) as amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

“REMAINING NET POSITIVE ADJUSTMENTS”  means as of the end of any taxable period, (i) with respect to the Common Unitholders in respect of their Common Units, the excess of (a) the Net Positive Adjustments of the Common Unitholders in respect of their Common Units as of the end of such period over (b) the sum of those Common Unitholders’ Share of Additional Book Basis Derivative Items in respect of their Common Units for each prior taxable period, (ii) with respect to the General Partner (as holder of the General Partner Interest), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Interest for each prior taxable period, and (i) with respect to the holders of Incentive Distribution Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

“REQUIRED ALLOCATIONS”  means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) or 6.1(c)(ii) and (b) any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(d)(i),  6.1(d)(ii),  6.1(d)(iv),  6.1(d)(vii) or 6.1(d)(ix).

“RESIDUAL GAIN”  or “RESIDUAL LOSS”  means any item of gain or loss, as the case may be, of the Partnership recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss is not allocated pursuant to Section 6.2(b)(i)(A) or 6.2(b)(ii)(A), respectively, to eliminate Book-Tax Disparities.

“SECOND RESTATED AGREEMENT”  has the meaning assigned to such term in the Recitals.

“SECOND TARGET DISTRIBUTION”  means $0.88 per Unit per Quarter, subject to adjustment in accordance with Sections 6.6 and 6.9.

“SECURITIES ACT”  means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

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“SHARE OF ADDITIONAL BOOK BASIS DERIVATIVE ITEMS”  means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Common Unitholders in respect of their Common Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Common Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (as holder of the General Partner Interest), the amount that bears the same ratio to such additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

“SPECIAL APPROVAL”  means approval by a majority of the members of the Conflicts Committee.

“SUBSIDIARY”  means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.  The foregoing definition shall not include any JV Entity, including, without limitation, Northern Border PipeLine.

“SUBSTITUTED LIMITED PARTNER”  means a Person who is admitted as a Limited Partner to the Partnership pursuant to Section 10.2 in place of and with all the rights of a Limited Partner and who is shown as a Limited Partner on the books and records of the Partnership.

“SUPPLEMENT”  means each Supplement designated as a “Class Unit Supplement” or “Series Supplement” from time to time by the General Partner which sets forth the rights and obligations with respect to a particular class or series of Units or other Partnership Securities.

“SURVIVING BUSINESS ENTITY”  has the meaning assigned to such term in Section 14.2(b).

“THIRD RESTATED AGREEMENT” has the meaning assigned to such term in the Recitals.

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“TRADING DAY”  has the meaning assigned to such term in Section 15.1(a).

“TRANSACTION AGREEMENTS”  means the Agreement for Purchase and Sale of Membership Interest by and between Gas Transmission Northwest Corporation and TC PipeLines Intermediate Limited Partnership dated as of May 19, 2009, the Common Unit Purchase Agreement by and between TransCan Northern Ltd. and the Partnership dated as of July 1, 2009, the Exchange Agreement, the Yuma Transfer Agreement by and between Gas Transmission Northwest Corporation and North Baja Pipeline, LLC and the PSA (as defined in the Class B Unit Supplement).

“TRANSFER”  has the meaning assigned to such term in Section 4.4(a).

“TRANSFER AGENT”  means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the Partnership to act as registrar and transfer agent for the Common Units; provided that if no Transfer Agent is specifically designated for any other Partnership Securities, the General Partner shall act in such capacity.

“TRANSFER APPLICATION”  means an application and agreement for transfer of Units in the form set forth on the back of a Certificate or in a form substantially to the same effect in a separate instrument.

“TREASURY REGULATIONS”  means the permanent, temporary or proposed regulations of the United States Department of the Treasury promulgated under the Code, as such regulations may be amended and in effect from time to time.  Any reference herein to a specific section or sections of the Treasury Regulations shall be deemed to include a reference to any corresponding provision of successor law.

“UNIT”  means a Partnership Security that is designated as a “UNIT” and shall include Common Units, Class B Units and any other class or series of Partnership Securities so issued and designated in the future, but shall not include (i) a General Partner Interest or (ii) Incentive Distribution Rights.

“UNIT MAJORITY”  means at least a majority of the Outstanding Common Units.

“UNITHOLDERS”  means the holders of Common Units and Class B Units and any other Units issued by the Partnership hereafter.

“UNPAID FTD”  has the meaning assigned to such term in Section 6.1(c)(i)(B).

“UNREALIZED GAIN”  attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

“UNREALIZED LOSS”  attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such

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date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

“UNRECOVERED CAPITAL”  means at any time, with respect to a Common Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of a Common Unit sold in the Initial Offering and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of a Common Unit sold in the Initial Offering, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

“U.S. GAAP”  means United States Generally Accepted Accounting Principles consistently applied.

“WITHDRAWAL OPINION OF COUNSEL”  has the meaning assigned to such term in Section 11.1(b).

“WORKING CAPITAL BORROWINGS”  means borrowings exclusively for working capital purposes.  Amounts drawn from a credit facility to enable the Partnership to pay distributions to partners of the Partnership if there has been a temporary interruption or delay in receipt of distributions from Northern Border PipeLine shall also constitute Working Capital Borrowings.

SECTION 1.2      CONSTRUCTION.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; and (c) the term “INCLUDE”  or “INCLUDES”  means includes, without limitation, and “INCLUDING”  means including, without limitation.

ARTICLE II

ORGANIZATION

SECTION 2.1      FORMATION.

The Partnership has been operated as a limited partnership pursuant to the provisions of the Delaware Act pursuant to the Original Agreement.  The General Partner hereby amends and restates the Original Agreement in its entirety.  This amendment and restatement shall become effective on the date of this Agreement.  The Original Agreement shall be controlling for matters prior to the effective date of this Agreement.  Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act.  All Partnership Interests shall constitute personal property of the owner thereof for all purposes and a Partner has no interest in specific Partnership property.

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SECTION 2.2      NAME.

The name of the Partnership is “TC PipeLines, LP” The Partnership’s business may be conducted under any other name or names deemed necessary or appropriate by the General Partner in its sole discretion, including the name of the General Partner.  The words “Limited Partnership,” “L.P.,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires.  The General Partner in its discretion may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

SECTION 2.3      REGISTERED OFFICE; REGISTERED AGENT; PRINCIPAL OFFICE; OTHER OFFICES.

Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at Corporation Trust Center, 1209 Orange Street, Wilmington, DE 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company, Corporation Trust Center, 1209 Orange Street, Wilmington, DE 19801.  The principal office of the Partnership shall be located at 700 Louisiana Street, Suite 700, Houston, TX 77002 or such other place as the General Partner may from time to time designate by notice to the Limited Partners.  The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner deems necessary or appropriate.  The address of the General Partner shall be 700 Louisiana Street, Suite 700, Houston, TX 77002 or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

SECTION 2.4      PURPOSE AND BUSINESS.

The purpose and nature of the business to be conducted by the Partnership shall be to (a)  engage directly in, or enter into or form any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner and which lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity; provided, however, that the General Partner reasonably determines, as of the date of the acquisition or commencement of such activity, that such activity (i) generates “QUALIFYING INCOME” (as such term is defined pursuant to Section 7704 of the Code) or (ii) enhances the operations of a Partnership activity that generates qualifying income, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member or JV Entity.  The General Partner has no obligation or duty to the Partnership, the Limited Partners or the Assignees to propose or approve, and in its discretion may decline to propose or approve, the conduct by the Partnership of any business.

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SECTION 2.5      POWERS.

The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4.

SECTION 2.6      POWER OF ATTORNEY.

(a)        Each Limited Partner and each Assignee hereby constitutes and appoints the General Partner and, if a Liquidator shall have been selected pursuant to Section 12.3, the Liquidator, (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with MI power of substitution, as his true and lawful agent and attorney-in-fact, with fill power and authority in his name, place and stead, to:

(i)         execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (A) all certificates, documents and other instruments (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof) that the General Partner or the Liquidator deems necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property; (B) all certificates, documents and other instruments that the General Partner or the Liquidator deems necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the General Partner or the Liquidator deems necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement; (D) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV,  X,  XI or XII;  (E) all certificates, documents and other instruments relating to the determination of the preferences, rights, powers, privileges and duties of any class or series of Partnership Securities issued pursuant to Section 5.6; and (F) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger or consolidation of the Partnership pursuant to Article XIV; and

(ii)       execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments necessary or appropriate, in the discretion of the General Partner or the Liquidator, to make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or is necessary or appropriate, in the discretion of the General Partner or the Liquidator, to effectuate the terms or intent of this Agreement; provided, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.6(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.

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Nothing contained in this Section 2.6(a) shall be construed as authorizing the General Partner to amend this Agreement except in accordance with Article XIII or as may be otherwise expressly provided for in this Agreement.

(b)        The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Limited Partner or Assignee and the transfer of all or any portion of such Limited Partner’s or Assignee’s Partnership Interest and shall extend to such Limited Partner’s or Assignee’s heirs, successors, assigns and personal representatives.  Each such Limited Partner or Assignee hereby agrees to be bound by any representation made by the General Partner or the Liquidator acting in good faith pursuant to such power of attorney; and each such Limited Partner or Assignee, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the General Partner or the Liquidator taken in good faith under such power of attorney.  Each Limited Partner or Assignee shall execute and deliver to the General Partner or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as the General Partner or the Liquidator deems necessary to effectuate this Agreement and the purposes of the Partnership.

SECTION 2.7      TERM.

The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the close of Partnership business on December 31, 2097 or until the earlier dissolution of the Partnership in accordance with the provisions of Article XII.  The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

SECTION 2.8      TITLE TO PARTNERSHIP ASSETS.

Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner or Assignee, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof.  Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine.  The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use

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of such assets in a manner satisfactory to the General Partner.  All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

ARTICLE III

RIGHTS OF LIMITED PARTNERS

SECTION 3.1      LIMITATION OF LIABILITY.

The Limited Partners and the Assignees shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

SECTION 3.2      MANAGEMENT OF BUSINESS.

No Limited Partner or Assignee, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership.  Any action taken by any Affiliate of the General Partner or any officer, director, employee, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participation in the control of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners or Assignees under this Agreement.

SECTION 3.3      OUTSIDE ACTIVITIES OF THE LIMITED PARTNERS.

Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners or Assignees, any Limited Partner or Assignee shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with any Group Member or IV Entity.  Neither the Partnership nor any of the other Partners or Assignees shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner or Assignee.

SECTION 3.4      RIGHTS OF LIMITED PARTNERS.

(a)       In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a limited partner in the Partnership, upon reasonable written demand and at such Limited Partner’s own expense:

(i)         to obtain true and full information regarding the status of the business and financial condition of the Partnership;

(ii)       promptly after becoming available, to obtain a copy of the Partnership’s federal, state and local income tax returns for each year;

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(iii)      to have furnished to him a current list of the name and last known business, residence or mailing address of each Partner;

(iv)       to have furnished to him a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with a copy of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;

(v)        to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and which each Partner has agreed to contribute in the future, and the date on which each became a Partner; and

(vi)       to obtain such other information regarding the affairs of the Partnership as is just and reasonable.

(b)        The General Partner may keep confidential from the Limited Partners and Assignees, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of any Group Member or JV Entity, (B) could damage any Group Member or JV Entity or (C) that any Group Member or JV Entity is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section).

ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS;
REDEMPTION OF PARTNERSHIP INTERESTS

SECTION 4.1      CERTIFICATES.

Upon the Partnership’s issuance of Common Units to any Person, the Partnership shall issue one or more Certificates in the name of such Person evidencing the number of such Units being so issued.  In addition, (a) upon the General Partner’s request, the Partnership shall issue to it one or more Certificates in the name of the General Partner evidencing its interests in the Partnership and (b) upon the request of any Person holding Incentive Distribution Rights or any other Partnership Securities other than Common Units, the Partnership shall issue to such Person one or more certificates evidencing such Incentive Distribution Rights or other Partnership Securities other than Common Units.  Certificates shall be executed on behalf of the Partnership by the Chairman, President or any Executive Vice President or Vice President and the Secretary or any Assistant Secretary of the General Partner.  No Common Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the General Partner elects to issue Common Units in global form, the Common Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Common Units have been duly registered in accordance with the directions of the Partnership.  Notwithstanding anything in this Section 4.1 or any other provision of this Agreement, at the General Partner’s discretion, Partnership Securities may be issued, recorded and transferred by

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electronic or other means not involving the issuance of physical Certificates.  The provisions of this Agreement shall be interpreted as reasonably required to implement such a system.  For example, no signature shall be required with respect to an uncertificated electronic registration system.

SECTION 4.2      MUTILATED, DESTROYED, LOST OR STOLEN CERTIFICATES.

(a)        If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Securities as the Certificate so surrendered.

(b)        The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i)         makes proof by affidavit, in form and substance satisfactory to the Partnership, that a previously issued Certificate has been lost, destroyed or stolen;

(ii)       requests the issuance of a new Certificate before the Partnership has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii)      if requested by the Partnership, delivers to the Partnership a bond, in form and substance satisfactory to the Partnership, with surety or sureties and with fixed or open penalty as the Partnership may reasonably direct, in its sole discretion, to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv)       satisfies any other reasonable requirements imposed by the Partnership.

If a Limited Partner or Assignee fails to notify the Partnership within a reasonable time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner or Assignee shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

(c)        As a condition to the issuance of any new Certificate under this Section 4.2, the Partnership may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

SECTION 4.3      RECORD HOLDERS.

The Partnership shall be entitled to recognize the Record Holder as the Partner or Assignee with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such Partnership Interest on the part of

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any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed for trading.  Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person (a) shall be the Partner or Assignee (as the case may be) of record and beneficially, (b) must execute and deliver a Transfer Application and (c) shall be bound by this Agreement and shall have the rights and obligations of a Partner or Assignee (as the case may be) hereunder and as, and to the extent, provided for herein.

SECTION 4.4      TRANSFER GENERALLY.

(a)        The term “TRANSFER,”  when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction by which the General Partner assigns its General Partner Interest to another Person who becomes the General Partner, by which the holder of a Limited Partner Interest assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner or an Assignee, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise.

(b)        No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV.  Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void.

(c)        Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder of the General Partner of any or all of the issued and outstanding stock of the General Partner.

SECTION 4.5      REGISTRATION AND TRANSFER OF LIMITED PARTNER INTERESTS.

(a)        The Partnership shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests.  The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided.  The Partnership shall not recognize transfers of Certificates evidencing Limited Partner Interests unless such transfers are effected in the manner described in this Section 4.5.  Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Common Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s

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instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(b)        Except as otherwise provided in Section 4.9, the Partnership shall not recognize any transfer of Limited Partner Interests until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer and such Certificates are accompanied by a Transfer Application duly executed by the transferee (or the transferee’s attorney-in-fact duly authorized in writing).  No charge shall be imposed by the Partnership for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the Partnership may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.

(c)        Limited Partner Interests may be transferred only in the manner described in this Section 4.5.  The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.

(d)        Until admitted as a Substituted Limited Partner pursuant to Section 10.2, the Record Holder of a Limited Partner Interest shall be an Assignee in respect of such Limited Partner Interest.  Limited Partners may include custodians, nominees or any other individual or entity in its own or any representative capacity.

(e)        A transferee of a Limited Partner Interest who has completed and delivered a Transfer Application shall be deemed to have (i) requested admission as a Substituted Limited Partner, (ii) agreed to comply with and be bound by and to have executed this Agreement, (iii) represented and warranted that such transferee has the right, power and authority and, if an individual, the capacity to enter into this Agreement, (iv) granted the powers of attorney set forth in this Agreement and (v) given the consents and approvals and made the waivers contained in this Agreement.

(f)        The General Partner and its Affiliates shall have the right at any time to transfer their Common Units to one or more Persons.

SECTION 4.6      TRANSFER OF THE GENERAL PARTNER’S GENERAL PARTNER INTEREST.

(a)        [INTENTIONALLY OMITTED.]

(b)        Subject to Section 4.6(c) below, the General Partner may transfer all or any of its General Partner Interest without Unitholder approval.

(c)        Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion

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thereof, if applicable) of the interest of the General Partner as the general partner or managing member of each other Group Member.  In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.3, be admitted to the Partnership as a General Partner immediately prior to the transfer of the Partnership Interest, and the business of the Partnership shall continue without dissolution.

SECTION 4.7      TRANSFER OF INCENTIVE DISTRIBUTION RIGHTS.

The General Partner or any other holder of Incentive Distribution Rights may transfer any or all of its Incentive Distribution Rights without Unitholder approval.  Notwithstanding anything herein to the contrary, no transfer of Incentive Distribution Rights to another Person shall be permitted unless the transferee agrees to be bound by the provisions of this Agreement.  The General Partner shall have the authority (but shall not be required) to adopt such reasonable restrictions on the transfer of Incentive Distribution Rights and requirements for registering the transfer of Incentive Distribution Rights as the General Partner, in its sole discretion, shall determine are necessary or appropriate.

SECTION 4.8      RESTRICTIONS ON TRANSFERS.

(a)        Notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b)        The General Partner may impose restrictions on the transfer of Partnership Interests if it determines based upon a subsequent Opinion of Counsel that such restrictions are necessary to avoid a significant risk of the Partnership being treated as an association taxable as a corporation or otherwise being taxed as an entity for federal income tax purposes.  The restrictions may be imposed by making such amendments to this Agreement as the General Partner may determine to be necessary or appropriate to impose such restrictions; provided, however, that any amendment that the General Partner believes, in the exercise of its reasonable discretion, could result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then traded must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c)        Nothing contained in this Article IV or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed for trading.

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SECTION 4.9      CITIZENSHIP CERTIFICATES; NON-CITIZEN ASSIGNEES.

(a)        If any Group Member or JV Entity is or becomes subject to any federal, state or local law or regulation that, in the reasonable determination of the General Partner, creates a substantial risk of cancellation or forfeiture of any property in which the Group Member or JV Entity has an interest based on the nationality, citizenship or other related status of a Limited Partner or Assignee, the General Partner may request any Limited Partner or Assignee to furnish to the General Partner, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Limited Partner or Assignee is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner may request.  If a Limited Partner or Assignee fails to furnish to the General Partner within the aforementioned 30-day period such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the General Partner determines, with the advice of counsel, that a Limited Partner or Assignee is not an Eligible Citizen, the Partnership Interests owned by such Limited Partner or Assignee shall be subject to redemption in accordance with the provisions of Section 4.10.  In addition, the General Partner may require that the status of any such Partner or Assignee be changed to that of a Non-citizen Assignee and, thereupon, the General Partner shall be substituted for such Non-citizen Assignee as the Limited Partner in respect of his Limited Partner Interests.

(b)        The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Non-citizen Assignees, distribute the votes in the same ratios as the votes of Partners (including without limitation the General Partner) in respect of Limited Partner Interests other than those of Non-citizen Assignees are cast, either for, against or abstaining as to the matter.

(c)        Upon dissolution of the Partnership, a Non-citizen Assignee shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Non-citizen Assignee’s share of the distribution in kind.  Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Non-citizen Assignee of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).

(d)        At any time after he can and does certify that he has become an Eligible Citizen, a Non-citizen Assignee may, upon application to the General Partner, request admission as a Substituted Limited Partner with respect to any Limited Partner Interests of such Non-citizen Assignee not redeemed pursuant to Section 4.10, and upon his admission pursuant to Section 10.2, the General Partner shall cease to be deemed to be the Limited Partner in respect of the Non-citizen Assignee’s Limited Partner Interests.

SECTION 4.10    REDEMPTION OF PARTNERSHIP INTERESTS OF NON-CITIZEN ASSIGNEES.

(a)        If at any time a Limited Partner or Assignee fails to furnish a Citizenship Certification or other information requested within the 30-day period specified in Section 4.9(a), or if upon receipt of such Citizenship Certification or other information the General Partner

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determines, with the advice of counsel, that a Limited Partner or Assignee is not an Eligible Citizen, the Partnership may, unless the Limited Partner or Assignee establishes to the satisfaction of the General Partner that such Limited Partner or Assignee is an Eligible Citizen or has transferred his Partnership Interests to a Person who is an Eligible Citizen and who furnishes a Citizenship Certification to the General Partner prior to the date fixed for redemption as provided below, redeem the Partnership Interest of such Limited Partner or Assignee as follows:

(i)         The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner or Assignee, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid.  The notice shall be deemed to have been given when so mailed.  The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner or Assignee would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii)       The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests.  The redemption price shall be paid, in the discretion of the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 10% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii)      Upon surrender by or on behalf of the Limited Partner or Assignee, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Limited Partner or Assignee or his duly authorized representative shall be entitled to receive the payment therefor.

(iv)       After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b)        The provisions of this Section 4.10 shall also be applicable to Limited Partner Interests held by a Limited Partner or Assignee as nominee of a Person determined to be other than an Eligible Citizen.

(c)        Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement.  Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner in a Citizenship Certification delivered in connection with the Transfer Application that he is an Eligible Citizen.  If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

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ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

SECTION 5.1      [INTENTIONALLY OMITTED.]

SECTION 5.2      CONTRIBUTIONS TO THE PARTNERSHIP.

(a)        The General Partner and the Limited Partners have previously made Capital Contributions for interests in the Partnership.

(b)        Upon the subsequent issuance of any additional Limited Partner Interests by the Partnership, the General Partner shall be required to make additional Capital Contributions equal to 2/98ths of any amount contributed to the Partnership by the Limited Partners in exchange for such additional Limited Partner Interests.  Except as set forth in the immediately preceding sentence and Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

SECTION 5.3      [INTENTIONALLY OMITTED.]

SECTION 5.4      INTEREST AND WITHDRAWAL.

No interest shall be paid by the Partnership on Capital Contributions.  No Partner or Assignee shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement may be considered as such by law and then only to the extent provided for in this Agreement.  Except to the extent expressly provided in this Agreement, no Partner or Assignee shall have priority over any other Partner or Assignee either as to the return of Capital Contributions or as to profits, losses or distributions.  Any such return shall be a compromise to which all Partners and Assignees agree within the meaning of Section 17-502(b) of the Delaware Act.

SECTION 5.5      CAPITAL ACCOUNTS.

(a)        The Partnership has maintained and shall continue to maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner in its sole discretion) holding a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv).  Such Capital Account has been and shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest pursuant to this Agreement (or pursuant to the Original Agreement or the Second Restated Agreement) and (ii) all items of Partnership income and gain (including, without limitation, income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1 (or allocated pursuant to Section 6.1 of the Original Agreement or the Second Restated Agreement), and has been and shall be decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest pursuant to this Agreement (or pursuant to the Original Agreement or the Second Restated Agreement) and (y) all items of Partnership deduction and loss computed in

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accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1 (or allocated pursuant to Section 6.1 of the Original Agreement or the Second Restated Agreement).  Capital Account maintenance and adjustments prior to the effective date of this Agreement were governed by the terms of the Original Agreement and the Second Restated Agreement.

(b)        For purposes of computing the amount of any item of income, gain, loss or deduction which is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including, without limitation, any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i)         Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Subsidiary’s organizational agreements) of all property owned by any Subsidiary that is classified as a partnership for federal income tax purposes.

(ii)       All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii)      Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction shall be made without regard to any election under Section 754 of the Code which may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes.  To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv)       Any income, gain or loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

(v)        In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property.  Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined (A) as if the adjusted

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basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery or amortization derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for federal income tax purposes, depreciation, cost recovery or amortization deductions shall be determined using any reasonable method that the General Partner may elect.

(vi)       If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Partners pursuant to Section 6.1.  Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

(c)        A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(d)        (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), upon an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests in consideration for services, or upon the conversion of all or a portion of the General Partner’s Combined Interest to Common Units pursuant to Section 11.3(b), the Capital Accounts of the Partners (other than the Class B Unitholders in respect of their Class B Units) and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance and had been allocated to the Partners (other than the Class B Unitholders in respect of their Class B Units) at such time pursuant to Section 6.1(c) in the same manner as any item of gain or loss actually recognized following an event giving rise to a dissolution of the Partnership would have been allocated.  In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including, without limitation, cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such reasonable method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time.  The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines in its discretion to be reasonable) to arrive at a fair market value for individual properties.

(ii)       In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(0, immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of the Partners (other than the Class B Unitholders in respect of their Class B Units) and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of

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each such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners (other than the Class B Unitholders in respect of their Class B Units), at such time, pursuant to Section 6.1(c) in the same manner as any item of gain or loss actually recognized following an event giving rise to a dissolution of the Partnership would have been allocated.  In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such reasonable method of valuation as it may adopt.

SECTION 5.6      ISSUANCES OF ADDITIONAL PARTNERSHIP SECURITIES.

(a)        Subject to Section 5.7, the Partnership may issue additional Partnership Securities and options, rights, warrants and appreciation rights relating to the Partnership Securities for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as shall be established by the General Partner in its sole discretion, all without the approval of any Limited Partners.

(b)        Each additional Partnership Security authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers, privileges and duties (which may be senior to existing classes and series of Partnership Securities), as shall be fixed by the General Partner in the exercise of its sole discretion, including (i) the right to share Partnership profits and losses or items thereof;  (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may redeem the Partnership Security; (v) whether such Partnership Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Security will be issued, evidenced by certificates and assigned or transferred; and (vii) the right, if any, of each such Partnership Security to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Security.

(c)        The General Partner is hereby authorized and directed to take all actions that it deems necessary or appropriate (including all actions to assure the economic uniformity of the Common Units and the Class B Units) in connection with (i) each issuance of Partnership Securities and options, rights, warrants and appreciation rights relating to Partnership Securities pursuant to this Section 5.6,  (ii) the conversion of the General Partner Interest and Incentive Distribution Rights into Units pursuant to the terms of this Agreement, (iii) the admission of Additional Limited Partners and (iv) all additional issuances of Partnership Securities.  The General Partner is further authorized and directed to specify the relative preferences, rights, powers, privileges and duties of the holders of the Units or other Partnership Securities being so issued.  The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things it deems to be necessary or advisable in connection with any future issuance of Partnership Securities or in connection with the conversion of the General Partner Interest and Incentive Distribution Rights into Units pursuant to the terms of this

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Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Securities are listed for trading.

SECTION 5.7      LIMITATIONS ON ISSUANCE OF FRACTIONAL PARTNERSHIP SECURITIES.

No fractional Units shall be issued by the Partnership.

SECTION 5.8      [INTENTIONALLY OMITTED.]

SECTION 5.9      LIMITED PREEMPTIVE RIGHT.

Except as provided in this Section 5.9 and in Section 5.2(b), no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Security, whether unissued, held in the treasury or hereafter created.  The General Partner shall have the right (but not obligation), which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Securities from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Securities to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Securities.

SECTION 5.10    SPLITS AND COMBINATION.

(a)        Subject to Sections 5.10(d),  6.6 and 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Securities to all Record Holders or may effect a subdivision or combination of Partnership Securities so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis (including any Unrecovered Capital) or stated as a number of Units are proportionately adjusted.

(b)        Whenever such a distribution, subdivision or combination of Partnership Securities is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice.  The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination.  The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c)        Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates to the Record Holders of Partnership Securities as of the applicable Record Date representing the new number of Partnership Securities held by such Record Holders, or the General Partner may adopt such other procedures as it may deem appropriate to reflect such changes.  If any such combination results in a smaller total number of Partnership Securities Outstanding, the Partnership shall require, as a condition to the delivery to

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a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d)        The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units.  If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of Section 5.7 and this Section 5.10(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

SECTION 5.11    FULLY PAID AND NON-ASSESSABLE NATURE OF LIMITED PARTNER INTERESTS.

All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 of the Delaware Act.

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

SECTION 6.1      ALLOCATIONS FOR CAPITAL ACCOUNT PURPOSES.

For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section 5.5(b)) shall be allocated among the Partners in each taxable year (or portion thereof) as provided herein below.

(a)        NET INCOME.  After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable period shall be allocated as follows:

(i)         First, 100% to the General Partner in an amount equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable periods until the aggregate Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) for the current taxable period and all previous taxable periods is equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable periods;

(ii)       Second, 2% to the General Partner in an amount equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(ii) for all previous taxable periods and 98% to the Common Unitholders, in accordance with their respective Percentage Interests, until the aggregate Net Income allocated to such Partners pursuant to this Section 6.1(a)(ii) for the current taxable period and all previous taxable periods is equal to the aggregate Net Losses allocated to such Partners pursuant to Section 6.1(b)(ii) for all previous taxable periods; and

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(iii)      Third, the balance, if any, 100% to the General Partner and the Common Unitholders in accordance with their respective Percentage Interests.

(b)        NET LOSSES.  After giving effect to the special allocations set forth in Section 6.1(d), Net Losses for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Losses for such taxable period shall be allocated as follows:

(i)         First, 2% to the General Partner and 98% to the Common Unitholders, Pro Rata, until the aggregate Net Losses allocated pursuant to this Section 6.1(b)(i) for the current taxable period and all previous taxable periods is equal to the aggregate Net Income allocated to such Partners pursuant to Section 6.1(a)(iii) for all previous taxable periods, provided that the Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Common Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account);

(ii)       Second, 2% to the General Partner and 98% to the Common Unitholders, Pro Rata; provided, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(ii) to the extent that such allocation would cause any Common Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account);

(iii)      Third, the balance, if any, 100% to the General Partner.

(c)        NET TERMINATION GAINS AND LOSSES.  After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss and deduction taken into account in computing Net Termination Gain or Net Termination Loss for each taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder.  All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Sections 6.4 and 6.5 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

(i)         If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

(A)       First, to each such Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all such Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

(B)       Second, 98% to all Common Unitholders, Pro Rata, and 2% to the General Partner until the Capital Account in respect of each Common Unit then Outstanding is

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equal to the sum of (1) its Unrecovered Capital plus (2) the First Target Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “UNPAID FTD”);

(C)       Third, 85% to all Common Unitholders, Pro Rata, 13% to the holders of the Incentive Distribution Rights, Pro Rata, and 2% to the General Partner until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Capital plus (2) the Unpaid FTD, plus (3) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter after the date of this Agreement over (bb) the cumulative per Unit amount of any distributions of Operating Surplus made pursuant to Section 6.4(b) after the date of this Agreement;

(D)       Finally, any remaining amount 75% to all Common Unitholders, Pro Rata, 23% to the holders of the Incentive Distribution Rights, Pro Rata, and 2% to the General Partner.

(ii)       If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Loss shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be decreased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

(A)       First, 98% to all Common Unitholders, Pro Rata, and 2% to the General Partner until the Capital Account in respect of each Common Unit then Outstanding has been reduced to zero; and

(B)       Second, the balance, if any, 100% to the General Partner.

(d)        SPECIAL ALLOCATIONS.  Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i)         PARTNERSHIP MINIMUM GAIN CHARGEBACK.  Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i).  For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Sections 6.1(d)(vi) and 6.1(d)(vii)).  This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii)       CHARGEBACK OF PARTNER NONRECOURSE DEBT MINIMUM GAIN.  Notwithstanding any other provision of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner

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with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii).  For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Sections 6.1(d)(vi) and 6.1(d)(vii), with respect to such taxable period.  This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii)      PRIORITY ALLOCATIONS.  (A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) to any Unitholder with respect to its Units for any taxable period is greater (on a per Unit basis) than the amount of cash or the Net Agreed Value of property distributed to the other Unitholders with respect to their Units (on a per Unit basis), then (1) each Unitholder receiving such greater cash or property distribution shall be allocated gross income in an amount equal to the product of (aa) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution (on a per Unit basis) to the Unitholders receiving the smallest distribution and (bb) the number of Units held by the Unitholder receiving the greater distribution; and (2) the General Partner shall be allocated gross income in an aggregate amount equal to 2/98ths of the sum of the amounts allocated in clause (1) above.

(B)       After the application of Section 6.1(d)(iii)(A), all or any portion of the remaining items of Partnership gross income or gain for the taxable period, if any, shall be allocated 100% to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this paragraph 6.1(d)(iii)(B) for the current taxable period and all previous taxable periods is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Closing Date to a date 45 days after the end of the current taxable period.

(iv)       QUALIFIED INCOME OFFSET.  In the event ally Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or 6.1(d)(ii).

(v)        GROSS INCOME ALLOCATIONS.  In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that

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such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

(vi)       NONRECOURSE DEDUCTIONS.  Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests.  If the General Partner determines in its good faith discretion that the Partnership’s Nonrecourse Deductions must be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii)     PARTNER NONRECOURSE DEDUCTIONS.  Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i).  If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

(viii)    NONRECOURSE LIABILITIES.  For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.

(ix)       CODE SECTION 754 ADJUSTMENTS.  To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(c) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x)        ECONOMIC UNIFORMITY.  For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations of income, gain, loss, deduction, Unrealized Gain or Unrealized Loss; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof).  The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.1(d)(x) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding

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or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

(xi)       CURATIVE ALLOCATION.

(A)       Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1.  Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain.  Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner reasonably determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners.  Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred to the extent the General Partner reasonably determines that such allocations are likely to be offset by subsequent Required Allocations.

(B)       The General Partner shall have reasonable discretion, with respect to each taxable period, to (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii)     CORRECTIVE AND OTHER ALLOCATIONS.  In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A)       Except as provided in Section 6.1(d)(xii)(B), in the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof) with respect to any Partnership property, the General Partner shall allocate such Additional Book Basis Derivative Items (1) to (aa) the holders of Incentive Distribution Rights and (bb) the General Partner in the same manner that the Unrealized Gain or Unrealized Loss attributable to such property is allocated pursuant to Section 5.5(d)(i) or 5.5(d)(ii) and (2) to the Common Unitholders, Pro Rata, to the extent that the Unrealized Gain or Unrealized Loss attributable to such property is allocated to any Common Unitholders in respect of their Common Units pursuant to Section 5.5(d)(i) or 5.5(d)(ii).

(B)       In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) or an allocation of Net Termination Gain or Net Termination Loss under Section 6.1(c)) as a result of a sale or other taxable disposition of any Partnership asset that is an Adjusted Property (“DISPOSED OF ADJUSTED PROPERTY”),  the General Partner shall allocate additional items

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of gross income and gain away from the holders of Incentive Distribution Rights and the General Partner to the Common Unitholders, or additional items of deduction and loss away from the Common Unitholders to the holders of Incentive Distribution Rights and the General Partner, to the extent that the Additional Book Basis Derivative Items allocated to the Common Unitholders exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property.  For this purpose, the Common Unitholders shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Common Unitholders under this Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among the Partners).  Any allocation made pursuant to this Section 6.1(d)(xii)(B) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

(C)       In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as reasonably determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balance of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c).

(D)       In making the allocations required under this Section 6.1(d)(xii), the General Partner, in its sole discretion, may apply whatever conventions or other methodology it deems reasonable to satisfy the purpose of this Section 6.1(d)(xii).

(xiii)    CAPITAL ACCOUNT DEFICITS.  Except as otherwise provided in this Section 6.1(d)(xiii), the General Partner shall not be allocated its portion of any item of Net Losses to the extent that such allocation would cause or increase a deficit balance in the General Partner’s Adjusted Capital Account.  Any item of Net Losses or portion thereof which, but for the limitation in the first sentence of this Section 6.1(d)(xiii), would be allocated to the General Partner, shall be allocated to the Class B Unitholders having positive balances in their Adjusted Capital Accounts, to the extent of and in proportion to such positive balances, provided that if the Adjusted Capital Account of all of the Class B Unitholders have been reduced to zero, any remaining Net Losses shall be allocated to the General Partner.  If Net Losses have been allocated to the Class B Unitholders pursuant to this Section 6.1(d)(xiii) for any taxable year, then Net Income for each subsequent taxable year and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable year shall be allocated 100% to such Class B Unitholders in proportion to such Net Losses previously allocated to them before any allocation of Net Income pursuant to Section 6.1(a) until the aggregate Net Income allocated to them pursuant to this Section 6.1(d)(xiii) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to them pursuant to this Section 6.1(d)(xiii) for all previous taxable years.

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SECTION 6.2      ALLOCATIONS FOR TAX PURPOSES.

(a)        Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “BOOK”  income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b)        In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners as follows:

(i)         (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “BOOK” gain or loss is allocated pursuant to Section 6.1.

(ii)       (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.5(d)(i) or 5.5(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with Section 6.2(b)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “BOOK” gain or loss is allocated pursuant to Section 6.1.

(iii)      The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

(c)        For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall have sole discretion to (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including, without limitation, gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof).  The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(c) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

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(d)        The General Partner in its discretion may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Partnership’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-1(a)(6).  If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property.  If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other reasonable depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(e)        Any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(f)        All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code which may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted as necessary or appropriate, as determined by the General Partner, to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(g)        Each item of Partnership income, gain, loss and deduction shall, for federal income tax purposes, be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the New York Stock Exchange on the first Business Day of each month; provided, however, that gain or loss on a sale or other disposition of any assets of the Partnership other than in the ordinary course of business shall be allocated to the Partners as of the opening of the New York Stock Exchange on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes.  The General Partner may revise, alter or otherwise modify such methods of allocation as it determines necessary, to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(h)        Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner in its sole discretion.

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(i)        Notwithstanding any other provision of this agreement, solely for Canadian income tax purposes,

(i)         the gross amount of any dividend or deemed dividend (a “FOREIGN AFFILIATE DIVIDEND”)  paid by any entity that is a “foreign affiliate” (as defined in subsection 95(1) of the Income Tax Act (Canada) (the “ITA”)) of the Partnership (a “FOREIGN AFFILIATE”)  to the Partnership, and the gross amount of any expenses of the Partnership attributable thereto, shall be allocated in a manner consistent with subsection 93.1(2) of the ITA; and

(ii)       the amount of all other items of income, gain, loss, deduction and credit recognized by the Partnership shall be allocated to the Partners in accordance with this Section 6.2, provided that such amount shall exclude any such item that (A) is recognized by a Foreign Affiliate, and (B) is not required to be included in the income of the Partnership under subsection 91(1) of the ITA.

SECTION 6.3      REQUIREMENT AND CHARACTERIZATION OF DISTRIBUTIONS; DISTRIBUTIONS TO RECORD HOLDERS.

(a)        Within 45 clays following the end of each Quarter, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner in its reasonable discretion.  All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately preceding Quarter.  Ally remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be “CAPITAL SURPLUS.”  All distributions required to be made under this Agreement shall be made subject to Section 17-607 of the Delaware Act.

(b)        Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all receipts received during or after the Quarter in which the Liquidation Date occurs, other than from borrowings described in (a)(ii) of the definition of Available Cash, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c)        The General Partner shall have the discretion to treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(d)        Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution.  Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

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SECTION 6.4      DISTRIBUTIONS OF AVAILABLE CASH FROM OPERATING SURPLUS.

Available Cash with respect to any Quarter that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or 6.5, subject to Section 17-607 of the Delaware Act, shall be distributed as follows, except as otherwise required by Section 5.6(b) in respect of additional Partnership Securities issued pursuant thereto:

(a)        First, 98% to all Common Unitholders, Pro Rata, and 2% to the General Partner until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the First Target Distribution for such Quarter;

(b)        Second, 85% to all Common Unitholders, Pro Rata, 13% to the holders of the Incentive Distribution Rights, Pro Rata, and 2% to the General Partner until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

(c)        Thereafter, 75% to all Common Unitholders, Pro Rata, 23% to the holders of the Incentive Distribution Rights, Pro Rata, and 2% to the General Partner;

provided, however, if the First Target Distribution and the Second Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(c).

SECTION 6.5      DISTRIBUTIONS OF AVAILABLE CASH FROM CAPITAL SURPLUS.

Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall, subject to Section 17-607 of the Delaware Act, be distributed, unless the provisions of Section 6.3 require otherwise, 98% to all Common Unitholders, Pro Rata, and 2% to the General Partner until a hypothetical holder of a Common Unit acquired on the Closing Date has received with respect to such Common Unit, during the period since the Closing Date through such date, distributions of Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Unit Price.  Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4.

SECTION 6.6      ADJUSTMENT OF MINIMUM QUARTERLY DISTRIBUTION AND TARGET DISTRIBUTION LEVELS.

(a)        The Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Common Units or otherwise) of the Common Units or other Partnership Securities in accordance with Section 5.10.  In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution shall be adjusted proportionately downward to equal the product obtained by multiplying the

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otherwise applicable Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution, as the case may be, by a fraction of which the numerator is the Unrecovered Capital of the Common Units immediately after giving effect to such distribution and of which the denominator is the Unrecovered Capital of the Common Units immediately prior to giving effect to such distribution.  These adjustments will not apply to the quarter in which the distributions of Available Cash that are deemed to be from Capital Surplus trigger these adjustments.

(b)        The Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution shall also be subject to adjustment pursuant to Section 6.9.

SECTION 6.7      [INTENTIONALLY OMITTED.]

SECTION 6.8      SPECIAL PROVISIONS RELATING TO THE HOLDERS OF INCENTIVE DISTRIBUTION RIGHTS.

Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (a) shall (i) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Articles III and VII and (ii) have a Capital Account as a Partner pursuant to Section 5.5 and all other provisions related thereto and (b) shall not (i) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, (ii) be entitled to any distributions other than as provided in Sections 6.4(b),  6.4(c) and 12.4 or (iii) be allocated items of income, gain, loss or deduction other than as specified in this Article VI.

SECTION 6.9      ENTITY-LEVEL TAXATION.

If legislation is enacted or the interpretation of existing legislation is modified by the relevant governmental authority which causes the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise subjects the Partnership, or any Group Member to entity-level taxation for federal income tax purposes, the then applicable Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution may, at the General Partner's discretion, be adjusted to an amount that is not less than the amount equal to the product obtained by multiplying (a) the amount thereof by (b) one minus the sum of (i) the highest marginal federal corporate (or other entity, as applicable) income tax rate that could apply to the Partnership or any Group Member  for the taxable year of the Partnership or such Group Member in which such Quarter occurs (expressed as a decimal) plus (ii) the effective overall state and local income tax rate (expressed as a decimal) that would have been applicable to the Partnership or such Group Member for the calendar year next preceding the calendar year in which such Quarter occurs (after taking into account the benefit of any deduction allowable for federal income tax purposes with respect to the payment of state and local income taxes), but only to the extent of the increase in such rates resulting from such legislation or interpretation. For purposes of this Section 6.9, such effective overall state and local income tax rate shall be determined for the taxable year next preceding the first taxable year during which the Partnership or any Group Member is taxable for federal income tax purposes as an association taxable as a corporation or is otherwise subject to entity-level taxation by determining such rate as if the

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Partnership or any Group Member had been subject to such state and local taxes during such preceding taxable year.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

SECTION 7.1      MANAGEMENT.

(a)        The General Partner shall conduct, direct and manage all activities of the Partnership.  Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner or Assignee shall have any management power over the business and affairs of the Partnership.  In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or which are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it, in its sole discretion, may deem necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i)         the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into Partnership Securities, and the incurring of any other obligations;

(ii)       the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii)      the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3);

(iv)       the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group or making investments in or loans to JV Entities; subject to Section 7.6(a), the lending of funds to other Persons; the repayment of obligations of the Partnership Group or any JV Entity and the making of capital contributions to any Group Member or JV Entity;

(v)        the negotiation, execution and performance of any contracts, conveyances or other instruments (including contracts, conveyances or instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if these arrangements result in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

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(vi)       the distribution of Partnership cash;

(vii)     the selection and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

(viii)    the maintenance of such insurance for the benefit of the Partnership Group and the Partners as it deems necessary or appropriate;

(ix)       the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations or other relationships subject to the restrictions set forth in Section 2.4;

(x)        the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation and the incurring of legal expense and the settlement of claims and litigation;

(xi)       the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii)     the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8); and

(xiii)    unless restricted or prohibited by Section 5.7, the issuance, purchase, sale or other acquisition or disposition of Partnership Securities or options, rights, warrants and appreciation rights relating to Partnership Securities.

(b)        Notwithstanding any other provision of this Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and the Assignees and each other Person who may acquire an interest in Partnership Securities agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them, of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV), shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.

SECTION 7.2      CERTIFICATE OF LIMITED PARTNERSHIP.

The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act and shall use all reasonable efforts to cause to be filed such other certificates or documents as may be determined by the General Partner in its sole discretion to be reasonable and necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in

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which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property.  To the extent that such action is determined by the General Partner in its sole discretion to be reasonable and necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property.  Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

SECTION 7.3      RESTRICTIONS ON GENERAL PARTNER’S AUTHORITY.

(a)        The General Partner may not, without written approval of the specific act by holders of all of the Outstanding Limited Partner Interests or by other written instrument executed and delivered by holders of all of the Outstanding Limited Partner Interests subsequent to the date of this Agreement, take any action in contravention of this Agreement, including, except as otherwise provided in this Agreement, (i) committing any act that would make it impossible to carry on the ordinary business of the Partnership; (ii) possessing Partnership property, or assigning any rights in specific Partnership property, for other than a Partnership purpose; (iii) admitting a Person as a Partner; (iv) amending this Agreement in any manner; or (v) transferring its interest as general partner of the Partnership.

(b)        Except as provided in Articles XII and XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the Partnership’s assets in a single transaction or a series of related transactions (including by way of merger, consolidation or other combination) without the approval of holders of a Unit Majority; provided however that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership and shall not apply to any sale of any or all of the assets of the Partnership pursuant to the foreclosure of, or other realization upon, any such encumbrance.  Without the approval of holders of a Unit Majority, the General Partner shall not, on behalf of the Partnership, except as permitted under Section 4.6,  11.1 or 11.2, elect or cause the Partnership to elect a successor general partner of the Partnership.

(c)        The General Partner may not approve or consent to the conversion of Northern Border PipeLine or any other JV Entity that is not then taxable as an entity for federal income tax purposes to corporate form without first obtaining the approval of the holders of at least a majority of the Outstanding Units.

SECTION 7.4      REIMBURSEMENT OF THE GENERAL PARTNER.

(a)        Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as general partner or managing member of any Group Member.

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(b)        The General Partner shall be reimbursed on a monthly basis, or such other reasonable basis as the General Partner may determine hi its sole discretion, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership (including salary, bonus, incentive compensation and other amounts paid to any Person including Affiliates of the General Partner to perform services for the Partnership or for the General Partner in the discharge of its duties to the Partnership), and (ii) all other necessary or appropriate expenses allocable to the Partnership or otherwise reasonably incurred by the General Partner in connection with operating the Partnership’s business (including expenses allocated to the General Partner by its Affiliates).  The General Partner shall determine the expenses that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion.  Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(c)        Subject to Section 5.7, the General Partner, in its sole discretion and without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Securities or options to purchase Partnership Securities), or cause the Partnership to issue Partnership Securities in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any of its Affiliates, in each case for the benefit of employees of the General Partner, any Group Member or any Affiliate, or any of them, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group.  The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Securities that the General Partner or such Affiliate is obligated to provide to any employees pursuant to any such employee benefit plans, employee programs or employee practices.  Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliate of Partnership Securities purchased by the General Partner or such Affiliate from the Partnership to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b).  Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

SECTION 7.5      OUTSIDE ACTIVITIES.

(a)        The General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as the general partner (or managing member) of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a limited partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner (or managing member) of one or more Group Members or as described in or contemplated by the Registration Statement or (B) the acquiring, owning or disposing of debt or equity securities or interests in any Group Member.

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(b)        Except as specifically restricted by Section 7.5(a), each Indemnitee (other than the General Partner) shall have the right to engage in businesses of any and every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member or JV Entity, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member or JV Entity, and none of the same shall constitute a breach of this Agreement or any duty express or implied by law to any Group Member or JV Entity or any Partner or Assignee.  Neither any Group Member, any JV Entity, any Limited Partner nor any other Person shall have any rights by virtue of this Agreement or the partnership relationship established hereby in any business ventures of any Indemnitee.

(c)        Subject to the terms of Sections 7.5(a) and 7.5(b), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Indemnitees (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of the General Partner’s fiduciary duty or any other obligation of any type whatsoever of the General Partner for the Indemnitees (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the General Partner and the Indemnities shall have no obligation to present business opportunities to the Partnership.

(d)        The General Partner and any of its Affiliates may acquire Units or other Partnership Securities in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise all rights, powers and privileges (as General Partner, Limited Partner or Assignee, as applicable) relating to such Units or Partnership Securities.

(e)        The term “AFFILIATES”  when used in Section 7.5(d) with respect to the General Partner shall not include any Group Member or any Subsidiary of a Group Member.

(f)        Anything in this Agreement to the contrary notwithstanding, to the extent that provisions of Section 7.7,  7.8,  7.9,  7.10 or other Sections of this Agreement purport or are interpreted to have the effect of restricting the fiduciary duties that might otherwise, as a result of Delaware or other applicable law, be owed by the General Partner to the Partnership and its Limited Partners, or to constitute a waiver or consent by the Limited Partners to any such restriction, such provisions shall be inapplicable and have no effect in determining whether the General Partner has complied with its fiduciary duties in connection with determinations made by it under Section 7.5(a).

SECTION 7.6      LOANS FROM THE GENERAL PARTNER; LOANS OR CONTRIBUTIONS FROM THE PARTNERSHIP; CONTRACTS WITH AFFILIATES; CERTAIN RESTRICTIONS ON THE GENERAL PARTNER.

(a)        The General Partner or its Affiliates may lend to any Group Member or JV Entity, and any Group Member or TV Entity may borrow from the General Partner or any of its

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Affiliates, funds needed or desired by the Group Member or JV Entity for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees).  The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds.  For purposes of this Section 7.6(a) and Section 7.6(b), the term “GROUP MEMBER” shall include any Affiliate of a Group Member that is controlled by the Group Member.  No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

(b)        The Partnership may lend or contribute to any Group Member or JV Entity, and any Group Member or JV Entity may borrow from the Partnership, funds on terms and conditions established in the sole discretion of the General Partner; provided, however, that the Partnership may not charge the Group Member or JV Entity interest at a rate less than the rate that would be charged to the Group Member or JV Entity (without reference to the General Partner’s financial abilities or guarantees) by unrelated lenders on comparable loans.  The foregoing authority shall be exercised by the General Partner in its sole discretion and shall not create any right or benefit in favor of any Group Member, JV Entity or any other Person.

(c)        The General Partner may itself, or may enter into an agreement with any of its Affiliates to, render services to a Group Member or JV Entity or to the General Partner in the discharge of its duties as general partner of the Partnership.  Any services rendered to a Group Member or JV Entity by the General Partner or any of its Affiliates shall be on terms that are fair and reasonable to the Partnership; provided, however, that the requirements of this Section 7.6(c) shall be deemed satisfied as to (i) any transaction approved by Special Approval, (ii) any transaction, the terms of which are no less favorable to such Group Member or JV Entity than those generally being provided to or available from unrelated third parties or (iii) any transaction that, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to such Group Member or JV Entity), is equitable to such Group Member or JV Entity.  The provisions of Section 7.4 shall apply to the rendering of services described in this Section

(d)        The Partnership Group may transfer assets to joint ventures, other partnerships, corporations, limited liability companies or other business entities in which it is or thereby becomes a participant upon such terms and subject to such conditions as are consistent with this Agreement and applicable law.

(e)        Neither the General Partner nor any of its Affiliates shall sell, transfer or convey any  property to, or purchase any property from, the Partnership, any other Group Member or any JV Entity directly or indirectly, except pursuant to transactions that are fair and reasonable to the Partnership; provided, however, that the requirements of this Section 7.6(e) shall be deemed to be satisfied as to (i) the transactions effected pursuant to the Transaction Agreements, (ii) any transaction approved by Special Approval, (iii) any transaction, the terms of which are no less favorable to the Partnership than those generally being provided to or available from unrelated

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third parties, or (iv) any transaction that, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership), is equitable to the Partnership.  With respect to any contribution of assets to the Partnership in exchange for Partnership Securities, the Conflicts Committee, in determining whether the appropriate number of Partnership Securities are being issued, may take into account, among other things, the fair market value of the assets, the liquidated and contingent liabilities assumed, the tax basis in the assets, the extent to which tax-only allocations to the transferor will protect the existing partners of the Partnership against a low tax basis, and such other factors as the Conflicts Committee deems relevant under the circumstances.

(f)        The General Partner and its Affiliates will have no obligation to permit any Group Member or JV Entity to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use, nor shall there be any obligation on the part of the General Partner or its Affiliates to enter into such contracts.

(g)        Without limitation of Sections 7.6(a) through 7.6(f), and notwithstanding anything to the contrary in this Agreement (including Sections 7.6(a) through 7.6(f)), the existence of the conflicts of interest described in the Registration Statement have previously been approved by the Partners.

SECTION 7.7      INDEMNIFICATION.

(a)        To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee; provided, that in each case the Indemnitee acted in good faith and in a manner that such Indemnitee reasonably believed to be in, or (in the case of a Person other than the General Partner) not opposed to, the best interests of the Partnership and, with respect to any criminal proceeding, had no reasonable cause to believe its conduct was unlawful; and provided further that no indemnification pursuant to this Section 7.7 shall be available to the General Partner or its Affiliates with respect to their obligations incurred pursuant to the Transaction Agreements (other than obligations incurred by the General Partner on behalf of the Partnership).  The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere, or its equivalent, shall not create a presumption that the Indemnitee acted in a minter contrary to that specified above.  Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

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(b)        To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to the final disposition of such claim, demand, action, suit or proceeding upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be determined that the Indemnitee is not entitled to be indemnified as authorized in this Section 7.7.

(c)        The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d)        The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against or expense that may be incurred by such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e)        For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “FINES” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose which is in, or not opposed to, the best interests of the Partnership.

(f)        In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g)        An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h)        The provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i)         No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future

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Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

SECTION 7.8      LIABILITY OF INDEMNITEES.

(a)        Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners, the Assignees or any other Persons who have acquired interests in the Partnership Securities, for losses sustained or liabilities incurred as a result of any act or omission if such Indemnitee acted in good faith.

(b)        Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c)        To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.  The provisions of this Agreement, to the extent that they restrict or otherwise modify the duties and liabilities of an Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of such Indemnitee.

(d)        Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability to the Partnership, the Limited Partners, the General Partner, and the Partnership’s and General Partner’s directors, officers and employees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

SECTION 7.9      RESOLUTION OF CONFLICTS OF INTEREST.

(a)        Unless otherwise expressly provided in this Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Partner or any Assignee, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any agreement contemplated herein, or of any duty stated or implied by law or equity, if the resolution or course of action is, or by operation of this Agreement is deemed to be, fair and reasonable to the Partnership.  The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such

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resolution.  Any conflict of interest and any resolution of such conflict of interest shall be conclusively deemed fair and reasonable to the Partnership if such conflict of interest or resolution is (i) approved by Special Approval (as long as the material facts known to the General Partner or any of its Affiliates regarding any proposed transaction were disclosed to the Conflicts Committee at the time it gave its approval), (ii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iii) fair to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership).  The General Partner may also adopt a resolution or course of action that has not received Special Approval.  The General Partner (including the Conflicts Committee in connection with Special Approval) shall be authorized in connection with its determination of what is “fair and reasonable” to the Partnership and in connection with its resolution of any conflict of interest to consider (A) the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest; (B) any customary or accepted industry practices and any customary or historical dealings with a particular Person; (C) any applicable generally accepted accounting practices or principles; and (D) such additional factors as the General Partner (including the Conflicts Committee) determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.  Nothing contained in this Agreement, however, is intended to nor shall it be construed to require the General Partner (including the Conflicts Committee) to consider the interests of any Person other than the Partnership.  In the absence of bad faith by the General Partner, the resolution, action or terms so made, taken or provided by the General Partner with respect to such matter shall not constitute a breach of this Agreement or any other agreement contemplated herein or a breach of any standard of care or duty imposed herein or therein or, to the extent permitted by law, under the Delaware Act or any other law, rule or regulation.

(b)        Whenever this Agreement or any other agreement contemplated hereby provides that the General Partner or any of its Affiliates is permitted or required to make a decision (i) in its “sole discretion” or “discretion,” that it deems “necessary or appropriate” or  “necessary or advisable” or under a grant of similar authority or latitude, except as otherwise provided herein, the General Partner or such Affiliate shall be entitled to consider only such interests and factors as it desires and shall have no duty or obligation to give any consideration to any interest of, or factors affecting, the Partnership, any other Group Member or JV Entity, any Limited Partner or any Assignee, (ii) it may make such decision in its sole discretion (regardless of whether there is a reference to “sole discretion” or “discretion”) unless another express standard is provided for, or (iii) in “good faith” or under another express standard, the General Partner or such Affiliate shall act under such express standard and shall not be subject to any other or different standards imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation.  In addition, any actions taken by the General Partner or such Affiliate consistent with the standards of “reasonable discretion” set forth in the definitions of Available Cash or Operating Surplus shall not constitute a breach of any duty of the General Partner to the Partnership or the Limited Partners.  The General Partner shall have no duty, express or implied, to sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business.  No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty of the General Partner to the Partnership or the Limited Partners by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to enable distributions to the General Partner or its Affiliates

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(including in their capacities as Limited Partners) to exceed 2% of the total amount distributed to all Partners.

(c)        Whenever a particular transaction, arrangement or resolution of a conflict of interest is required under this Agreement to be “fair and reasonable” to any Person, the fair and reasonable nature of such transaction, arrangement or resolution shall be considered in the context of all similar or related transactions.

(d)        The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

SECTION 7.10    OTHER MATTERS CONCERNING THE GENERAL PARTNER.

(a)        The General Partner may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b)        The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence and in accordance with such opinion shall be conclusively presumed to have been done or omitted in good faith.

(c)        The General Partner shall have the right, in respect of any of its rights, powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership.

(d)        Any standard of care and duty imposed by this Agreement or under the Delaware Act or any applicable law, rule or regulation shall be modified, waived or limited, to the extent permitted by law, as required to permit the General Partner to act under this Agreement or any other agreement contemplated by this Agreement and to make any decision pursuant to the authority prescribed in this Agreement, so long as such action is reasonably believed by the General Partner to be in, or not inconsistent with, the best interests of the Partnership.

SECTION 7.11    PURCHASE OR SALE OF PARTNERSHIP SECURITIES.

The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Securities.  As long as Partnership Securities are held by any Group Member, such Partnership Securities shall not be considered Outstanding for any purpose, except as otherwise provided herein.  The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Securities for its own account, subject to the provisions of Articles IV and X.

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SECTION 7.12    REGISTRATION RIGHTS OF THE GENERAL PARTNER AND ITS AFFILIATES.

(a)        If (i) the General Partner or any Affiliate of the General Partner (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Securities (the “HOLDER”)  to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then upon the request of the General Partner or any of its Affiliates, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Securities specified by the Holder; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to this Section 7.12(a); and provided further, however, that if the Conflicts Committee determines in its good faith judgment that a postponement of the requested registration for up to six months would be in the best interests of the Partnership and its Partners due to a pending transaction, investigation or other event, the filing of such registration statement or the effectiveness thereof may be deferred for up to six months, but not thereafter.  In connection with any registration pursuant to the immediately preceding sentence, the Partnership shall promptly prepare and file (x) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation, or partnership doing business in such jurisdiction solely as a result of such registration, and (y) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and do any and all other acts and things that may reasonably be necessary or advisable to enable the Holder to consummate a public sale of such Partnership Securities in such states.  Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b)        If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of equity securities of the Partnership for cash (other than an offering relating solely to an employee benefit plan), the Partnership shall use all reasonable efforts to include such number or amount of securities held by the Holder in such registration statement as the Holder shall request.  If the proposed offering pursuant to this Section 7.12(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Partnership Securities would adversely and materially affect the success of the offering, the Partnership shall include in such offering only that number or amount, if any, of securities held by the Holder which, in the opinion of the

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managing underwriter or managing underwriters, will not so adversely and materially affect the offering.  Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c)        If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters.  Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder and each Person who controls the Holder (within the meaning of the Securities Act) and their respective directors, officers, employees, members, partners or agents (collectively, “INDEMNIFIED PERSONS”)  against any losses, claims, demands, actions, causes of action, assessments, damages, liabilities (joint or several), costs and expenses (including interest, penalties and reasonable attorneys’ fees and disbursements), resulting to, imposed upon, or incurred by the Indemnified Persons, directly or indirectly, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(c) as a “CLAIM”  and in the plural as “CLAIMS”)  based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Securities were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(d)        The provisions of Sections 7.12(a) and 7.12(b) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be a Partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Securities with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Securities for which registration was demanded during such two-year period.  The provisions of Section 7.12(c) shall continue in effect thereafter.

(e)        Any request to register Partnership Securities pursuant to this Section 7.12 shall (i) specify the Partnership Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such shares for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Securities, and (iv) contain the undertaking of such Person to provide all such information and materials and

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take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Securities.

SECTION 7.13    RELIANCE BY THIRD PARTIES.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that (i) the General Partner and (ii) any officer or attorney-in-fact of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership, has fill power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer or attorney-in-fact as if it were the Partnership’s sole party in interest, both legally and beneficially.  Each Limited Partner hereby waives any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer or attorney-in-fact in connection with any such dealing.  In no event shall any Person dealing with the General Partner or any such officer or attorney-in-fact be obligated to ascertain that the terms of the Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or attorney-in-fact.  Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or any such officer or attorney-in-fact shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

SECTION 8.1      RECORDS AND ACCOUNTING.

The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a).  Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders and Assignees of Units or other Partnership Securities, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time.  The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP.

SECTION 8.2      FISCAL YEAR.

The fiscal year of the Partnership shall be a fiscal year ending December 31.

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SECTION 8.3      REPORTS.

(a)        As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available by any reasonable means (including posting on or accessible through the Partnership’s or the SEC’s website) to each Record Holder of a Unit, as of a date selected by the General Partner in its discretion, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

(b)        To the extent required by applicable law, regulation or rule of any National Securities Exchange on which the Common Units are listed for trading or as the General Partner determines to be necessary or appropriate, as soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available by any reasonable means (including posting on or accessible through the Partnership’s or the SEC’s website) to each Record Holder of a Unit, as of a date selected by the General Partner in its discretion, a report containing unaudited financial statements of the Partnership and such other information as so required, or as the General Partner determines to be necessary or appropriate.

ARTICLE IX

TAX MATTERS

SECTION 9.1      TAX RETURNS AND INFORMATION.

The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and a taxable year ending on December 31.  The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable year ends.  The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

SECTION 9.2      TAX ELECTIONS.

(a)        The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners.  Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are traded during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(g) without regard to the actual price paid by such transferee.

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(b)        Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

SECTION 9.3      TAX CONTROVERSIES.

(a)        Subject to the provisions hereof, the General Partner (or its designee) is designated as the Tax Matters Partner (as defined in Section 6231(a)(7) of the Code as in effect prior to the enactment of the Bipartisan Budget Act of 2015), and the Partnership Representative (as defined in Section 6223 of the Code following the enactment of the Bipartisan Budget Act of 2015 or under any applicable state or local law providing for an analogous capacity), and is authorized to represent the Partnership (at the Partnership's expense) in connection with all examinations of the Partnership's affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith.  In its capacity as Partnership Representative, the General Partner shall exercise any and all authority of the Partnership Representative, including, without limitation, (i) binding the Partnership and its Partners with respect to tax matters and (ii) determining whether to make any available election under Section 6226 of the Code or an analogous election under state or local law, which election permits the Partnership to pass any partnership adjustment through to the Persons who were Partners of the Partnership in the year to which the adjustment relates and irrespective of whether such Persons are Partners of the Partnership at the time such election is made.  Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably requested by the General Partner in its capacity as the Tax Matters Partner or Partnership Representative.  For Partners that are not tax-exempt entities (as defined in Section 168(h)(2) of the Code) and subject to the General Partner's discretion to seek modifications of an imputed underpayment, this cooperation includes (i) filing amended federal, state or local tax returns, paying any additional tax (including interest, penalties and other additions to tax), and providing the General Partner with an affidavit swearing to relevant facts (all within the requisite time periods), and (ii) providing any other information requested by the General Partner in order to seek modifications of an imputed underpayment.  For Partners that are tax-exempt entities (as defined in Section 168(h)(2) of the Code) and subject to the General Partner's discretion to seek modifications of an imputed underpayment, this cooperation includes providing the General Partner with information necessary to establish any such Partner's tax-exempt status.  This agreement to cooperate applies irrespective of whether such Persons are Partners of the Partnership at the time of such requested cooperation.

(b)        Each Partner agrees that notice of or updates regarding tax controversies shall be deemed conclusively to have been given or made by the General Partner if the Partnership has either (i) filed the information for which notice is required with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such information is publicly available on such system or (ii) made the information for which notice is required available on any publicly available website maintained by the Partnership, whether or not such Partner remains a Partner in the Partnership at the time such information is made publicly available.  Notwithstanding anything herein to the contrary, nothing in this provision shall obligate the Partnership Representative to provide notice to the Partners other than as required by the Code.

(c)        The General Partner may amend the provisions of this Agreement as it determines appropriate to satisfy any requirements, conditions, or guidelines set forth in any amendment to

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the provisions of Subchapter C of Chapter 63 of Subtitle F of the Code, any analogous provisions of the laws of any state or locality, or the promulgation of regulations or publication of other administrative guidance thereunder.

SECTION 9.4      WITHHOLDING.

(a)        The General Partner may treat taxes paid by the Partnership on behalf of all or less than all of the Partners as a distribution of cash to such Partners, as a general expense of the Partnership, or as indemnifiable payments made by the Partnership on behalf of the Partners (as provided in Section 9.4(c)), as determined appropriate under the circumstances by the General Partner.

(b)        Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code.  To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income or from a distribution to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 or Section 12.4(c) in the amount of such withholding from such Partner.

(c)        If the Partnership pays an imputed underpayment under Section 6225 of the Code and/or any analogous provision of the laws of any state or locality, the General Partner may require that Partners of the Partnership in the year to which the underpayment relates indemnify the Partnership for their allocable share of that underpayment (including interest, penalties and other additions to tax).  This indemnification obligation shall not apply to a Partner to the extent that (i) the Partnership received a modification of the imputed underpayment under Section 6225(c)(2) of the Code (or any analogous provision of state or local law) due to the Partner's filing of amended tax returns and payment of any resulting tax (including interest, penalties and other additions to tax), (ii) the Partner is a tax-exempt entity (as defined in Section 168(h)(2) of the Code) and either the Partnership received a modification of the imputed underpayment under Section 6225(c)(3) of the Code (or any analogous provision of state or local law) because of such Partner's status as a tax-exempt entity or the Partnership did not make a good faith effort to obtain a modification of the imputed underpayment due to such Partner's status as a tax-exempt entity, or (iii) the Partnership received a modification of the imputed underpayment under Section 6225(c)(4)-(6) of the Code (or any analogous provision of state or local law) as a result of other information that was either provided by the Partner or otherwise available to the Partnership with respect to the Partner.  This indemnification obligation imposed on Partners, including former Partners, applies irrespective of whether such Persons are Partners of the Partnership at the time the Partnership pays the imputed underpayment.

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ARTICLE X

ADMISSION OF PARTNERS

SECTION 10.1    CURRENT PARTNERS.

The General Partner and the Limited Partners who are Record Holders of interests in the Partnership as Limited Partners are the current Partners of the Partnership as of the date of this Agreement.

SECTION 10.2    ADMISSION OF SUBSTITUTED LIMITED PARTNER.

By transfer of a Limited Partner Interest in accordance with Article IV, the transferor shall be deemed to have given the transferee the right to seek admission as a Substituted Limited Partner subject to the conditions of, and in the manner permitted under, this Agreement.  A transferor of a Certificate representing a Limited Partner Interest shall, however, only have the authority to convey to a purchaser or other transferee who does not execute and deliver a Transfer Application (a) the right to negotiate such Certificate to a purchaser or other transferee and (b) the right to transfer the right to request admission as a Substituted Limited Partner to such purchaser or other transferee in respect of the transferred Limited Partner Interests.  Each transferee of a Limited Partner Interest (including any nominee holder or an agent acquiring such Limited Partner Interest for the account of another Person) who executes and delivers a Transfer Application shall, by virtue of such execution and delivery, be an Assignee and be deemed to have applied to become a Substituted Limited Partner with respect to the Limited Partner Interests so transferred to such Person.  Such Assignee shall become a Substituted Limited Partner (x) at such time as the General Partner consents thereto, which consent may be given or withheld in the General Partner’s discretion, and (y) when any such admission is shown on the books and records of the Partnership.  If such consent is withheld, such transferee shall be an Assignee.  An Assignee shall have an interest in the Partnership equivalent to that of a Limited Partner with respect to allocations and distributions, including liquidating distributions, of the Partnership.  With respect to voting rights attributable to Limited Partner Interests that are held by Assignees, the General Partner shall be deemed to be the Limited Partner with respect thereto and shall, in exercising the voting rights in respect of such Limited Partner Interests on any matter, vote such Limited Partner Interests at the written direction of the Assignee who is the holder of such Limited Partner Interests.  If no such written direction is received, such Limited Partner Interests will not be voted.  An Assignee shall have no other rights of a Limited Partner.

SECTION 10.3    ADMISSION OF SUCCESSOR GENERAL PARTNER.

A successor General Partner approved pursuant to Section 11.1 or 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner pursuant to Section 11.1 or 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to

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effect such admission.  Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

SECTION 10.4    ADMISSION OF ADDITIONAL LIMITED PARTNERS.

(a)        A Person (other than the General Partner, an Initial Limited Partner or a Substituted Limited Partner) who makes a Capital Contribution to the Partnership in accordance with this Agreement shall be admitted to the Partnership as an Additional Limited Partner only upon furnishing to the General Partner (i) evidence of acceptance in form satisfactory to the General Partner of all of the terms and conditions of this Agreement, including the power of attorney granted in Section 2.6, and (ii) such other documents or instruments as may be required in the discretion of the General Partner to effect such Person’s admission as an Additional Limited Partner.

(b)        Notwithstanding anything to the contrary in this Section 10.4, no Person shall be admitted as an Additional Limited Partner without the consent of the General Partner, which consent may be given or withheld in the General Partner’s discretion.  The admission of any Person as an Additional Limited Partner shall become effective on the date upon which the name of such Person is recorded as such in the books and records of the Partnership, following the consent of the General Partner to such admission.

SECTION 10.5    AMENDMENT OF AGREEMENT AND CERTIFICATE OF LIMITED PARTNERSHIP.

To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary and appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership, and the General Partner may for this purpose, among others, exercise the power of attorney granted pursuant to Section 2.6.

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

SECTION 11.1    WITHDRAWAL OF THE GENERAL PARTNER.

(a)        The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “EVENT OF WITHDRAWAL”);

(i)         The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii)       The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

(iii)      The General Partner is removed pursuant to Section 11.2;

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(iv)       The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v)        A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(vi)       (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iv),  (v) or (vi)(A),  (B),  (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence.  The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b)        Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, Eastern Standard Time, on June 30, 2009, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“WITHDRAWAL OPINION OF COUNSEL”)  that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such); (ii) at any time after 12:00 midnight, Eastern Standard Time, on June 30, 2009, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at

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least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Common Units.  The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, as the case may be, of the other Group Members.  If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner.  The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, as the case may be, of the other Group Members of which the General Partner is a general partner or a managing member.  If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1.  Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.3.

SECTION 11.2    REMOVAL OF THE GENERAL PARTNER.

The General Partner may be removed if such removal is approved by the Common Unitholders holding at least 66 2/3% of the Outstanding Common Units (including Common Units held by the General Partner and its Affiliates).  Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Common Unitholders holding a Unit Majority (including Common Units held by the General Partner and its Affiliates).  Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.3.  The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, as the case may be, of the other Group Members of which the General Partner is a general partner or a managing member.  If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.3, automatically become a successor general partner or managing member, as the case may be, of the other Group Members of which the General Partner is a general partner or a managing member.  The right of the holders of Outstanding Common Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel.  Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.3.

SECTION 11.3    INTEREST OF DEPARTING PARTNER AND SUCCESSOR GENERAL PARTNER.

(a)        In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Common Units under circumstances where Cause does not exist, if a successor General Partner is elected in accordance with the terms of Section 11.1 or 11.2, the Departing Partner shall have the option exercisable prior to the effective date of the departure of such Departing Partner to require its successor to purchase its General Partner Interest and its

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general partner interest (or equivalent interest) in the other Group Members and all of its Incentive Distribution Rights (collectively, the “COMBINED INTEREST”)  in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its departure.  If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or 11.2, such successor shall have the option, exercisable prior to the effective date of the departure of such Departing Partner, to purchase the Combined Interest for such fair market value of such Combined Interest.  In either event, the Departing Partner shall be entitled to receive all reimbursements due such Departing Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing Partner for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing Partner and its successor or, failing agreement within 30 days after the effective date of such Departing Partner’s departure, by an independent investment banking firm or other independent expert selected by the Departing Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter.  If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such departure, then the Departing Partner shall designate an independent investment banking firm or other independent expert, the Departing Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest.  In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Common Units on any National Securities Exchange on which Common Units are then listed, the value of the Partnership’s assets, the rights and obligations of the Departing Partner and other factors it may deem relevant.

(b)        If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor).  Any successor General Partner shall indemnify the Departing Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing Partner (or its transferee) becomes a Limited Partner.  For purposes of this Agreement, conversion of the Combined Interest to Common Units will be characterized as if the Departing Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Common Units.

(c)        If a successor General Partner is elected in accordance with the terms of Section 11.1 or 11.2 and the option described in Section 11.3(a) is not exercised by the party

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entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to 2/98ths of the Net Agreed Value of the Partnership’s assets on such date.  In such event, such successor General Partner shall, subject to the following sentence, be entitled to 2% of all Partnership allocations and distributions.  The successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be 2%.

SECTION 11.4    [INTENTIONALLY OMITTED.]

SECTION 11.5    WITHDRAWAL OF LIMITED PARTNERS.

No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

SECTION 12.1    DISSOLUTION.

The Partnership shall not be dissolved by the admission of Substituted Limited Partners or Additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement.  Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 or 11.2, the Partnership shall not be dissolved and such successor General Partner shall continue the business of the Partnership.  The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

(a)        the expiration of its term as provided in Section 2.7;

(b)        an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and an Opinion of Counsel is received as provided in Section 11.1(b) or 11.2 and such successor is admitted to the Partnership pursuant to Section 10.3;

(c)        an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

(d)        the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or

(e)        the sale of all or substantially all of the assets and properties of the Partnership Group.

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SECTION 12.2    CONTINUATION OF THE BUSINESS OF THE PARTNERSHIP AFTER DISSOLUTION.

Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing Partner pursuant to Section 11.1 or 11.2, then within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv),  (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to reconstitute the Partnership and continue its business on the same terms and conditions set forth in this Agreement by forming a new limited partnership on terms identical to those set forth in this Agreement and having as the successor General Partner a Person approved by the holders of a Unit Majority (subject to the proviso in the last sentence of this Section 12.2).  Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs.  If such an election is so made, then:

(i)         the reconstituted Partnership shall continue until the end of the term set forth in Section 2.7 unless earlier dissolved in accordance with this Article XII;

(ii)       if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii)      all necessary steps shall be taken to cancel this Agreement and the Certificate of Limited Partnership and to enter into and, as necessary, to file a new partnership agreement and certificate of limited partnership, and the successor General Partner may for this purpose exercise the powers of attorney granted the General Partner pursuant to Section 2.6; provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to reconstitute and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner and (y) neither the Partnership nor the reconstituted limited partnership would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue.

SECTION 12.3    LIQUIDATOR.

Upon dissolution of the Partnership, unless the Partnership is continued under an election to reconstitute and continue the Partnership pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator.  The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units.  The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units.  Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights,

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powers and ditties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units, who shall also approve the compensation payable to such Liquidator.  The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided.  Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale or other disposition set forth in Section 7.3(b)) to the extent necessary or desirable in the good faith judgment of the Liquidator to carry out the duties and functions of the Liquidator hereunder for and during such period of time as shall be reasonably required in the good faith judgment of the Liquidator to complete the winding up and liquidation of the Partnership as provided for herein.

SECTION 12.4    LIQUIDATION.

The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as the Liquidator determines to be in the best interest of the Partners, subject to Section 17-804 of the Delaware Act and the following:

(a)        DISPOSITION OF ASSETS.  The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree.  If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners.  The Liquidator may, in its absolute discretion, defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners.  The Liquidator may, in its absolute discretion, distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b)        DISCHARGE OF LIABILITIES.  Liabilities of the Partnership include amounts owed to Partners otherwise than in respect of their distribution rights under Article VI.  With respect to any that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment.  When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c)        LIQUIDATION DISTRIBUTIONS.  All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period during which the liquidation of the Partnership occurs (with such date of occurrence being

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determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).

SECTION 12.5    CANCELLATION OF CERTIFICATE OF LIMITED PARTNERSHIP.

Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

SECTION 12.6    RETURN OF CONTRIBUTIONS.

The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

SECTION 12.7    WAIVER OF PARTITION.

To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

SECTION 12.8    CAPITAL ACCOUNT RESTORATION.

No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership.  The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable period during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

SECTION 13.1    AMENDMENT TO BE ADOPTED SOLELY BY THE GENERAL PARTNER.

Each Partner agrees that the General Partner, without the approval of any Partner or Assignee, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a)        a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b)        admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

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(c)        a change that, in the sole discretion of the General Partner, is necessary or advisable to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Partnership will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(d)        a change that, in the discretion of the General Partner, (i) does not adversely affect the Limited Partners in any material respect, (ii) is necessary or advisable to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Limited Partner Interests (including the division of any class or classes of Outstanding Limited Partner Interests into different classes to facilitate uniformity of tax consequences within such classes of Limited Partner Interests) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Limited Partner Interests are or will be listed for trading, compliance with any of which the General Partner determines in its discretion to be in the best interests of the Partnership and the Limited Partners, (iii) is necessary or advisable in connection with action taken by the General Partner pursuant to Section 5.10 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e)        a change in the fiscal year or taxable year of the Partnership and any changes that, in the discretion of the General Partner, are necessary or advisable as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “QUARTER”  and the dates on which distributions are to be made by the Partnership;

(f)        an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g)        an amendment that, in the discretion of the General Partner, is necessary or advisable in connection with the authorization or issuance of any class or series of Partnership Securities (or options, rights, warrants and appreciation rights relating to such Partnership Securities) pursuant to Section 5.6;

(h)        any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i)         an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

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(j)         an amendment that, in the discretion of the General Partner, is necessary or advisable to reflect, account for and deal with appropriately the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;

(k)        a merger or conveyance pursuant to Section 14.3(d); or

(l)         any other amendments substantially similar to the foregoing.

SECTION 13.2    AMENDMENT PROCEDURES.

Except as provided in Sections 13.1 and 13.3 and the Class B Unit Supplement, all amendments to this Agreement shall be made in accordance with the following requirements.  Amendments to this Agreement may be proposed only by or with the consent of the General Partner which consent may be given or withheld in its sole discretion.  A proposed amendment shall be effective upon its approval by the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law.  Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Common Units shall be set forth in a writing that contains the text of the proposed amendment.  If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Common Units or call a meeting of the Common Unitholders to consider and vote on such proposed amendment.  The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments.

SECTION 13.3    AMENDMENT REQUIREMENTS.

(a)        Notwithstanding the provisions of Sections 13.1 and 13.2, no provision of this Agreement that establishes a percentage of Outstanding Common Units (including Common Units held, or deemed held, by the General Partner or its Affiliates) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Common Units whose aggregate Outstanding Common Units constitute not less than the voting requirement sought to be reduced.

(b)        Notwithstanding the provisions of Sections 13.1 and 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c),  (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld in its sole discretion, (iii) change Section 12.1(a) or 12.1(c), or (iv) change the term of the Partnership or, except as set forth in Section 12.1(c), give any Person the right to dissolve the Partnership.

(c)        Except as provided in Section 14.3 or otherwise as may be provided in this Agreement and without limitation of the General Partner’s authority to adopt amendments to this Agreement as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes

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of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.

(d)        Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Common Units unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not (i) adversely affect the limited liability of any Limited Partner under the Delaware Act or the law of any other state in which the Partnership is registered as a foreign limited partnership or is otherwise qualified to do business or (ii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such).

(e)        Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Common Units.

SECTION 13.4    SPECIAL MEETINGS.

All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII.  Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners holding 20% or more of the Outstanding Limited Partner Interests of the class or classes for which a meeting is proposed.  Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called.  Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent.  A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting.  Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is registered as a foreign limited partnership or is otherwise qualified to do business.

SECTION 13.5    NOTICE OF A MEETING.

Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Limited Partner Interests for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1.  The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

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SECTION 13.6    RECORD DATE.

For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Limited Partner Interests are listed for trading, in which case the rule, regulation, guideline or requirement of such exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals.

SECTION 13.7    ADJOURNMENT.

When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days.  At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting.  If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

SECTION 13.8    WAIVER OF NOTICE; APPROVAL OF MEETING; APPROVAL OF MINUTES.

The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy, and if, either before or after the meeting, Limited Partners representing such quorum who were present in person or by proxy and entitled to vote, sign a written waiver of notice or an approval of the holding of the meeting or an approval of the minutes thereof.  All waivers and approvals shall be filed with the Partnership records or made a part of the minutes of the meeting.  Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner does not approve, at the beginning of the meeting, of the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

SECTION 13.9    QUORUM.

The holders of a majority of the Outstanding Limited Partner Interests of the class or classes for which a meeting has been called (including Limited Partner Interests held or deemed held by the General Partner or its Affiliates) represented in person or by proxy shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Limited Partner Interests, in which case the quorum shall be such greater percentage.  At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is

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present, the act of Limited Partners holding Outstanding Limited Partner Interests that in the aggregate represent a majority of the Outstanding Limited Partner Interests entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Limited Partner Interests that in the aggregate represent at least such greater or different percentage shall be required.  The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Limited Partner Interests specified in this Agreement (including Limited Partner Interests deemed owned by the General Partner).  In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Limited Partner Interests entitled to vote at such meeting (including Limited Partner Interests held or deemed held by the General Partner or its Affiliates) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

SECTION 13.10  CONDUCT OF A MEETING.

The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting.  The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting.  All minutes shall be kept with the records of the Partnership maintained by the General Partner.  The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

SECTION 13.11  ACTION WITHOUT A MEETING.

If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Limited Partners holding not less than the minimum percentage of the Outstanding Limited Partner Interests (including Limited Partner Interests held or deemed held by the General Partner or its Affiliates) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Limited Partner Interests are listed for trading, in which case the rule, regulation, guideline or requirement of such exchange shall govern).  Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing.  The General Partner may specify that any written ballot submitted to Limited Partners for the purpose

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of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner.  If a ballot returned to the Partnership does not vote all of the Limited Partner Interests held by a Limited Partner, the Partnership shall be deemed to have failed to receive a ballot for the Limited Partner Interests that were not voted.  If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.

SECTION 13.12  VOTING AND OTHER RIGHTS.

(a)        Only those Record Holders of the Limited Partner Interests on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “OUTSTANDING”)  shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Limited Partner Interests have the right to vote or to act.  All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Limited Partner Interests shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Limited Partner Interests.

(b)        With respect to Limited Partner Interests that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Limited Partner Interests are registered, such other Person shall, in exercising the voting rights in respect of such Limited Partner Interests on any matter, and unless the arrangement between such Persons provides otherwise, vote such Limited Partner Interests in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry.  The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

MERGER

SECTION 14.1    AUTHORITY.

The Partnership may merge or consolidate with one or more corporations, limited liability companies, business trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a general partnership or limited partnership, formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written agreement of merger or consolidation (“MERGER AGREEMENT”)  in accordance with this Article XIV.

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SECTION 14.2    PROCEDURE FOR MERGER OR CONSOLIDATION.

Merger or consolidation of the Partnership pursuant to this Article XIV requires the prior approval of the General Partner.  If the General Partner shall determine, in the exercise of its discretion, to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(a)        The names and jurisdictions of formation or organization of each of the business entities proposing to merge or consolidate;

(b)        The name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “SURVIVING BUSINESS ENTITY”);

(c)        The terms and conditions of the proposed merger or consolidation;

(d)        The manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or general or limited partner interests, rights, securities or obligations of any limited partnership, corporation, trust or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their general or limited partner interests, securities or rights, and (ii) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(e)        A statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other similar chatter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(f)        The effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of the certificate of merger, the effective time shall be fixed no later than the time of the filing of the certificate of merger and stated therein); and

(g)        Such other provisions with respect to the proposed merger or consolidation as are deemed necessary or appropriate by the General Partner.

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SECTION 14.3    APPROVAL BY LIMITED PARTNERS OF MERGER OR CONSOLIDATION.

(a)        Except as provided in Section 14.3(d), the General Partner, upon its approval of the Merger Agreement, shall direct that the Merger Agreement be submitted to a vote of the Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII.  A copy or a summary of the Merger Agreement shall be included in or enclosed with the notice of a special meeting or the written consent.

(b)        Except as provided in Section 14.3(d), the Merger Agreement shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of a greater percentage of the Outstanding Limited Partner Interests or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement.

(c)        Except as provided in Section 14.3(d), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger pursuant to Section 14.4, the merger or consolidation may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement.

(d)        Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, in its discretion, without Limited Partner approval, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity which shall be newly formed and shall have no assets, liabilities or operations at the time of such Merger other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such merger or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with the same rights and obligations as are herein contained.

SECTION 14.4    CERTIFICATE OF MERGER.

Upon the required approval by the General Partner and the Unitholders of a Merger Agreement, a certificate of merger shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

SECTION 14.5    EFFECT OF MERGER.

(a)        At the effective time of the certificate of merger:

(i)         all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any

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of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were property of each constituent business entity;

(ii)       the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and shall not in any way be impaired because of the merger or consolidation;

(iii)      all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv)       all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b)        A merger or consolidation effected pursuant to this Article shall not be deemed to result in a transfer or assignment of assets or liabilities from one entity to another.

ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

SECTION 15.1    RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS.

(a)        Notwithstanding any other provision of this Agreement, if at any time not more than 20% of the total Limited Partner Interests of any class then Outstanding is held by Persons other than the General Partner and its Affiliates, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable in its sole discretion, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.  As used in this Agreement, (i) “CURRENT MARKET PRICE”  as of any date of any class of Limited Partner Interests listed or admitted to trading on any National Securities Exchange means the average of the daily Closing Prices (as hereinafter defined) per Limited Partner Interest of such class for the 20 consecutive Trading Days (as hereinafter defined) immediately prior to such date; (ii) “CLOSING PRICE”  for any day means the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted for trading on the principal National Securities Exchange (other than the Nasdaq Stock Market) on which such Limited Partner Interests of such class are listed or admitted to trading or, if such Limited Partner Interests of such class are not listed or admitted to trading on any National Securities Exchange (other than the Nasdaq Stock Market), the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the

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over-the-counter market, as reported by the Nasdaq Stock Market or such other system then in use, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined reasonably and in good faith by the General Partner; and (iii) “TRADING DAY” means a day on which the principal National Securities Exchange on which such Limited Partner Interests of any class are listed or admitted to trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

(b)        If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “NOTICE OF ELECTION TO PURCHASE”)  and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date.  Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York, The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading.  Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice.  On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1.  If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Articles IV,  V,  VI, and XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as

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the case may be, shall be deemed to be the holder of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the holder of such Limited Partner Interests (including all rights as holder of such Limited Partner Interests pursuant to Articles IV, V, VI and XII).

(c)        At any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

ARTICLE XVI

GENERAL PROVISIONS

SECTION 16.1    ADDRESSES AND NOTICES.

Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner or Assignee under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner or Assignee at the address described below.  Any notice, payment or report to be given or made to a Partner or Assignee hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Securities by reason of any assignment or otherwise.  An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report.  If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Partnership is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner or Assignee at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners and Assignees.  Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3.  The General Partner may rely and shall be protected in relying on any notice or other document from a Partner, Assignee or other Person if believed by it to be genuine.

SECTION 16.2    FURTHER ACTION.

The patties hereto shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

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SECTION 16.3    BINDING EFFECT.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

SECTION 16.4    INTEGRATION.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

SECTION 16.5    CREDITORS.

None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

SECTION 16.6    WAIVER.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute a waiver of any subsequent breach or any breach of any other covenant, duty, agreement or condition.

SECTION 16.7    COUNTERPARTS.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart.  Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Unit, upon accepting the certificate evidencing such Unit or executing and delivering a Transfer Application as herein described, independently of the signature of any other party.

SECTION 16.8    APPLICABLE LAW.

This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

SECTION 16.9    INVALIDITY OF PROVISIONS.

If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

SECTION 16.10  CONSENT OF PARTNERS.

Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the

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Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

[REST OF PAGE INTENTIONALLY LEFT BLANK]

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

GENERAL PARTNER:
TC PIPELINES GP, INC.
By:	/s/ Nathan Brown
Name:	Nathan Brown
Title:	President
By:	/s/ Jon A. Dobson
Name:	Jon A. Dobson
Title:	Secretary
All Limited Partners now and hereafter admitted as Limited Partners of the Partnership, pursuant to powers of attorney now and hereafter executed in favor of, and granted and delivered to the General Partner.
TC PIPELINES GP, INC.
By:	/s/ Nathan Brown
Name:	Nathan Brown
Title:	President
By:	/s/ Jon A. Dobson
Name:	Jon A. Dobson
Title:	Secretary

EXHIBIT A

TO

FOURTH AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

TC PIPELINES, LP

CERTIFICATE EVIDENCING COMMON UNITS

REPRESENTING LIMITED PARTNER INTERESTS IN

TC PIPELINES, LP

No. __________ __________ Common Units

In accordance with Section 4.1 of the Fourth Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP, as amended, supplemented or restated from time to time (the “PARTNERSHIP AGREEMENT”), TC PipeLines, LP, a Delaware limited partnership (the “PARTNERSHIP”),  hereby certifies that ____________________ (the “HOLDER”)  is the registered owner of __________ Common Units representing limited partner interests in the Partnership (the “COMMON UNITS”)  transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed and accompanied by a properly executed application for transfer of the Common Units represented by this Certificate.  The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement.  Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at ____________________.  Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

Except as otherwise provided in the Partnership Agreement, this Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

A-1

Dated:		TC PIPELINES, LP
Countersigned and Registered by:		By:	TC PipeLines GP, Inc., its General Partner
		By:
as Transfer Agent and Registrar		Name:
By:		By:
	Authorized Signature		Secretary

A-2

[REVERSE OF CERTIFICATE]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

TEN COM —	as tenants in common	UNIF GIFT/TRANSFERS MIN ACT—
TEN ENT —	as tenants by the entireties
		Name of Custodian) as Custodian for
	as joint tenants with right of survivorship and not as tenants in common
JT TEN —		Under Uniform Gifts/Transfers to Minors Act
		(Name of State)

Additional abbreviations, though not in the above list, may also be used.

FOR VALUE RECEIVED,

_________________________ HEREBY ASSIGNS, CONVEYS, SELLS AND TRANSFERS UNTO

Please print or typewrite name and address of Assignee: Please insert Social Security or other identifying number of Assignee:

__________ Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint_________________________ as its attorney-in-fact with full power of substitution to transfer the same on the books of TC PipeLines, LP

Date:  ____________________	NOTE:  The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.
SIGNATURE(S) MUST BE
GUARANTEED BY A	(Signature)
MEMBER FIRM OF THE
NATIONAL ASSOCIATION
OF SECURITIES DEALERS,
INC. OR BY A COMMERCIAL	(Signature)
BANK OR TRUST COMPANY

A-3

SIGNATURE(S) GUARANTEED

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer and an Application for Transfer of Common Units has been executed by a transferee either (a) on the form set forth below or (b) on a separate application that the Partnership will furnish on request without charge.  A transferor of the Common Units shall have no duty to the transferee with respect to execution of the transfer application in order for such transferee to obtain registration of the transfer of the Common Units.

APPLICATION FOR TRANSFER OF COMMON UNITS

The undersigned (“ASSIGNEE”)  hereby applies for transfer to the name of the Assignee of the Common Units evidenced hereby.

The Assignee (a) requests admission as a Substituted Limited Partner and agrees to comply with and be bound by, and hereby executes, the Fourth Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP (the “PARTNERSHIP”),  as amended, supplemented or restated to the date hereof (the “PARTNERSHIP AGREEMENT”),  (b) represents and warrants that the Assignee has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (c) appoints the General Partner of the Partnership and, if a Liquidator shall be appointed, the Liquidator of the Partnership as the Assignee’s attorney-in-fact to execute, swear to, acknowledge and file any document, including, without limitation, the Partnership Agreement and any amendment thereto and the Certificate of Limited Partnership of the Partnership and any amendment thereto, necessary or appropriate for the Assignee’s admission as a Substituted Limited Partner and as a party to the Partnership Agreement, (d) gives the powers of attorney provided for in the Partnership Agreement, and (e) makes the waivers and gives the consents and approvals contained in the Partnership Agreement.  Capitalized terms not defined herein have the meanings assigned to such terms in the Partnership Agreement.

Date: ____________________

Social Security or other identifying number of Assignee	Signature of Assignee
Purchase Price including commissions, if any:	Name and Addressee of Assignee

A-4

Type of Entity (check one):

☐ Individual	☐ Partnership	☐ Other
☐ Trust	☐Corporation

Nationality (check one):

☐ U.S. Citizen, Resident or Domestic
Entity

☐ Foreign Corporation

☐ Non-Resident Alien

If the U.S. Citizen, Resident or Domestic Entity box is checked, the following certification must be completed.

Under Section 1445(e) of the Internal Revenue Code of 1986, as amended (the “CODE”), the Partnership must withhold tax with respect to certain transfers of property if a holder of an interest in the Partnership is a foreign person.  To inform the Partnership that no withholding is required with respect to the undersigned interestholder’s interest in it, the undersigned hereby certifies the following (or, if applicable, certifies the following on behalf of the interestholder).

A-5

Complete Either A or B:

A.  Individual Interestholder
1.   I am not a non-resident alien for purposes of U.S. income taxation.
2.   My U.S. taxpayer identification number (Social Security Number) is:	______________________________
3.   My home address is:	______________________________ ______________________________ ______________________________
B.   Partnership, Corporation or Other Interestholder
1.   The Interestholder is not a foreign corporation, foreign partnership, foreign trust or foreign estate (as those terms are defined in the Code and Treasury Regulations).	______________________________ (Name of Interestholder)
2.   The Interestholder’s U.S. employer identification number is:	______________________________
3.   The Interestholder’s office address and place of incorporation (if applicable) is:	______________________________ ______________________________ ______________________________

The Interestholder agrees to notify the Partnership within sixty (60) days of the date the interestholder becomes a foreign person.

The interestholder understands that this certificate may be disclosed to the Internal Revenue Service by the Partnership and that any false statement contained herein could be punishable by fine, imprisonment or both.

Under penalties of perjury, I declare that I have examined this certification and to the best of my knowledge and belief it is true, correct and complete and, if applicable, I further declare that I have authority to sign this document on behalf of:

	Signature
Dated: _______________
	Name of Interestholder
	Title (if applicable)

A-6

Note: If the Assignee is a broker, dealer, bank, trust company, clearing corporation, other nominee holder or an agent of any of the foregoing, and is holding for the account of any other person, this application should be completed by an officer thereof or, in the case of a broker or dealer, by a registered representative who is a member of a registered national securities exchange or a member of the National Association of Securities Dealers, Inc., or, in the case of any other nominee holder, a person performing a similar function.  If the Assignee is a broker, dealer, bank, trust company, clearing corporation, other nominee owner or an agent of any of the foregoing, the above certification as to any person for whom the Assignee will hold the Common Units shall be made to the best of the Assignee’s knowledge.

A-7

EXHIBIT B

TO

FOURTH AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

TC PIPELINES, LP

CLASS B UNIT SUPPLEMENT

This Class B Unit Supplement to the Fourth Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP (the “AGREEMENT”) is effective as of the Class B Issuance Date.

Section 1.1 of the Agreement provides that the Partnership may issue additional Partnership Securities for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as shall be established by the General Partner in its sole discretion, all without the approval of any Limited Partners.

Pursuant to the General Partner’s determination, the Partnership is establishing a new class of Units designated as “Class B Units” and is issuing 1,900,000 Class B Units to TransCanada American Investments Ltd. as of the Class B Issuance Date pursuant to the PSA.

The following provisions shall apply with respect to the Class B Units, notwithstanding anything to the contrary in the Agreement, and this Supplement is intended to be incorporated into the Agreement:

1.         Defined Terms Generally.  Capitalized terms used in this Supplement but not defined herein shall have the meanings ascribed to such terms in the Agreement.

2.         Supplement Defined Terms.  With respect to the Class B Units, the capitalized terms below shall have the following meanings:

“CLASS B DISTRIBUTION” means the amount distributable annually to the Class B Unitholders in respect of their Class B Units, calculated as follows:

(A)       For the partial year commencing on the Class B Issuance Date and ending December 31, 2015, an amount equal to (I) 30% of the GTN Distributable Cash Flow during such period, less (II) $15 million.

(B)       For each of the calendar years 2016 through 2019, an amount equal to (I) 30% of the GTN Distributable Cash Flow during such year, less (II) $20 million.

(C)       For the calendar year 2020, an amount equal to (I) 43.75% of (II) (x) 30% the GTN Distributable Cash Flow during such year, less (y) $20 million.

(D)       For each of the calendar years after 2020, an amount equal to (I) 25% of (II)(x) 30% of the GTN Distributable Cash Flow during such year, less (y) $20 million reduced by the Class B Reduction (if any) for such year.

B-1

“CLASS B ISSUANCE DATE” means April 1, 2015, or if the “Closing Date,” as defined in the PSA, occurs on a different date, such Closing Date.

“CLASS B UNIT LIQUIDATION VALUE” means the fair market value of the Class B Units determined immediately prior to the occurrence of liquidation pursuant to Section 12.4 of the Agreement.

“CLASS B REDUCTION” means, for any particular calendar year, the percentage (if any) by which distributions payable in respect of Common Units for such calendar year are less than the maximum distributions paid in respect of Common Units for any calendar year beginning on or after January 1, 2014.

“CLASS B UNITS” means 1,900,000 Class B Units issued as of the Class B Issuance Date.

“GTN DISTRIBUTABLE CASH FLOW” means an amount, determined in accordance with U.S. GAAP on a stand-alone basis for any calendar year (or partial calendar year), equal to GTN’s net income for the applicable period, increased by GTN’s (a) depreciation expenses and (b) amortization of regulatory assets, and decreased by GTN’s (x) amortization of regulatory liabilities, (y) allowance for funds used during construction, and (z) maintenance capital expenditures during such period, to be, and to the extent, distributed by GTN directly or indirectly to the Partnership in a manner consistent with the GTN Distribution Policy and historical practice prior to the date of a distribution to the Class B Unitholders.

“GTN DISTRIBUTION POLICY” means the GTN cash distribution policy dated October 25, 2011, in effect as of February 24, 2015.

“PRO RATA” means, with respect to the Class B Unitholders and their Assignees, proportionately based on the number of Class B Units held by them, respectively.

“PSA” means that certain Agreement for Purchase and Sale of Membership Interest dated as of February 24, 2015 by and among the Partnership and TransCanada American Investments Ltd.

“SIGNIFICANT EVENT” means (i) a sale or other disposition by the Partnership or its Affiliate of all or substantially all of its membership interests in GTN or (ii) a sale or other disposition of all or substantially all of the assets owned by GTN.

“SUPPLEMENT” means this Class B Unit Supplement dated April 1, 2015.

3.         Initial Capital Accounts of Class B Units.  The initial Capital Account balance in respect of each Class B Unit shall be $50.00, as more particularly described in the PSA.

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4.         Allocations.

(a)        Except as provided in Sections 4(b), 4(c) and 10 of this Supplement and Section 6.1(d)(xiii) of the Agreement, the Class B Unitholders shall not be allocated any Net Income, Net Loss, Net Termination Gain, Net Termination Loss or other “BOOK” items pursuant to terms of Section 6.1 or corresponding tax items pursuant to terms of Section 6.2 in respect of its Class B Units.

(b)        The Class B Unitholders shall be allocated items of “BOOK” gross income as provided in Section 6.1(d)(v) of the Agreement and corresponding tax items under Section 6.2(a) of the Agreement.  In addition, the Class B Unitholders shall be allocated taxable income, gain or loss under Section 6.2(b)(i) of the Agreement as required by Section 704(c) of the Code.

(c)        Solely for Canadian income tax purposes, the Class B Unitholders shall be allocated the amounts as provided in Section 6.2(i) of Agreement.

5.         Distributions.  The General Partner shall distribute the Class B Distribution Amount in accordance with this Section 5 of the Supplement and the Agreement.  The Class B Distribution amount for each year shall be distributed to the Class B Unitholders at the same time as the first quarterly distribution is made to the Common Unitholders after the end of such year.  Such distribution shall be made Pro Rata among the Class B Unitholders as of the Record Date for such distribution.  Each Record Date established pursuant to this Section 5 for distribution in respect of the Class B Units shall be the same Record Date established for any distribution to be made by the Partnership in respect of the Common Units during the first Quarter of the applicable taxable year.  For the avoidance of doubt, no distribution shall be payable in respect of the Incentive Distribution Rights under Section 6.4 or 6.5 by virtue of the distribution of the Class B Unit Distribution amounts.

6.         Significant Event.  Without restricting the powers of the General Partner under Section 7.1 of the Agreement, a Significant Event shall also require Special Approval.  The General Partner shall not cause a Significant Event to occur without prior Special Approval.

7.         Transfers of Class B Units.  No transfer of a Class B Unit shall be made without prior Special Approval except for (i) transfers to the transferor’s Affiliates, or (ii) transfers to Persons who are not Affiliates in connection with the transfer by the General Partner of all of the General Partner Interests held by the General Partner.

8.         Splits and Combinations.  Notwithstanding Section 5.10(a) of the Agreement, the Class B Unitholders shall not be entitled to receive any Partnership Securities other than Class B Units under Section 5.10(a), and no Class B Units shall be distributed to Record Holders other than the Class B Unitholders.

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9.         Voting Rights.  Except as provided by law or Section 13.3 of the Agreement, the Class B Unitholders shall have no voting rights in respect of their Class B Units except that any amendment of the Agreement, including this Supplement, that would have an adverse effect on the Class B Unitholders disproportionate to the effect on other Partnership Securities shall require the approval of a majority in interest of the Class B Unitholders.

10.       Special Allocation Upon Liquidation to Class B Units.  Immediately prior to making any distribution of cash or property to the Partners pursuant to Section 12.4 of the Agreement, items of Net Income or Net Termination Gain shall be allocated among the Class B Unitholders in a manner that, to the nearest extent possible, results in the Capital Accounts of Class B Unitholders in respect of their Class B Units to equal their respective Pro Rata shares of Class B Unit Liquidation Value immediately prior to such distribution.

B-4

EX-4.7

Exhibit 4.7

DESCRIPTION OF THE REGISTRANT’S SECURITIES

REGISTERED PURSUANT TO SECTION 12 OF THE

SECURITIES EXCHANGE ACT OF 1934

As of February 20, 2020, TC PipeLines, LP has one class of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”): our common units. For purposes of these descriptions, references to “the Partnership,” “we,” “our” and “us” refer only to TC PipeLines, LP and not to its subsidiaries.

Common Units

The common units represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units in and to partnership distributions, please read “Cash Distribution Policy.” For a description of the rights and privileges of limited partners under our Fourth Amended and Restated Agreement of Limited Partnership, as amended (the “Partnership Agreement”), including voting rights, please read “Description of Our Partnership Agreement.”

Transfer of Common Units

Upon the transfer of a common unit in accordance with our Partnership Agreement, the transferee of the common unit shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

(1)   represents that the transferee has the capacity, power and authority to become bound by our Partnership Agreement;

(2)   automatically becomes bound by the terms and conditions of our Partnership Agreement; and

(3)   gives the consents, waivers and approvals contained in our Partnership Agreement.

TC PipeLines GP Inc. (our “General Partner”) will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Number of Common Units

As of February 19, 2020, we had 71,306,396 common units outstanding. Our outstanding common units are listed on the NYSE under the symbol “TCP.”

CASH DISTRIBUTION POLICY

General

We will make distributions to our partners for each of our fiscal quarters before liquidation in an amount equal to all of our Available Cash for that quarter. Available Cash is defined in our Partnership Agreement and generally means, with respect to any quarter of the Partnership, all cash on hand at the end of such quarter less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of the General Partner to:

      provide for the proper conduct of our business (including reserves for future capital expenditures and for anticipated credit needs);

      comply with applicable laws or any of our debt instruments or agreements; or

      provide funds for cash distributions to unitholders and the General Partner in respect of any one or more of the next four quarters; and

      provide funds for cash distributions to Class B unitholders.

We expect to make distributions of all Available Cash within approximately 45 days after the end of each calendar quarter to holders of record on the applicable record date.

Operating Surplus and Capital Surplus

Cash distributions will be characterized as distributions from either Operating Surplus or Capital Surplus. This distinction affects the amounts distributed to unitholders relative to the General Partner. See “—Distributions from Capital Surplus” below.

Operating Surplus generally means:

(1)   our cash balance on the date we began operations, plus $20 million, plus all of our cash receipts from our operations, excluding cash constituting Capital Surplus; less

(2)   all of our operating expenses, debt service payments, maintenance, capital expenditures and reserves established for future operations.

Capital Surplus will generally be generated only by:

(1)   borrowings other than Working Capital Borrowings (as defined in the Partnership Agreement);

(2)   sales of debt and equity securities; and

(3)   sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

All Available Cash distributed from any source will be treated as distributed from Operating Surplus until the sum of all Available Cash distributed since we began operations equals the Operating Surplus as of the end of the quarter before that distribution. This method of cash distribution avoids the difficulty of trying to determine whether Available Cash is distributed from Operating Surplus or Capital Surplus. Any excess of Available Cash over Operating Surplus, irrespective of its source, will be treated as Capital Surplus.

Capital Surplus is first distributed 98% to all common units, pro rata, and 2% to the General Partner until each common unit that was issued in our initial public offering has received distributions from Capital Surplus in an aggregate amount equal to the initial public offering price of the common units. After these distributions have been made the distinction between Operating Surplus and Capital Surplus will cease. All subsequent distributions will be

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treated as from Operating Surplus. See “—Distributions from Capital Surplus” below. We do not anticipate that there will be significant distributions of Capital Surplus.

Distributions of Available Cash from Operating Surplus

Distributions of Available Cash from Operating Surplus for any quarter will be made in the following manner:

      First, 98% to the common units, pro rata, and 2% to the General Partner, until there has been distributed for each outstanding common unit an amount equal to $0.81 per unit for that quarter (the “First Target Distribution”); provided that during the calendar year 2020, the Class B units entitle TC Energy to a distribution based on (I) 43.75% of (II) (x) 30% of the distributable cash flow of Gas Transmission Northwest, LLC (“GTN”) (to the extent distributed by GTN) during 2020 less (y) $20 million; for each of the calendar years after 2020, the Class B units entitle TC Energy to a distribution of based on (I) 25% of (II) (x) 30% of GTN's distributable cash flow (to the extent distributed by GTN), less (y) $20 million (which amount may be reduced by the percentage by which the distributions payable in respect of common units during such calendar year are less than distributions paid in respect of any year beginning on or after January 1, 2014); and

      Thereafter, in the manner described in “—Incentive Distribution Rights” below.

The above reference to 2% of Available Cash from Operating Surplus distributed to the General Partner is a reference to the percentage interest of the General Partner in distributions from the Partnership, exclusive of the General Partner’s or any of its affiliates’ interest as holders of the units or incentive distribution rights (“IDRs”). The General Partner owns a 2% general partner interest in the Partnership.

Incentive Distribution Rights

IDRs represent the right to receive an increasing percentage of quarterly distributions of Available Cash from Operating Surplus after the First Target Distribution and the related 2% distribution to the General Partner have been made for any quarter.

Any Available Cash from Operating Surplus for a quarter in excess of the First Target Distribution and the related 2% distribution to the General Partner will be distributed among the unitholders and the General Partner in the following manner:

      First, 85% to all units, pro rata, and 15% to the General Partner, until each unitholder has received a total of $0.88 for that quarter (the “Second Target Distribution”); and

      Thereafter, 75% to all units, pro rata, and 25% to the General Partner.

The distributions to the General Partner described above, other than in its capacity as a holder of units, that are in excess of its aggregate 2% general partner interest represent the IDRs. The right to receive incentive distributions is not part of the general partner interest and may be transferred separately from that interest.

The General Partner may at any time transfer its common units and its IDRs to one or more persons without unitholder approval. As a condition to the transfer, the transferee must assume the rights and duties of the General Partner to whose interest that transferee has succeeded, agree to be bound by the provisions of the Partnership Agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Distributions from Capital Surplus

Distributions of Available Cash from Capital Surplus will be made in the following manner:

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      First, 98% to all units, pro rata, and 2% to the General Partner, until each common unit that was issued in our initial public offering has received distributions from Capital Surplus equal to the initial public offering price; and

      Thereafter, all distributions of Available Cash from Capital Surplus will be distributed as if they were from Operating Surplus.

When a distribution is made from Capital Surplus, it is treated as if it were a repayment of the unit price from our initial public offering. To reflect this repayment, the minimum quarterly distribution ($0.45 per quarter) and the target distribution levels will be adjusted downward by multiplying each amount by a fraction. This fraction is determined as follows:

      the numerator is the initial public offering price, less distributions of Capital Surplus (the “Unrecovered Capital”) with respect to the common units immediately after giving effect to the repayment; and

      the denominator is the Unrecovered Capital of the common units immediately before the repayment.

A “payback” of the unit price from our initial public offering occurs when the Unrecovered Capital of the common units is zero. At that time the minimum quarterly distribution and the target distribution levels will have been reduced to zero. All distributions of Available Cash from all sources after that time will be treated as if they were from Operating Surplus. Because the target distribution levels will have been reduced to zero, the General Partner will then be entitled to receive 75% of all distributions of Available Cash in its capacities as General Partner and as holder of the IDRs, in addition to any distributions to which it may be entitled as a holder of units.

Distributions from Capital Surplus will not reduce the target distribution levels for the quarter in which they are distributed.

Adjustment of Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjustments made upon a distribution of Available Cash from Capital Surplus, the following will each be proportionately adjusted upward or downward, as appropriate, if any combination or subdivision of units should occur:

(1)   the minimum quarterly distribution;

(2)   the target distribution levels;

(3)   the Unrecovered Capital of a common unit; and

(4)   other amounts calculated on a per unit basis.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the Unrecovered Capital of the common units would each be reduced to 50% of its initial level.

No adjustment will be made by reason of the issuance of additional common units for cash or property.

The minimum quarterly distribution and the target distribution levels may also be adjusted if legislation is enacted or if existing law is modified or interpreted in a manner that causes of the Partnership and any majority owned subsidiary of the Partnership to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In this event, the minimum quarterly distribution and the target distribution levels for each quarter after that time, may, at the General Partner’s discretion, be reduced to an amount that is not less than the amount equal to the product obtained by multiplying:

(1)   the minimum quarterly distribution and each of the target distribution levels (as applicable);

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by

(2)   one minus the sum of:

(x)   the highest marginal federal income tax rate (expressed as a decimal) which could apply to the Partnership or any majority owned subsidiary of the Partnership that is taxed as an entity; plus

(y)   any increase in the effective overall state and local income tax rate (expressed as a decimal) that would have been applicable to the Partnership or any majority owned subsidiary of the Partnership in the preceding calendar year as a result of the new imposition of the entity level tax, after taking into account the benefit of any deduction allowable for federal income tax purposes for the payment of state and local income taxes, but only to the extent of the increase in rates resulting from that legislation or interpretation.

Distributions of Cash Upon Liquidation

Following the beginning of our dissolution and liquidation, assets will be sold or otherwise disposed of and the partners’ capital account balances will be adjusted to reflect any resulting gain or loss. The manner of the adjustment is as provided in the Partnership Agreement. The proceeds of liquidation will first be applied to the payment of our creditors in the order of priority provided in the Partnership Agreement and by law. After that, the proceeds will be distributed to the unitholders and the General Partner in accordance with their capital account balances, as so adjusted.

Net gains recognized upon liquidation will be allocated first to restore negative balances in the capital account of the General Partner and the unitholders. Then net gains will be allocated 98% to the unitholders and 2% to the General Partner until the capital account balances of the unitholders are equal to their Unrecovered Capital plus any First Target Distribution for the quarter during which the liquidation date occurs. However, no assurance can be given that there will be sufficient gain upon liquidation of the Partnership to enable the holders of common units to fully recover all of these amounts. Any further net gains recognized upon liquidation will be allocated in a manner that takes into account the IDRs of the General Partner.

Any unrealized gain attributable to assets distributed in kind will be allocated in a manner consistent with the allocation of net recognized gains described above.

Upon our liquidation, any loss will generally be allocated to the General Partner and the unitholders in the following manner:

· First, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the General Partner, until the capital accounts of the common unitholders have been reduced to zero; and

· Thereafter, 100% to the General Partner.

Interim adjustments to capital accounts will be made at the time we issue additional interests in the Partnership or make distributions of property. These adjustments will be based on the fair market value of the interests issued or the property distributed and any gain or loss resulting from the adjustments will be allocated to the unitholders and the General Partner (including with respect to its IDRs) in the same manner as gain or loss would be allocated upon liquidation. In the event that positive interim adjustments are made to the capital accounts, any later negative adjustments to the capital accounts resulting from the issuance of additional Partnership interests, our distributions of property, or losses upon sales of assets in our liquidation, will be allocated in a manner, as reasonably determined by the General Partner, that to the extent possible result in the capital counts of the partners being equal the capital accounts of the partners if no earlier positive adjustments to the capital accounts had been made.

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DESCRIPTION OF OUR PARTNERSHIP AGREEMENT

The following is a summary of the certain material provisions of our Partnership Agreement that relate to ownership of our common units.

Voting Rights

The following is a summary of the common unitholder vote required for approval of the matters specified below. Matters that call for the approval of a “unit majority” require the approval of a majority of the common units.

In voting their common units, our general partner and its affiliates have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners.

The incentive distribution rights may be entitled to vote in certain circumstances.

Issuance of additional units	No approval right.
Amendment of the partnership agreement	Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets	Unit majority in certain circumstances. Please read “—Merger, Sale or Other Disposition of Assets.”
Dissolution of our partnership	Unit majority. Please read “—Termination and Dissolution.”
Continuation of our business upon dissolution	Unit majority. Please read “—Termination and Dissolution.”
Withdrawal of our general partner	No approval right. Please read “—Withdrawal or Removal of Our General Partner.”
Removal of our general partner	Not less than 66 2/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.”
Transfer of our general partner interest	No approval right.
Transfer of incentive distribution rights	No approval right.

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and otherwise acts in conformity with the provisions of the Partnership Agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by the limited partners as a group:

· to remove or replace the General Partner;

· to approve some amendments to the Partnership Agreement; or

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· to take other action under the Partnership Agreement

constituted “participation in control” of our business for purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware to the same extent as the General Partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the Partnership, exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the Partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and which could not be ascertained from the Partnership Agreement.

Issuance of Additional Securities

The Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for the consideration and on the terms and conditions established by the General Partner in its sole discretion without the approval of any limited partners.

We may issue an unlimited number of common units as follows:

(1)   issuance under employee and director benefit plans (subject to any approval requirements of the NYSE);

(2)   upon conversion of the general partner interests and IDRs as a result of a withdrawal of the General Partner; or

(3)   in the event of a combination or subdivision of common units.

It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of Available Cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of the Partnership Agreement, we may also issue additional partnership securities that, in the sole discretion of the General Partner, may have special voting rights to which the common units are not entitled.

Upon issuance of additional partnership securities in exchange for cash or property, the General Partner will be required to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Moreover, the General Partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than the General Partner and its affiliates, to the extent necessary to maintain their percentage interest, including their interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

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Amendment of Partnership Agreement

Amendments to the Partnership Agreement may be proposed only by or with the consent of the General Partner, which consent may be given or withheld in its sole discretion. In order to adopt a proposed amendment, other than the amendments discussed below, the General Partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment except as described below.

Prohibited Amendments. No amendment may be made that would:

(1)   enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected;

(2)   enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by the Partnership to the General Partner or any of its affiliates without its consent, which may be given or withheld in its sole discretion;

(3)   change the term of the Partnership;

(4)   provide that the Partnership is not dissolved upon the expiration of its term or upon an election to dissolve the Partnership by the General Partner that is approved by the holders of a majority of the outstanding common units; or

(5)   give any person the right to dissolve the Partnership other than the General Partner’s right to dissolve the Partnership with the approval of the holders of a majority of the outstanding common units.

The provision of the Partnership Agreement preventing the amendments having the effects described in clauses (1)-(5) above can be amended upon the approval of the holders of at least 90% of the outstanding units.

No Unitholder Approval. The General Partner may generally make amendments to the Partnership Agreement without the approval of any limited partner or assignee to reflect:

(1)   a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent or the registered office of the Partnership;

(2)   the admission, substitution, withdrawal or removal of partners in accordance with the Partnership Agreement;

(3)   a change that, in the sole discretion of the General Partner, is necessary or advisable to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that the Partnership will not be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

(4)   an amendment that is necessary, in the opinion of counsel to the Partnership, to prevent the Partnership or the General Partner or its directors, officers, agents or trustees, from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended (“ERISA”) whether or not substantially similar to plan asset regulations currently applied or proposed;

(5)   an amendment that in the discretion of the General Partner is necessary or advisable for the authorization or issuance of additional limited or general partner interests;

(6)   any amendment expressly permitted in the Partnership Agreement to be made by the General Partner acting alone;

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(7)   an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the Partnership Agreement;

(8)   any amendment that, in the discretion of the General Partner, is necessary or advisable for the formation by the Partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by the Partnership Agreement;

(9)   a change in the fiscal year or taxable year of the Partnership and related changes; and

(10) any other amendments substantially similar to any of the matters described in (1)-(9) above.

In addition, the General Partner may make amendments to the Partnership Agreement without the approval of any limited partner or assignee if those amendments, in the discretion of the General Partner:

(1)   do not adversely affect the limited partners in any material respect;

(2)   are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

(3)   are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, compliance with any of which the General Partner deems to be in the best interests of the Partnership and the limited partners;

(4)   are necessary or advisable for any action taken by the General Partner relating to splits or combinations of units under the provisions of the Partnership Agreement; or

(5)   are required to effect the intent of the provisions of the Partnership Agreement or are otherwise contemplated by the Partnership Agreement.

Opinion of Counsel and Unitholder Approval. The General Partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in the Partnership being treated as an entity for federal income tax purposes if one of the amendments described above under “—No Unitholder Approval” should occur. No other amendments to the Partnership Agreement will become effective without the approval of holders of at least 90% of the units unless the Partnership obtains an opinion of counsel to the effect that the amendment will not adversely affect the limited liability under applicable law of any limited partner in the Partnership or cause the Partnership to be taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously taxed as such).

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

The General Partner is generally prohibited, without the prior approval of holders of a majority of the outstanding common units from causing the Partnership to, among other things, sell, exchange or otherwise dispose of all or substantially all of its assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination; provided that the General Partner may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the Partnership’s assets without that approval. The General Partner may also sell all or substantially all of the Partnership’s assets under a foreclosure or other realization upon the encumbrances above without that approval. Furthermore, provided that conditions specified in the Partnership Agreement are satisfied, the General Partner may merge the Partnership or any of its subsidiaries into, or convey some or all of their assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect solely a change in the legal form of the Partnership into another limited liability entity.

9

The unitholders are not entitled to dissenters’ rights of appraisal under the Partnership Agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of the Partnership’s assets or any other transaction or event.

Termination and Dissolution

We will continue until December 31, 2097, unless terminated sooner under the Partnership Agreement. We will dissolve upon:

(1)   the election of the General Partner to dissolve us, if approved by the holders of a majority of the outstanding common units;

(2)   the sale, exchange or other disposition of all or substantially all of the assets and properties of the Partnership;

(3)   the entry of a decree of judicial dissolution of the Partnership; or

(4)   the withdrawal or removal of the General Partner or any other event that results in its ceasing to be the General Partner other than by reason of a transfer of its general partner interest in accordance with the Partnership Agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under clause (4), the holders of a majority of the outstanding common units may also elect, within specific time limitations, to reconstitute the Partnership and continue its business on the same terms and conditions described in the Partnership Agreement by forming a new limited partnership on terms identical to those in the Partnership Agreement and having as General Partner an entity approved by the holders of units who elected to reconstitute the Partnership subject to receipt by the Partnership of an opinion of counsel to the effect that:

(1)   the action would not result in the loss of limited liability of any limited partner; and

(2)   neither the Partnership nor the reconstituted limited partnership would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of the General Partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets and apply the proceeds of the liquidation as provided in “Cash Distribution Policy—Distributions of Cash Upon Liquidation”. The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Withdrawal or Removal of the General Partner

The General Partner of the Partnership may withdraw as the General Partner without first obtaining approval from any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of the Partnership Agreement. In addition, the Partnership Agreement permits the General Partner in some instances to sell or otherwise transfer all of its general partner interests in the Partnership without the approval of the unitholders.

Upon the withdrawal of the General Partner under any circumstances, other than as a result of a transfer by the General Partner of all or a part of its general partner interests in the Partnership, the holders of a majority of the outstanding common units may select a successor to that withdrawing General Partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, the Partnership will be dissolved, wound up and liquidated, unless within 180 days after that withdrawal the holders of a majority of the outstanding common units agree in writing to continue the business of the Partnership and to appoint a successor general partner. See “—Termination and Dissolution” above.

10

The General Partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, including units held by the General Partner and its affiliates, and the Partnership receives an opinion of counsel regarding limited liability and tax matters. Any removal of this kind is also subject to the approval of a successor General Partner by the vote of the holders of a majority of the outstanding common units.

The Partnership Agreement also provides that if the General Partner is removed as General Partner of the Partnership under circumstances where cause does not exist the General Partner will have the right to convert its general partner interests and all the IDRs into common units or to receive cash in exchange for those interests from the successor General Partner.

In the event of removal of the General Partner under circumstances where cause exists or withdrawal of the General Partner where that withdrawal violates the Partnership Agreement, a successor General Partner will have the option to purchase the general partner interests and IDRs of the departing General Partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where the General Partner withdraws or is removed by the limited partners, the departing General Partner will have the option to require the successor General Partner to purchase the general partner interests of the departing General Partner and its IDRs for a cash payment equal to the fair market value of those interests. In each case, this fair market value will be determined by agreement between the departing General Partner and the successor General Partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing General Partner and the successor General Partner will determine the fair market value. If the departing General Partner and the successor General Partner cannot agree upon an expert to determine the fair market value, then an expert chosen by agreement of experts selected by each of them will determine the fair market value.

If the above-described option is not exercised by either the departing General Partner or the successor General Partner, the departing General Partner’s general partner interests and its IDRs will automatically convert into common units equal to the fair market value of those interests, as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, the Partnership will be required to reimburse the departing General Partner for all amounts due the departing General Partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing General Partner for the benefit of the Partnership.

TC Energy Ownership of General Partner

TC Energy will retain beneficial ownership of our General Partner until six months after the date when there are no officers of our General Partner who are also directors, officers or employees of TC Energy or its other affiliates.

Change of Management Provisions

The Partnership Agreement contains specific provisions that are intended to discourage a person or group from attempting to remove the General Partner of the Partnership as General Partner of the Partnership or otherwise change management. If any person or group other than the General Partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our General Partner or its affiliates and any transferees of that person or group approved by our General Partner.

The Partnership Agreement also provides that if the General Partner is removed under circumstances where cause does not exist and units held by the General Partner and its affiliates are not voted in favor of that removal, the General Partner will have the right to convert its general partner interests and all of its IDRs into common units or to receive cash in exchange for those interests.

11

Limited Call Right

If at any time the General Partner and its affiliates hold at least 80% of the then-issued and outstanding partnership securities of any class, the General Partner will have the right, but not the obligation, which it may assign in whole or in part to any of its affiliates or to the Partnership, to acquire all, but not less than all, of the remaining partnership securities of the class held by unaffiliated persons as of a record date to be selected by the General Partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of: (i) the highest price paid by either of the General Partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which the General Partner first mails notice of its election to purchase those partnership securities; and (ii) the current market price as of the date three days before the date the notice is mailed. For this purpose, the “current market price” of any publicly traded class of securities listed or admitted to trading on a national securities exchange is the average of the daily closing prices for the 20 consecutive trading days immediately prior to such date.

As a result of the General Partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market.

Status as Limited Partner or Assignee

Except as described above under “—Limited Liability”, the common units will be fully paid, and unitholders will not be required to make additional contributions.

An assignee of a common unit, after executing and delivering a transfer application, but pending its admission as a substituted limited partner, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from the Partnership, including liquidating distributions. The General Partner will vote and exercise other powers attributable to common units owned by an assignee who has not become a substitute limited partner at the written direction of the assignee. See “—Meetings; Voting”. Transferees who do not execute and deliver a transfer application will be treated neither as assignees nor as record holders of common units, and will not receive cash distributions, federal income tax allocations or reports furnished to record holders of common units. See “Transfer of Common Units”.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of the General Partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem the units held by the limited partner or assignee at their current market price. In order to avoid any cancellation or forfeiture, the General Partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about this nationality, citizenship or other related status within 30 days after a request for the information or the General Partner determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

12

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF THE REGISTRANT

1. The Registrant holds a 46.45 percent general partner interest in Great Lakes Gas Transmission Limited Partnership, a Delaware limited partnership.

2. The Registrant holds a 50 percent general partner interest in Northern Border Pipeline Company, a Texas general partnership.

3. The Registrant wholly-owns Gas Transmission Northwest LLC, a Delaware limited liability company.

4. The Registrant wholly-owns Bison Pipeline LLC, a Delaware limited liability company.

5. The Registrant wholly-owns North Baja Pipeline, LLC, a Delaware limited liability company.

6. The Registrant holds a 61.71 percent general partner interest in Portland Natural Gas Transmission System, a Maine general partnership.

7. The Registrant holds a 25 percent general partner interest and 24.34 percent limited partner interest in Iroquois Gas Transmission System, L.P, a Delaware limited partnership.

8. The Registrant wholly-owns TC PipeLines Tuscarora LLC, a Delaware limited liability company.

9. Through its interest TC PipeLines Tuscarora LLC, the Registrant wholly-owns Tuscarora Gas Transmission Company, a Nevada general partnership, through its directly held 99 percent general partner interest and indirectly held one percent general partner interest through its wholly-owned subsidiary, TC PipeLines Tuscarora LLC.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of TC PipeLines GP, Inc.

General Partner of TC PipeLines, LP:

We consent to the incorporation by reference in the registration statement (No. 333‑236291) on Form S‑3 of TC PipeLines, LP of our report dated February 20, 2020, with respect to the consolidated balance sheets of TC PipeLines, LP as of December 31, 2019 and 2018, and the related consolidated statements of operations, comprehensive income (loss), changes in partners’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2019, and the related notes (collectively, the “consolidated financial statements”), and the effectiveness of internal control over financial reporting as of December 31, 2019, which report appears in the December 31, 2019 annual report on Form 10‑K of TC PipeLines, LP.

/s/ KPMG LLP

Houston, Texas

February 20, 2020

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of TC PipeLines GP, Inc.

General Partner of TC PipeLines, LP:

We consent to the incorporation by reference in the registration statement (No. 333‑236291) on Form S‑3 of TC PipeLines, LP of our report dated February 14, 2020, with respect to the balance sheets of Northern Border Pipeline Company as of December 31, 2019 and 2018, and the related statements of income, comprehensive income, changes in partners’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2019, and the related notes (collectively, the “financial statements”), which report appears in the December 31, 2019 annual report on Form 10‑K of TC PipeLines, LP.

/s/ KPMG LLP

Houston, Texas

February 20, 2020

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of TC PipeLines GP, Inc.

General Partner of TC PipeLines, LP:

We consent to the incorporation by reference in the registration statement (No. 333‑236291) on Form S‑3 of TC PipeLines, LP of our report dated February 14, 2020, with respect to the balance sheets of Great Lakes Gas Transmission Limited Partnership as of December 31, 2019 and 2018, and the related statements of income and partners’ capital, and cash flows for each of the years in the three‑year period ended December 31, 2019, and the related notes (collectively, the “financial statements”), which report appears in the December 31, 2019 annual report on Form 10‑K of TC PipeLines, LP.

/s/ KPMG LLP

Houston, Texas

February 20, 2020

EX-23.4

Exhibit 23.4

CONSENT OF INDEPENDENT PUBLIC ACCOUNTING FIRM

The Board of Directors

TC PipeLines GP, Inc., General Partner of TC PipeLines, LP:

We consent to the incorporation by reference in the registration statement (No. 333‑236291) on Form S‑3 of TC PipeLines, LP of our report dated February 19, 2020, with respect to the consolidated balance sheets of Iroquois Gas Transmission System, L.P., and its subsidiaries as of December 31, 2019 and 2018, and the related consolidated statements of comprehensive income, changes in partners’ equity and cash flows for each of the years in the three‑year period ended December 31, 2019, and the related notes to the consolidated financial statements (collectively, the financial statements), which report appears in the December 31, 2019 annual report on Form 10‑K of TC Pipelines, LP.

/s/ Blum, Shapiro & Company, P.C.

West Hartford, Connecticut

February 20, 2020

EX-31.1

Exhibit 31.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

I, Nathaniel A. Brown, certify that:

1.          I have reviewed this annual report on Form 10‑K of TC PipeLines, LP (the “registrant”);

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

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

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

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

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

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

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

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

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

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

Dated: February 20, 2020	/s/ Nathaniel A. Brown
	Nathaniel A. Brown
	Principal Executive Officer and President
	TC PipeLines GP, Inc., as General Partner of
	TC PipeLines, LP

EX-31.2

Exhibit 31.2

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

I, William C. Morris, certify that:

1.          I have reviewed this annual report on Form 10‑K of TC PipeLines, LP (the “registrant”);

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

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

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

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

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

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

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

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

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

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

Dated: February 20, 2020	/s/ William C. Morris
	William C. Morris
	Principal Financial Officer, Vice President and
	Treasurer
	TC PipeLines GP, Inc., as General Partner of
	TC Pipelines, LP

EX-32.1

Exhibit 32.1

CERTIFICATION OF

PRINCIPAL EXECUTIVE OFFICER

I, Nathaniel A. Brown, Principal Executive Officer and President of TC PipeLines GP, Inc., the General Partner of TC PipeLines, LP (the Partnership), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002 hereby certify, to the best of my knowledge, in connection with the Partnership’s Annual Report on Form 10‑K for the period ended December 31, 2019 as filed with the Securities and Exchange Commission (the Report) on the date hereof, that:

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

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

Dated: February 20, 2020	/s/ Nathaniel A. Brown
	Nathaniel A. Brown
	Principal Executive Officer and President
	TC PipeLines GP, Inc., as General Partner of
	TC PipeLines, LP

EX-32.2

Exhibit 32.2

CERTIFICATION OF

PRINCIPAL FINANCIAL OFFICER

I, William C. Morris, Principal Financial Officer and Controller of TC PipeLines GP, Inc., the General Partner of TC PipeLines, LP (the Partnership), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002 hereby certify, to the best of my knowledge, in connection with the Partnership’s Annual Report on Form 10‑K for the period ended December 31, 2019 as filed with the Securities and Exchange Commission (the Report) on the date hereof, that:

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

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

Dated: February 20, 2020	/s/ William C. Morris
	William C. Morris
	Principal Financial Officer, Vice President and
	Treasurer
	TC PipeLines GP, Inc., as General Partner of
	TC PipeLines, LP

EX-99.1

Exhibit 99.1

Contract ID.: FT18311 Amendment No: 3 FORM OF TRANSPORTATION SERVICE AGREEMENT This Transportation Service Agreement (Agreement) is entered into by Great Lakes Gas Transmission Limited Partnership (Transporter) and TransCanada PipeLines Limited (Shipper). WHEREAS, Shipper has requested Transporter to transport Gas on its behalf and Transporter represents that it is willing to transport Gas under the terms and conditions of this Agreement. NOW, THEREFORE, Transporter and Shipper agree that the terms below constitute the transportation service to be provided and the rights and obligations of Shipper and Transporter. 1. EFFECTIVE DATE: November 01, 2020 2. CONTRACT IDENTIFICATION: FT18311 3. RATE SCHEDULE: FT 4. SHIPPER TYPE: Other 5. STATE/PROVINCE OF INCORPORATION: Alberta 6. TERM: November 01, 2015 to October 31, 2021 Right of First Refusal: Regulatory (in accordance with Section 6.16 of the General Terms and Conditions of Transporter's FERC Gas Tariff) 7. EFFECT ON PREVIOUS CONTRACTS: This Agreement supersedes, cancels and terminates, as of the effective date stated above, the following contract(s): Service Agreement dated November 01, 2019 with Contract Identification FT18311. 8. MAXIMUM DAILY QUANTITY (Dth/Day): Please see Appendix A for further detail. 9. RATES: Unless Shipper and Transporter have agreed to a rate other than the maximum rate, rates shall be Transporter’s maximum rates and charges plus all applicable surcharges in effect from time to time under the applicable Rate Schedule (as stated above) on file with the Commission unless otherwise agreed to by the parties in writing. Provisions governing a Rate other than the maximum shall be set forth in this Paragraph 9.

Contract ID.: FT18311 Amendment No: 3 10. POINTS OF RECEIPT AND DELIVERY: The primary receipt and delivery points are set forth on Appendix A. 11. RELEASED CAPACITY: N/A 12. INCORPORATION OF TARIFF INTO AGREEMENT: This Agreement shall incorporate and in all respects be subject to the "General Terms and Conditions" and the applicable Rate Schedule (as stated above) set forth in Transporter's FERC Gas Tariff, Third Revised Volume No. l, as may be revised from time to time. Transporter may file and seek Commission approval under Section 4 of the Natural Gas Act (NGA) at any time and from time to time to change any rates, charges or provisions set forth in the applicable Rate Schedule (as stated above) and the "General Terms and Conditions" in Transporter's FERC Gas Tariff, Third Revised Volume No: 1, and Transporter shall have the right to place such changes in effect in accordance with the NGA; and this Agreement shall be deemed to include such changes and any such changes which become effective by operation of law and Commission Order, without prejudice to Shipper's right to protest the same. 13. MISCELLANEOUS: No waiver by either party to this Agreement of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any continuing or future default(s), whether of a like or a different character. Any controversy between the parties arising under this Agreement and not resolved by the parties shall be determined in accordance with the laws of the State of Michigan. 14. OTHER PROVISIONS (As necessary): It is agreed that no personal liability whatsoever shall attach to, be imposed on or otherwise be incurred by any Partner, agent, management official or employee of the Transporter or any director, officer or employee of any of the foregoing, for any obligation of the Transporter arising under this Agreement or for any claim based on such obligation and that the sole recourse of Shipper under this Agreement is limited to assets of the Transporter. Upon termination of this Agreement, Shipper's and Transporter's obligations to each other arising under this Agreement, prior to the date of termination, remain in effect and are not being terminated by any provision of this Agreement.

Contract ID.: FT18311 Amendment No: 3 15. NOTICES AND COMMUNICATIONS: All notices and communications with respect to this Agreement shall be in writing by mail, e-mail, or other means as agreed to by the parties, and sent to the addresses stated below or to any other such address(es) as may be designated in writing by mail, e mail, or other means similarly agreed to: ADMINISTRATIVE MATTERS: Great Lakes Gas Transmission Limited TransCanada PipeLines Limited Partnership 450 1st Street SW Commercial Operations Calgary, AB T2P 5H1 700 Louisiana Street, Suite 700 Houston, TX 77002-2700 Attn: Lisa Jamieson AGREED TO BY: GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP TransCanada PipeLines Limited By: Great Lakes Gas Transmission Company By: Kay Dennison By: DocuSigned by Jay White Title: Director, Transportation Accounting and Contracts BDBBA2270D4F1 Title: Vice President By: DocuSigned by Stefan Baranski TSC07F2232C2.Title: Director, Eastern Markets Legal DS NS DS Content.

APPENDIX A CONTRACT IDENTIFICATION: FT18311 Date: November 01, 2020 Supersedes Appendix Dated: November 01, 2019 Shipper: TransCanada PipeLines Limited Maximum Daily Quantity (Dth/Day) per Location: Point(s) Point(s) of Begin End of Primary Primary Date Date Receipt Delivery MDQ 11/1/2015 3/31/2016 EMERSON RECEIPT SAULT STE MARIE TCPL 12,132 4/1/2016 10/31/2019 EMERSON RECEIPT SAULT STE MARIE TCPL 12,132 11/1/2019 10/31/2020 EMERSON RECEIPT SAULT STE MARIE TCPL 18,903 11/1/2020 10/31/2021 EMERSON RECEIPT SAULT STE MARIE TCPL 18,903

EX-99.2

Exhibit 99.2

Contract ID.: FT18229 Amendment No: 2 FORM OF TRANSPORTATION SERVICE AGREEMENT This Transportation Service Agreement (Agreement) is entered into by Great Lakes Gas Transmission Limited Partnership (Transpo1 e1 and TransCanada PipeLines Limited (Shipper), WHEREAS, Shipper has requested Transpo1ter to transport Gas on its behalf and Transporter represents that it is willing to transpo1t Gas under the terms and conditions of this Agreement. NOW, THEREFORE, Transporter and ·Shipper agree that the terms below constitute the transportation service to be provided and the rights and obligations of Shipper and Transporter. 1. EFFECTIVE DATE: November 01, 2020 2. CONTRACT IDENTIFICATION: FT18229 3. RATE SCHEDULE: FT 4. SHIPPER TYPE: Other 5. STATE/PROVINCE OF INCORPORATION: Alberta 6. TERM: November 01, 2015 to October 31, 2021 Right of First Refusal: Regulatory (in accordance with Section 6.16 of the General Terms and Conditions of Transporter’s FERC Gas Tariff) 7, EFFECT ON PREVIOUS CONTRACTS: This Agreement supersedes, cancels and terminates, as of the effective date stated above, the following contract(s): Service Agreement dated November 01, 2019 with Contract Identification FT18229. 8, MAXIMUM DAILY QUANTITY (Dth/Day): Please see Appendix A for further detail. 9, RATES: Unless Shipper and TrMspol'te1· have agreed to a rate other than the maximum rate, rates shall be Transporter's maximum rates and charges plus all applicable surcharges in effect from time to time under the applicable Rate Schedule (as stated above) on file with the Commission u9less otherwise agreed to by the parties in writing. Provisions governing a Rate othe1· than the maximum shall be set forth in this Paragraph 9

Contract ID.: FT18229 Amendment No: 2 10. POINTS OF RECEIPT AND DELIVERY: The primary receipt and delivery points are set forth on Appendix A. 11. RELEASED CAPACITY: N/A 12. INCORPORATION OF TARIFF INTO AGREEMENT: This Agreement shall incorporate and in all respects be subject to the “General Terms and Conditions" and the applicable Rate Schedule (as stated above) set fo11h in Trnnspo1ter's FERC Gas Tariff, Third Revised Volume No. 1, as may be revised from time to time. Transporter may file and seek Commission approval under Section 4 of the Natural Gas Act (NGA) at any time and from time to time to change any rates, charges or provisions set forth in the applicable Rate Schedule (as stated above) and the "General Terms and Conditions" in Transporter's FERC Gas Tariff, Third Revised Volume No, 1, and Transporter shall have the right to place such changes in effect in accordance with the NGA, and this Agreement shall be deemed to include such changes and any such changes which become effective by operation of law and Commission Order, without prejudice to Shipper's right to protest the same. 13. MISCELLANEOUS: No waiver by either party to this Agreement of any one 01 more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any continuing or future default(s), whether of a like or a different character. Any controversy between the parties arising under this Agreement and not resolved by the parties shall be determined in accordance with the laws of the State of Michigan. 14. OTHER PROVISIONS (As necessary): It is agreed that no personal liability whatsoever shall attach to, be imposed on or otherwise be incurred by any Partner, agent, management official or employee of the Transporter or any director, officer or employee of any·of the foregoing, for any obligation of the Transporter arising)g under this Agreement or for any claim based on such obligation and that the sole recourse of Shipper· under this Agreement is limited to assets of the Transpo11er. Upon termination of this Agreement, Shipper's and Transporter's obligations to each other arising under this Agreement, prior to the date of termination, remain in effect and are not· being terminated by any provision of this Agreement

Contract ID: FT18229 Amendment No: 2 15, NOTICES AND COMMUNICATIONS: All notices·and communications with respect to this Agreement shall be in writing by mail, e-mail, or other means as agreed to by the parties, and sent to the addresses stated below or to any other such address(es) as may be designated in writing by mail, e-mail, or other means similarly agreed to: ADMINISTRATIVE MATTERS: Great Lakes Gas Transmission Limited Partnership Commercial Operations 700 Louisiana Street, Suite 700 Houston, TX 77002-2700 · TransCanada PipeLines Limited 450 1st Street SW Calgary, AB T2P 5Hl Attn: Lisa Jamieson AGREED TO BY: GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP By: Great Lakes Gas Transmission Company TransCanada PipeLines Limited . By: Kay Dennison By: DocuSigned by Jay White BD89AA27f0d04f1 Title: Jay White Vice President Title: Stefan Baranskri Director, Transportation Accounting and Contracts By: Title: Director, Eastern Markets Legal DS NS DS Content.

DocuSign Envelope ID: E6D47635- 5F4E- 4F7C- 9A7B- 9B3001190D22 APPENDIX A. CONTRACT IDENTIFICATION:FT18229 Date: November 01, 2020 Supersedes Appendix Dated: November 01, 2019 Shipper: TransCanada PipeLines Limited Maximum Daily Quantity (Dth/Day) per Location: Point(s) Point(s) of Begin End of Primary Primary Date Date Receipt Delivery MDQ 11/1/2016 10/31/2017 EMERSON RECEIPT SAULT STE MARIE TCPL 2,843 l1/1/2017 10/31/2018 EMERSON RECEIPT SAULT STE MARIE TCPL 2,843 11/1/2018 10/31/2019 EMERSON RECEIPT SAULT STE MARIE TCPL 2,843 I1/1/2019 10/31/2020 EMERSON RECEIPT SAULT STE MARIE TCPL 2,843 11/1/2020 10/31/2021 EMERSON RECEIPT SAULT STE MARIE TCPL 2,843

EX-99.3

Exhibit 99.3

DocuSign Envelope ID:E6D47635-5F4E-4F7C-9A7B-9B3001190D22 Contract ID.: FT17193 Amendment No: 3 FORM OF TRANSPORTATION SERVICE AGREEMENT This Transportation Service Agreement (Agreement) is entered into by Great Lakes Gas Transmission Limited Partnership (Transporter) and TransCanada PipeLines Limited (Shipper). WHEREAS, Shipper has requested Transporter to transport Gas on its behalf and Transporter represents that it is willing to transport Gas under the terms and conditions of this Agreement. NOW, THEREFORE, Transporter and Shipper agree that the terms below constitute the transportation service to be provided and the rights and obligations of Shipper and Transporter.1. EFFECTIVE DATE: November 01, 2020 2. CONTRACT IDENTIFICATION: FT17193 3. RATE SCHEDULE: FT 4. SHIPPER TYPE: Other 5. STATE/PROVINCE OF INCORPORATION: Alberta 6. TERM: November 01,2012 to October 31, 2021 Right of First Refusal: Regulatory (in accordance wlth Section 6.16 of the General Terms and Conditions of Transporter's FERC Gas Tariff) 7. EFFECT ON PREVIOUS CONTRACTS: This Agreement supersedes, cancels and terminates, as of the effective date stated above, the following contract(s): Service Agreement dated November 01, 2019 with Contract Identification FT17193. 8. MAXIMUM DAILY QUANTITY (Dth/Day): Please see Appendix A for further detail. 9. RATES: Unless Shipper and Transporter have agreed to a rate other than the maximum rate, rates shall be Transporter's maximum rates and charges plus all applicable surcharges in effect from time to time under the applicable Rate Schedule (as stated above) on file with the Commission unless otherwise agreed to by the parties in writing. Provisions governing a Rate other than the maximum shall be set forth ln this Paragraph 9.

DocuSign Envelope ID: E6D47635-5F4E-4F7C-9A7B-9B3001190D22 Contract ID.: FT17193 Amendment No: 3 10. POINTS OF RECEIPT AND DELIVERY: The primary receipt and delivery points are set forth on Appendix A. 11. RELEASED CAPACITY: N/A 12. INCORPORATION OF TARIFF INTO AGREEMENT: This Agreement shall incorporate and in all respects be subject to the "General Terms and Conditions" and the applicable Rate Schedule (as stated above) set forth in Transporter's FERC Gas Tariff, Third Revised Volume No. 1, as may be revised from time to time. Transporter may file and seek Commission approval under Section 4 of the Natural Gas Act (NGA) at any time and from fime to time to change any rates, charges or provisions set forth In the applicable Rate Schedule (as stated above) and the "General Terms and Conditions" ln Transporter's FERC Gas Tariff, Third Revised Volume No. 1, and Transporter shall have the right to place such changes in effect in accordance with the NGA, and this Agreement shall be deemed to include such changes and any such changes which become effective by operation of law and Commission Order, withotJt prejudice to Shipper's right to protest the same.13. MISCELLANEOUS: No waiver by either party to this Agreement of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any continuing or future default(s), whether of a like or a different character. Any controversy between the parties arising under. this Agreement and not resolved by the parties shall be determined in accordance with the laws of the State of Michigan. 14. OTHER PROVISIONS (As necessary): It is agreed that no personal liability whatsoevet shall attach to, be imposed on or otherwise be incurred by any Partner, agent, management official or employee of the Transporter or·any director, officer or employee of any of the foregoing, for any obligation of the Transporter arising under this Agreement or for any claim based on such obligation and that the sole recourse of Shipper under this Agreement is limited to assets ofthe Transporter. Upon termination of this Agreement, Shipper's and Transporter's obligations to each other arising under this Agreement; prior to the date of termination, remain in effect and are not being terminated by any provision of this Agreement.

DocuSJgn Envelope ID: E6D47635-5F4E-4F7C-9A78-983001190D22 ContrnctiD.: FT17193 Amendment No: 3 15. NOTICES AND COMMUNICATIONS: All notices and communications with respect to this Agreement shall be in writing by mail, e-mail, or other means as agreed to by the parties, and sent to the addresses stated below or to any other such address(es) as may be designated in writing by mail, e-mail;or other means similarly agreed to: ADMINISTRATIVE MATTERS: Great Lakes Gas Transmission Limited Partnership Commercial Operations 700 Louisiana Street, Suite 700 Houston, TX 77002-2700 TransCanada PipeLines Limited 450 1st Street SW Calgary, AB T2P 5H1 ·Attn: Lisa Jamieson AGREED TO BY: GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP By: Great Lakes Gas Transmission Company TransCanada PipeLines Limited By: Kay Dennison By: Docusigned by: Jay White Title: Director, transportation Accounting and Contracts Title: Vice President Bt: Stefan Baranski Title: Director, Eatern Markets Legal content

DocuSign Envelope ID: E6D47635-5F4E-4F7C-9A78-9B3001190D22 . APPENDIX A CONTRACT IDENTIFICATION: FT17193 Date: November 01, 2020 Supersedes Appendix Dated: November 01, 2019 Shipper TransCanada PipeLines Limited Maximum Daily Quantity (Dth/Day) per·Location: Point(s) of primary Receipt Point(s) of Primary Delivery Begin Date End Date MDO SAULT STE MARIE TCPL ST CLAIR RECEIPT 36,038 . 11/1/2012 3/31/2013 SAULT STE MARIE TCPL ST CLAIR RECEIPT 4/1/2013 10/31/2013 0 SAULT STE MARIE TCPL ST CLAIR RECEIPT 3/31/2014 36,038 11/1/2013 SAULT STE MARIE TCPL ST CLAIR RECEIPT 4/1/2014 10/31/201.4 0 SAULT. STE MARIE TCPL ST CLAIR RECEIPT 11/1/2014 3/31/2015 36,038 SAULT STE MARlE TCPL ST CLAIR RECBIPT 4/1/201S 10/31/2015 0

DocuSign Envelope 10:EBD47635-5F4E-4F7C-9A7B-983001190D22 SAULT STE MARIE TCPL ST CLAIR RECEIPT 3/31/2016 33,195 11/1/2015 SAULT STB MARIE TCPL ST CLAIR RECEIPT 4/1/2016 10/31/2016 0 SAULT STE MARIE TCPL ST CLAIR RECEIPT ·11/1/2016 3/31/2017 33,195 SAULT STE MARIE TCPL ST CLAIR RECEIPT-10/3112017 0 4/1/2017 SAULT STE MARIE TCPL ST CLAIR RECEIPT 33,195 11/1/2017 3/31/2018 SAULT STE MARIB TCPL ST CLAIR RECEIPT 4/1/2018 10/31/2018 0 SAULT STE MARIE TCPL ST CLAIR RECEIPT 11/1/2018 3/31/2019 33,195 SAULT STE MARIE TCPL ST CLAIR RECEIPT 4/1/2019 10/31/2019 0 SAULT STE MARJE TCPL ST CLAIR RECEIPT 11/1/2019 3/31/2020 33,195 SAULT STE MARIE TCPL ST CLAIR RECEIPT 0 4/1/2020 10/31/2020

DocuSign Envelope ID: E6D47635-5F4E-4F7C-9A7B-983001190D22 SAULT STE MARIE TCPL 33,195 ST CLAIR RECEIPT 11/1/2020 3/31/2021 SAULT STE MARIE TCPL ST CLAIR 10/31/2021 RECEIPT 4/1/2021 0

EX-99.4

Exhibit 99.4

Contract ID.: FT18147 Amendment No: 2 FORM OF TRANSPORTATION SERVICE AGREEMENT This Transportation Service Agreement (Agreement) is entered into by Great Lakes Gas Transmission Limited Partnership (Transporter) and ANR Pipeline Company (Shipper). WHEREAS, Shipper has requested Transporter to transport Gas on its behalf and Transporter represents that it is willing to transport Gas under the terms and conditions of this Agreement. NOW, THEREFORE, Transporter and Shipper agree that the terms below constitute the transportation service to be provided and the rights and obligations of Shipper and Transporter. I. EFFECTIVE DATE: November 01,2020 2. CONTRACT IDENTIFICATION: FT18147 3. RATE SCHEDULE: FT 4. SHIPPER TYPE: Other 5. STATE/PROVINCE OF INCORPORATION: Delaware 6. TERM: November 01,2014 to October 31,2021 Right of First Refusal: Regulatory (in accordance with Section 6.16 of the General Terms and Conditions of Transporter's FERC Gas Tariff) 7. EFFECT ON PREVIOUS CONTRACTS: This Agreement supersedes, cancels and terminates, as of the effective date stated above, the following contract(s): Service Agreement dated November 01, 2019 with Contract Identification FT18147. 8. MAXIMUM DAILY QUANTITY (Dth/Day): Please see Appendix A for further detail. 9. RATES: Unless Shipper and Transporter have agreed to a rate other than the maximum rate, rates shall be Transporter's maximum rates and charges plus all applicable surcharges in effect from time to time under the applicable Rate Schedule (as stated above) on file with the Commission unless otherwise agreed to by the parties in writing. Provisions governing a Rate other than the maximum shall be set forth in this Paragraph 9.

Contract ID.: FT18147 Amendment No: 2 10. POINTS OF RECEIPT AND DELIVERY: The primary receipt and delivery points are set forth on Appendix A. 11. RELEASED CAPACITY: N/A 12. INCORPORATION OF TARIFF INTO AGREEMENT: This Agreement shall incorporate and in all respects be subject to the "General Terms and Conditions" and the applicable Rate Schedule (as stated above) set forth in Transporter's FERC Gas Tariff, Third Revised Volume No. 1, as may be revised from time to time. Transporter may file and seek Commission approval under Section 4 of the Natural Gas Act (NGA) at any time and from time to time to change any rates, charges or provisions set forth in the applicable Rate Schedule (as stated above) and the "General Terms and Conditions" in Transporter's FERC Gas Tariff, Third Revised Volume No. 1, and Transporter shall have the right to place such changes in effect in accordance with the NGA, and this Agreement shall be deemed to include such changes and any such changes which become effective by operation of law and Commission Order, without prejudice to Shipper's right to protest the same. 13. MISCELLANEOUS: No waiver by either party to this Agreement of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any continuing or future default(s), whether of a like or a different character. Any controversy between the parties arising under this Agreement and not resolved by the parties shall be determined in accordance with the laws of the State of Michigan. 14. OTHER PROVISIONS (As necessary): It is agreed that no personal liability whatsoever shall attach to, be imposed on or otherwise be incurred by any Partner, agent, management official or employee of the Transporter or any director, officer or employee of any of the foregoing, for any obligation of the Transporter arising under this Agreement or for any claim based on such obligation and that the sole recourse of Shipper under this Agreement is limited to assets of the Transporter. Upon termination of this Agreement, Shipper's and Transporter's obligations to each other arising under this Agreement, prior to the date of termination, remain in effect and are not being terminated by any provision of this Agreement.

Contract ID.: FT18147 Amendment No: 2 15. NOTICES AND COMMUNICATIONS: All notices and communications with respect to this Agreement shall be in writing by mail, e-mail, or other means as agreed to by the parties, and sent to the addresses stated below or to any other such address(es) as may be designated in writing by mail, e-mail, or other means similarly agreed to: ADMINISTRATIVE MATTERS: Great Lakes Gas Transmission Limited Partnership Commercial Operations 700 Louisiana Street, Suite 700 Houston, TX 77002-2700 ANR Pipeline Company 700 Louisiana St., Suite 700 Houston, TX 77002-2700 Attn: Pearline McMahon AGREED TO BY: GREAT LAKES GAS TRANSMISSION ANR Pipeline Company LIMITED PARTNERSHIP By: Great Lakes Gas Transmission Company By: Kay Dennison Title: Director, Transportation Accounting and Contracts By: Jon Howe Title Director, Short Term Marketing

APPENDIX A CONTRACT IDENTIFICATION: FT18147 Date: November 01,2020 Supersedes Appendix Dated: November 01,2019 Shipper: ANR Pipeline Company Maximum Daily Quantity (Dth/Day) per Location: Point(s) of Primary Receipt Point(s) of Primary Delivery End Date Begin Date SOUTH CHESTER RECEIPT FORTUNE LAKE 11/1/2014 3/31/2015 303,900 SOUTH CHESTER RECEIPT FORTUNE LAKE 4/1/2015 10/31/2015 0 SOUTH CHESTER RECEIPT FORTUNE LAKE 11/1/2015 3/31/2016 303,900 SOUTH CHESTER RECEIPT FORTUNE LAKE 0 4/1/2016 10/31/2016 SOUTH CHESTER RECEIPT FORTUNE LAKE 11/1/2016 3/31/2017 303,900 SOUTH CHESTER RECEIPT FORTUNE LAKE 4/1/2017 10/31/2017 0 SOUTH CHESTER RECEIPT FORTUNE LAKE 303,900 11/1/2017 3/31/2018 SOUTH CHESTER RECEIPT FORTUNE LAKE 4/1/2018 10/31/2018 0

` SOUTH CHESTER RECEIPT 3/31/2019 FORTUNE LAKE 11/1/2018 303,900 SOUTH CHESTER 10/31/2019 RECEIPT FORTUNE LAKE 4/1/2019 0 SOUTH CHESTER RECEIPT 3/31/2020 FORTUNE LAKE 11/1/2019 303,900 SOUTH CHESTER RECEIPT 10/31/2020 FORTUNE LAKE 4/1/2020 0 SOUTH CHESTER RECEIPT FORTUNE LAKE 11/1/2020 3/31/2021 303,900 SOUTH CHESTER RECEIPT FORTUNE LAKE 0 4/1/2021 10/31/2021

EX-99.5

Exhibit 99.5

Contract ID.: FT18150 Amendment No: 2 FORM OF TRANSPORTATION SERVICE AGREEMENT This Transportation Service Agreement (Agreement) is entered into by Great Lakes Gas Transmission Limited Partnership (Transporter) and ANR Pipeline Company (Shipper). WHEREAS, Shipper has requested Transporter to transport Gas on its behalf and Transporter represents that it is willing to transport Gas under the terms and conditions of this Agreement. NOW, THEREFORE, Transporter and Shipper agree that the terms below constitute the transportation service to be provided and the rights and obligations of Shipper and Transporter. 1. EFFECTIVE DATE: November 01, 2020 2. CONTRACT IDENTIFICATION: FT18150 3. RATE SCHEDULE: FT 4. SHIPPER TYPE: Other 5. STATE/PROVINCE OF INCORPORATION: Delaware 6. TERM: November 01, 2014 to October 31, 2021 Right of First Refusal: Regulatory (in accordance with Section 6.16 of the General Terms and Conditions of Transporter's FERC Gas Tariff) 7. EFFECT ON PREVIOUS CONTRACTS: This Agreement supersedes, cancels and terminates, as of the effective date stated above, the following contract(s): Service Agreement dated November 01, 2019 with Contract Identification FT18150. 8. MAXIMUM DAILY QUANTITY (Dth/Day): Please see Appendix A for further detail. 9. RATES: Unless Shipper and Transporter have agreed to a rate other than the maximum rate, rates shall be Transporter's maximum rates and charges plus all applicable surcharges in effect from time to time under the applicable Rate Schedule (as stated above) on file with the Commission unless otherwise agreed to by the parties in writing. Provisions governing a Rate other than the maximum shall be set forth in this Paragraph 9.

Contract ID.: FT18150 Amendment No: 2 10. POINTS OF RECEIPT AND DELIVERY: The primary receipt and delivery points are set forth on Appendix A. 11. RELEASED CAPACITY: N/A 12. INCORPORATION OF TARIFF INTO AGREEMENT: This Agreement shall incorporate and in all respects be subject to the "General Terms and Conditions" and the applicable Rate Schedule (as stated above) set forth in Transporter's FERC Gas Tariff, Third Revised Volume No. 1, as may be revised from time to time. Transporter may file and seek Commission approval under Section 4 of the Natural Gas Act (NGA) at any time and from time to time to change any rates, charges or provisions set forth in the applicable Rate Schedule (as stated above) and the "General Terms and Conditions" in Transporter's FERC Gas Tariff, Third Revised Volume No.1, and Transporter shall have the right to place such changes in effect in accordance with the NGA, and this Agreement shall be deemed to include such changes and any such changes which become effective by operation of law and Commission Order, without prejudice to Shipper's right to protest the same. 13. MISCELLANEOUS: No waiver by either party to this Agreement of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any continuing or future default(s), whether of a like or a different character. Any controversy between the parties arising under this Agreement and not resolved by the parties shall be determined in accordance with the laws of the State of Michigan. 14. OTHER PROVISIONS (As necessary): It is agreed that no personal liability whatsoever shall attach to, be imposed on or otherwise be incurred by any Partner, agent, management official or employee of the Transporter or any director, officer or employee of any of the foregoing, for any obligation of the Transporter arising under this Agreement or for any claim based on such obligation and that the sole recourse of Shipper under this Agreement is limited to assets of the Transporter. Upon termination of this Agreement, Shipper's and Transporter's obligations to each other arising under this Agreement, prior to the date of termination, remain in effect and are not being terminated by any provision of this Agreement.

Contract ID.: FT18150 Amendment No: 2 15.NOTICES AND COMMUNICATIONS: All notices and communications with respect to this Agreement shall be in writing by mail, e-mail, or other means as agreed to by the parties, and sent to the addresses stated below or to any other such address(es) as may be designated in writing by mail, e-mail, or other means similarly agreed to: ADMINISTRATIVE MATTERS: Great Lakes Gas Transmission Limited ANR Pipeline CompanyPartnership700 Louisiana St., Suite 700 Commercial Operations Houston, TX 77002-2700700 Louisiana Street, Suite 700 Houston, TX 77002-2700 Attn: Jon Hawe AGREED TO BY: GREAT LAKES GAS TRANSMISSION ANR Pipeline Company LIMITED PARTNERSHIP By: Great Lakes Gas Transmission Company By: Kay Dennison By: Jon Hawe Title: Director, Transportation Accounting and Contracts Title: Director, Short Team Marketing

APPENDIX A CONTRACT IDENTIFICATION: FT18150 Date: November 01, 2020 Supersedes Appendix Dated: November 01, 2019 Shipper: ANR Pipeline Company Maximum Daily Quantity (Dth/Day) per Location: Point(s)Point(s)of Begin End of Primary Primary Date Date Receipt Delivery MDQ 11/1/2015 3/31/2016 SOUTH CHESTER RECEIPT FARWELL DELIVERY 101,300 4/1/2016 10/31/2016 SOUTH CHESTER RECEIPT FARWELL DELIVERY 0 11/1/2016 3/31/2017 SOUTH CHESTER RECEIPT FARWELL DELIVERY 101,300 4/1/2017 10/31/2017 SOUTH CHESTER RECEIPT FARWELL DELIVERY 011/1/2017 3/31/2018 SOUTH CHESTER RECEIPT FARWELL DELIVERY101,300 4/1/2018 10/31/2018 SOUTH CHESTER RECEIPT FARWELL DELIVERY 0

11/1/2018 3/31/2019 SOUTH CHESTER RECEIPT FARWELL DELIVERY 101,300 4/1/2019 10/31/2019 SOUTH CHESTER RECEIPT FARWELL DELIVERY 0 11/1/2019 3/31/2020 SOUTH CHESTER RECEIPT FARWELL DELIVERY 101,300 4/1/2020 10/31/2020 SOUTH CHESTER RECEIPT FARWELL DELIVERY 0 11/1/2020 3/31/2021 CHESTER RECEIPT FARWELL DELIVERY 101,300 4/1/2021 10/31/2021 SOUTH CHESTER RECEIPT FARWELL DELIVERY 0 11/1/2014 3/31/2015 DEWARD RECEIPT 101,300 11/1/2015 3/31/2016 DEWARD RECEIPT 101,300 11/1/2016 3/31/2017 DEWARD RECEIPT 101,300 11/1/2017 3/31/2018 DEWARD RECEIPT 101,300 11/1/2018 3/31/2019 DEWARD RECEIPT 101,300 11/1/2019 3/31/2020 DEWARD RECEIPT 101,300 11/1/2020 3/31/2021 DEWARD RECEIPT 101,300

EX-99.6

Exhibit 99.6

Contract ID.: FT17593 Amendment No: 3 FORM OF TRANSPORTATION SERVICE AGREEMENT This Transportation Service Agreement (Agreement) is entered into by Great Lakes Gas Transmission Limited Partnership (Transporter) and ANR Pipeline Company (Shipper). WHEREAS, Shipper has requested Transporter to transport Gas on its behalf and Transporter represents that it is willing to transport Gas under the terms and conditions of this Agreement. NOW, THEREFORE, Transporter and Shipper agree that the terms below constitute the transportation service to be provided and the rights and obligations of Shipper and Transporter. 1. EFFECTIVE DATE: November 01,2020 2. CONTRACT IDENTIFICATION: FT17593 3. RATE SCHEDULE: FT 4. SHIPPER TYPE: Other 5. STATE/PROVINCE OF INCORPORATION: Delaware 6. TERM: November 01,2012 to October 31,2021 Right of First Refusal: Regulatory (in accordance with Section 6.16 of the General Terms and Conditions of Transporter's FERC Gas Tariff) 7. EFFECT ON PREVIOUS CONTRACTS: This Agreement supersedes, cancels and terminates, as of the effective date stated above, the following contract(s): Service Agreement dated November 01, 2019 with Contract Identification FT17593. 8. MAXIMUM DAILY QUANTITY (Dth/Day): Please see Appendix A for further detail. 9. RATES: Unless Shipper and Transporter have agreed to a rate other than the maximum rate, rates shall be Transporter's maximum rates and charges plus all applicable surcharges in effect from time to time under the applicable Rate Schedule (as stated above) on file with the Commission unless otherwise agreed to by the parties in writing. Provisions governing a Rate other than the maximum shall be set fotih in this Paragraph 9.

Contract ID.: FT17593 Amendment No: 3 10. POINTS OF RECEIPT AND DELIVERY: The primary receipt and delivery points are set forth on Appendix A. 11. RELEASED CAPACITY: N/A 12. INCORPORATION OF TARIFF INTO AGREEMENT: This Agreement shall incorporate and in all respects be subject to the "General Terms and Conditions" and the applicable Rate Schedule (as stated above) set forth in Transporter's FERC Gas Tariff, Third Revised Volume No. 1, as may be revised from time to time. Transporter may file and seek Commission approval under Section 4 of the Natural Gas Act (NGA) at any time and from time to time to change any rates, charges or provisions set forth in the applicable Rate Schedule (as stated above) and the "General Terms and Conditions" in Transporter's FERC Gas Tariff, Third Revised Volume No. 1, and Transporter shall have the right to place such changes in effect in accordance with the NGA, and this Agreement shall be deemed to include such changes and any such changes which become effective by operation of law and Commission Order, without prejudice to Shipper's right to protest the same. 13. MISCELLANEOUS: No waiver by either party to this Agreement of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any continuing or future default(s), whether of a like or a different character. Any controversy between the parties arising under this Agreement and not resolved by the parties shall be detetmined in accordance with the laws of the State of Michigan. 14. OTHER PROVISIONS (As necessary): It is agreed that no personal liability whatsoever shall attach to, be imposed on or otherwise be incurred by any Partner, agent, management official or employee of the Transporter or any director, officer or employee of any of the foregoing, for any obligation of the Transporter arising under this Agreement or for any claim based on such obligation and that the sole recourse of Shipper under this Agreement is limited to assets of the Transporter. Upon termination of this Agreement, Shipper's and Transporter's obligations to each other arising under this Agreement, prior to the date of termination, remain in effect and are not being terminated by any provision of this Agreement.

Contract ID.: FT17593 Amendment No: 3 15. NOTICES AND COMMUNICATIONS: All notices and communications with respect to this Agreement shall be in writing by mail, e-mail, or other means as agreed to by the parties, and sent to the addresses stated below or to any other such address(es) as may be designated in writing by mail, e-mail, or other means similarly agreed to: ADMINISTRATIVE MATTERS: Great Lakes Gas Transmission Limited Partnership Commercial Operations 700 Louisiana Street, Suite 700 Houston, TX 77002-2700 ANR Pipeline Company 700 Louisiana St., Suite 700 Houston, TX 77002-2700 Attn: Colin Lindley AGREED TO BY: GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP By: Great Lakes Gas Transmission Company By: Kay Dennison By: Jon Hawe Title: Director, Transportation Accounting and Contracts Title: Director, Short Team Marketing

APPENDIX A CONTRACT IDENTIFICATION: FT17593 Date: November 01,2020 Supersedes Appendix Dated: November 01,2019 Shipper: ANR Pipeline Company Maximum Daily Quantity (Dth/Day) per Location: Point(s) of Primary Receipt Point(s) of Primary Delivery Begin Date End Date MDO MUTTONVILLE RECEIPT FORTUNE LAKE 11/1/2012 3/31/2013 506,500 SOUTH CHESTER DELIVERY MUTTONVILLE RECEIPT 4/1/2013 10/31/2013 390,000 MUTTONVILLE RECEIPT FORTUNE LAKE 11/1/2013 3/31/2014 506,500 SOUTH CHESTER DELIVERY MUTTONVILLE RECEIPT 4/1/2014 10/31/2014 207,000 MUTTONVILLE RECEIPT FORTUNE LAKE 11/112014 3/31/2015 506,500 SOUTH CHESTER DELIVERY MUTTONVILLE RECEIPT 4/112015 10/31/2015 207,000 MUTTONVILLE RECEIPT FORTUNE LAKE 11/1/2015 3/31/2016 506,500 SOUTH CHESTER DELIVERY MUTTONVILLE RECEIPT 4/1/2016 10/31/2016 207,000 MUTTONVILLE RECEIPT FORTUNE LAKE 11/1/2016 3/31/2017 506,500

SOUTH CHESTER DELIVERY MUTTONVILLE RECEIPT 4/1/2017 10/31/2017 207,000 MUTTONVILLE RECEIPT FORTUNE LAKE 11/1/2017 3/31/2018 506,500 SOUTH CHESTER DELIVERY MUTTONVILLE RECEIPT . 4/1/2018 10/31/2018 207,000 MUTTONVILLE RECEIPT FORTUNE LAKE 11/1/2018 3/31/2019 506,500 SOUTH CHESTER DELIVERY MUTTONVILLE RECEIPT 4/1/2019 10/31/2019 207,000 MUTTONVILLE RECEIPT FORTUNE LAKE 11/1/2019 3/31/2020 506,500 SOUTH CHESTER DELIVERY MUTTONVILLE RECEIPT 4/1/2020 10/31/2020 207,000 MUTTONVILLE RECEIPT FORTUNE LAKE 11/1/2020 3/31/2021 506,500 SOUTH CHESTER DELIVERY MUTTON VILLE RECEIPT 4/1/2021 10/31/2021 207,000 FARWELL RECEIPT 11/1/2012 3/31/2013 506,500 DEWARD RECEIPT 11/1/2012 3/31/2013 506,500 SOUTH CHESTER RECEIPT 11/1/2012 3/31/2013 100,000 FARWELL RECEIPT 4/1/2013 10/31/2013 390,000 DEWARD RECEIPT 4/1/2013 10/31/2013 207,000 FARWELL RECEIPT 11/1/2013 3/31/2014 506,500

DEWARD RECEIPT 11/1/2013 3/31/2014 506,500 SOUTH CHESTER RECEIPT 11/1/2013 3/31/2014 100,000 FARWELL RECEIPT 4/1/2014 10/31/2014 207,000 SOUTH CHESTER RECEIPT 4/1/2014 10/31/2014 100,000 DEWARD RECEIPT 4/1/2014 10/31/2014 207,000 FARWELL RECEIPT 11/1/2014 3/31/2015 506,500 DEWARD RECEIPT 11/1/2014 3/31/2015 506,500 SOUTH CHESTER RECEIPT 11/1/2014 3/31/2015 100,000 FARWELL RECEIPT 4/1/2015 10/31/2015 207,000 DEWARD RECEIPT 4/1/2015 10/31/2015 207,000 SOUTH CHESTER RECEIPT 11/1/2015 3/31/2016 100,000 DEWARD RECEIPT 11/1/2015 3131/2016 506,500 FARWELL RECEIPT 11/1/2015 3/31/2016 506,500 FARWELL RECEIPT 4/1/2016 10/31/2016 207,000 DEWARD RECEIPT 4/1/2016 10/31/2016 207,000

SOUTH CHESTER RECEIPT 11/1/2016 3/31/2017 100,000 DEWARD RECEIPT 11/1/2016 3/31/2017 506,500 FARWELL RECEIPT 11/1/2016 3/31/2017 506,500 FARWELL RECEIPT 4/1/2017 10/31/2017 207,000 FARWELL RECEIPT 11/1/2017 3/31/2018 506,500 DEWARD· RECEIPT 11/1/2017 3/31/2018 506,500 SOUTH CHESTER RECEIPT 11/1/2017 3/31/2018 100,000 FARWELL RECEIPT 10/31/2018 4/1/2018 207,000 DEWARD RECEIPT 11/1/2018 3/31/2019 506,500 FARWELL RECEIPT 11/1/2018 3/31/2019 506,500 SOUTH CHESTER RECEIPT 11/1/2018 3/31/2019 100,000 FARWELL RECEIPT 4/1/2019 10/31/2019 207,000 DEWARD RECEIPT 11/1/2019 3/31/2020 506,500 FARWELL RECEIPT 11/1/2019 3/31/2020 506,500 SOUTH CHESTER RECEIPT 11/1/2019 3/31/2020 100,000

FARWELL RECEIPT 4/1/2020 10/31/2020 207,000 DEWARD RECEIPT 11/1/2020 3/31/2021 506,500 FARWELL RECEIPT 11/1/2020 3/31/2021 506,500 SOUTH CHESTER RECEIPT 11/1/2020 3/31/2021 100,000 FARWELL RECEIPT 4/1/2021 10/31/2021 207,000 FARWELL DELIVERY 11/1/2012 3/31/2013 506,500 DEWARD DELIVERY 11/2012 3/31/2013 506,500 MUTTONVILLE DELIVERY 11/1/2012 3/31/2013 100,000 11/1/2012 3/31/2013 OTISVILLE 100,000 DEWARD DELIVERY 4/1/2013 10/31/2013 390,000 FARWELL DELIVERY 11/1/2013 3/31/2014 506,500 DEWARD DELIVERY 11/1/2013 3/31/2014 506,500 MUTTONVILLE DELIVERY 11/1/2013 3/31/2014 100,000 11/1/2013 3/31/2014 OTISVILLE 100,000 DEWARD DELIVERY 4/1/2014 10/31/2014 207,000 FARWELL DELIVERY 4/1/2014 10/31/2014 207,000 FARWELL DELIVERY 11/1/2014 3/31/2015 506,500

MUTTONVILLE DELIVERY 11/1/2014 3/31/20I5 100,000 11/1/2014 3/31/2015 OTISVILLE 100,000 DEWARD DELIVERY 11/1/2014 3/31/20I5 506,500 DEWARD DELIVERY 4/1/2015 10/31/2015 207,000 DEWARD DELIVERY 11/1/2015 3/31/2016 506,500 FARWELL DELIVERY 11/1/2015 3/31/2016 506,500 11/1/2015 3/31/2016 OTISVILLE 100,000 MUTTONVILLE DELIVERY 11/1/2015 3/31/2016 100,000 DEWARD DELIVERY 4/1/2016 10/31/2016 207,000 DEWARD DELIVERY 11/1/2016 3/31/2017 506,500 11/1/2016 3/31/2017 OTISVILLE 100,000 MUTTONVILLE DELIVERY 11/1/2016 3/31/2017 100,000 FARWELL DELIVERY 11/1/2016 3/31/2017 506,500 DEWARD DELIVERY 10/31/2017 4/1/2017 207,000 FARWELL DELIVERY 11/1/2017 3/31/2018 506,500 DEWARD DELIVERY 11/1/2017 3/31/2018 506,500 MUTTONVILLE DELIVERY 11/1/2017 3/31/2018 100,000

11/1/2017 3/31/2018 OTISVILLE 100,000 SOUTH CHESTER DELIVERY 11/1/2017 3/31/2018 100,000 DEWARD DELIVERY 4/1/2018 10/31/2018 207,000 DEWARD DELIVERY 11/1/2018 3/31/2019 506,500 FARWELL DELIVERY 11/1/2018 3/31/2019 506,500 11/1/2018 3/31/2019 OTISVILLE 100,000 MUTTONVILLE DELIVERY 11/1/2018 3/31/2019 100,000 SOUTH CHESTER DELIVERY 11/1/2018 3/31/2019 100,000 DEWARD DELIVERY 4/1/2019 10/31/2019 207,000 DEWARD DELIVERY 11/1/2019 3/31/2020 506,500 FARWELL DELIVERY 11/1/2019 3/31/2020 506,500 11/1/2019 3/31/2020 OTISVILLE 100,000 MUTTON VILLE DELIVERY 11/1/2019 3/31/2020 100,000 SOUTH CHESTER DELIVERY 11/1/2019 3/31/2020 100,000 DEWARD DELIVERY 4/1/2020 10/31/2020 207,000 DEWARD DELIVERY 11/1/2020 3/31/2021 506,500

FARWELL DELIVERY 11/1/2020 3/31/2021 506,500 11/1/2020 3/31/2021 OTISVILLE 100,000 MUTTONVILLE DELIVERY 11/1/2020 3/31/2021 100,000 SOUTH CHESTER DELIVERY 11/1/2020 3/31/2021 100,000 DEWARD DELIVERY 4/1/2021 10/31/2021 207,000

EX-99.7

Exhibit 99.7

Contract ID.: FT18659 Amendment No: 2 FORM OF TRANSPORTATION SERVICE AGREEMENT This Transportation Service Agreement (Agreement) is entered into by Great Lakes Gas Transmission Limited Partnership (Transporter) and ANR Pipeline Company (Shipper). WHEREAS, Shipper has requested Transporter to transport Gas on its behalf and Transporter represents that it is willing to transport Gas under the terms and conditions of this Agreement. NOW, THEREFORE, Transporter and Shipper agree that the terms below constitute the transportation service to be provided and the rights and obligations of Shipper and Transporter. 1. EFFECTIVE DATE: November 01, 2020 2. CONTRACT IDENTIFICATION: FT18659 3. RATE SCHEDULE: FT 4. SHIPPER TYPE: Other 5. STATE/PROVINCE OF INCORPORATION: Delaware 6. TERM: April 01,2017 to October 31,2021 Right of First Refusal: Regulatory (in accordance with Section 6.16 of the General Terms and Conditions of Transporter's FERC Gas Tariff) 7. EFFECT ON PREVIOUS CONTRACTS: This Agreement supersedes, cancels and terminates, as of the effective date stated above, the following contract(s): Service Agreement dated November 01, 2019 with Contract Identification FTI8659. 8. MAXIMUM DAILY QUANTITY (Dth/Day): Please see Appendix A for further detail. 9. RATES: Unless Shipper and Transporter have agreed to a rate other than the maximum rate, rates shall be Transporter's maximum rates and charges plus all applicable surcharges in effect from time to time under the applicable Rate Schedule (as stated above) on file with the Commission unless otherwise agreed to by the parties in writing. Provisions governing a Rate other than the maximum shall be set forth in this Paragraph 9.

Contract ID.: FT18659 Amendment No: 2 10. POINTS OF RECEIPT AND DELIVERY: The primary receipt and delivery points are set forth on Appendix A. 11. RELEASED CAPACITY: N/A 12. INCORPORATION OF TARIFF INTO AGREEMENT: This Agreement shall incorporate and in all respects be subject to the "General Terms and Conditions" and the applicable Rate Schedule (as stated above) set forth in Transporter's FERC Gas Tariff, Third Revised Volume No. 1, as may be revised from time to time. Transporter may file and seek Commission approval under Section 4 of the Natural Gas Act (NGA) at any time and from time to time to change any rates, charges or provisions set forth in the applicable Rate Schedule (as stated above) and the "General Terms and Conditions" in Transporter's FERC Gas Tariff, Third Revised Volume No. 1, and Transporter shall have the right to place such changes in effect in accordance with the NGA, and this Agreement shall be deemed to include such changes and any such changes which become. effective by operation of law and Commission Order, without prejudice to Shipper's right to protest the same. 13. MISCELLANEOUS: No waiver by either party to this Agreement of any one or more defaults by the other in the performance of this Agreement shall operate or be construed as a waiver of any continuing or future default(s), whether of a like or a different character. Any controversy between the parties arising under this Agreement and not resolved by the parties shall be determined in accordance with the laws of the State of Michigan. 14. OTHER PROVISIONS (As necessary): It is agreed that no personal liability whatsoever shall attach to, be imposed on or otherwise be incurred by any Partner, agent, management official or employee of the Transporter or any director, officer or employee of any of the foregoing, for any obligation of the Transporter arising under this Agreement or for any claim based on such obligation and that the sole recourse of Shipper under this Agreement is limited to assets of the Transporter. Upon termination of this Agreement, Shipper's and Transporter's obligations to each other arising under this Agreement, prior to the date of termination, remain in effect and are not being terminated by any provision of this Agreement.

Contract ID.: FT18659 Amendment No: 2 15. NOTICES AND COMMUNICATIONS: All notices and communications with respect to this Agreement shall be in writing by mail, e-mail, or other means as agreed to by the parties, and sent to the addresses stated below or to any other such address(es) as may be designated in writing by mail, e-mail, or other means similarly agreed to: ADMINISTRATIVE MATTERS: Great Lakes Gas Transmission Limited Partnership Commercial Operations 700 Louisiana Street, Suite 700 Houston, TX 77002-2700 ANR Pipeline Company 700 Louisiana St., Suite 700 Houston, TX 77002-2700 Attn: Colin Lindley AGREED TO BY: GREAT LAKES GAS TRANSMISSION ANR Pipeline Company LIMITED PARTNERSHIP By: Great Lakes Gas Transmission Company By: Kay Dennison By: Jon Hawe Title: Director, Transportation Accounting and Contracts Title: Director, Short Team Marketing

APPENDIX A CONTRACT IDENTIFICATION: FT18659 Date: November 01,2020 Supersedes Appendix Dated: November 01,2019 Shipper: ANR Pipeline Company Maximum Daily Quantity (Dth/Day) per Location: Point(s) of Primary Receipt Point(s) of Primary Delivery Begin Date End Date DEWARD RECEIPT FARWELL DELIVERY 4/1/2017 10/31/2017 0 DEWARD RECEIPT FARWELL DELIVERY 202,464 11/1/2017 3/31/2018 DEWARD RECEIPT FARWELL DELIVERY 4/1/2018 10/31/2018 0 DEWARD RECEIPT FARWELL DELIVERY 11/1/2018 3/31/2019 202,464 DEWARD RECEIPT FARWELL DELIVERY 4/1/2019 10/31/2019 0 DEWARD RECEIPT FARWELL DELIVERY 11/1/2019 3/31/2020 202,464 DEWARD RECEIPT FARWELL DELIVERY 4/1/2020 10/31/2020 0 DEWARD RECEIPT FARWELL DELIVERY 11/1/2020 3/31/2021 202,464 DEWARD RECEIPT FARWELL DELIVERY 4/1/2021 10/31/2021 0 SOUTH CHESTER RECEIPT 11/1/2017 3/31/2018 115,771

SOUTH CHESTER RECEIPT 11/1/2018 3/31/2019 115,771 SOUTH CHESTER RECEIPT 11/1/2019 3/31/2020 115,771 SOUTH CHESTER RECEIPT 115,771 11/1/2020 3/31/2021

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OTHER LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2019

OTHER LIABILITIES

Schedule of other liabilities

December 31 (millions of dollars)	2019	2018
Regulatory liabilities	29	27
Other liabilities	7	2
	36	29

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EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2019

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

	Ownership
	Interest at		Equity Earnings (b)			Equity Investments
	December 31,		Year ended December 31			December 31
(millions of dollars)	2019		2019	2018	2017	2019	2018
Northern Border(a)	50.00	%	69	68	67	422	497
Great Lakes	46.45	%	51	59	31	491	489
Iroquois	49.34	%	40	46	26	185	210
			160	173	124	1,098	1,196

(a) Equity earnings from Northern Border is net of the 12-year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent in April 2006. The fee was fully amortized in May 2018.

(b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here.

Northern Border

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

December 31 (millions of dollars)	2019	2018
Assets
Cash and cash equivalents	21	10
Other current assets	37	36
Property, plant and equipment, net	989	1,037
Other assets	12	13
	1,059	1,096
Liabilities and Partners’ Equity
Current liabilities	42	34
Deferred credits and other	39	35
Long-term debt, net (a)	364	264
Partners’ equity
Partners’ capital	615	764
Accumulated other comprehensive loss	(1)	(1)
	1,059	1,096

Year ended December 31 (millions of dollars)	2019	2018	2017
Transmission revenues	300	289	291
Operating expenses	(82)	(78)	(78)
Depreciation	(62)	(60)	(59)
Financial charges and other	(18)	(15)	(18)
Net income	138	136	136

(a) No current maturities as of December 31, 2019 or 2018.

Great Lakes

EQUITY INVESTMENTS

Schedule of equity investments and summarized financial information for equity investees

December 31 (millions of dollars)	2019	2018
Assets
Current assets	72	75
Property, plant and equipment, net	685	689
	757	764
Liabilities and Partners’ Equity
Current liabilities	33	26
Long-term debt, net (a)	219	240
Other long-term liabilities	6	4
Partners’ equity	499	494
	757	764

Year ended December 31 (millions of dollars)	2019	2018	2017
Transmission revenues	238	246	181
Operating expenses	(79)	(68)	(66)
Depreciation	(32)	(32)	(29)
Financial charges and other	(16)	(18)	(20)
Net income	111	128	66

(a) Includes current maturities of $21 million as of December 31, 2019 and December 31, 2018.

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2019

SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation - Consolidation and equity method of accounting

(a)    Basis of Presentation

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

Basis of Presentation - Transactions between entities under common control

Acquisitions by the Partnership from TC Energy are considered common control transactions. When businesses that will be consolidated are acquired from TC Energy by the Partnership, the historical financial statements are required to be recast, with the exception of net income (loss) per common unit, to include the acquired entities for all periods presented.

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

On June 1, 2017, the Partnership acquired from a subsidiary of TC Energy an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 8). This acquisition was accounted for as transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TC Energy's carrying value.

Also, on June 1, 2017, the Partnership acquired from subsidiaries of TC Energy a 49.34 percent interest in Iroquois (Refer to Note 8). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to a pooling of interest, whereby the equity investment in Iroquois was recorded at TC Energy's carrying value and was accounted for prospectively.

Use of Estimates

(b)    Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

(c)    Cash and Cash Equivalents

The Partnership’s cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.

Trade Accounts Receivable

(d)    Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method.

Natural gas imbalances

(e)    Natural gas imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines’ tariff.

Imbalances due from others are reported as trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. The determination of the asset or liability classification is based on the net position of the customer. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year.

Inventories

(f)    Inventories

Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost and net realizable value.

Property, plant and Equipment

(g)    Property, plant and Equipment

Property, plant and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from five to 77 years. Depreciation of our subsidiaries’ assets is based on rates approved by FERC from the pipelines’ last rate proceeding and is calculated on a straight-line composite basis over the assets’ estimated useful lives. Under the composite method, assets with similar lives and characteristics are grouped and depreciated as one asset. Repair and maintenance costs are expensed as incurred. Costs that are considered a betterment are capitalized.

The Partnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long-lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based on the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of property, plant and equipment on the balance sheets. Amounts included in construction work in progress are not depreciated until transferred into service.

Impairment of Equity Method Investments

(h)    Impairment of Equity Method Investments

We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment.

If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge.

Impairment of Long-lived Assets

(i)    Impairment of Long-lived Assets

The Partnership reviews long-lived assets, such as property, plant and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.

Partners' Equity

(j)    Partners’ Equity

Costs incurred in connection with the issuance of units are deducted from the proceeds received.

Revenue Recognition

(k)    Revenue Recognition

The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Partnership utilizes the practical expedient of recognizing revenue as invoiced. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is

transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities.

The Partnership's pipeline systems are subject to Federal Energy Regulatory Commission (FERC) regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management’s best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. Refer to Note 6 for detailed disclosures regarding the Partnership’s revenues.

Debt Issuance Costs

(l)    Debt Issuance Costs

Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Consistent with debt discount, debt issuance costs are presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities. The amortization of debt issuance costs is reported as interest expense.

Income Taxes

(m)    Income Taxes

U.S. federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of operations, is includable in the U.S. federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the partnership is not available.

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

State Income Taxes on PNGTS

The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire (NH). As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at December 31, 2019, 2018 and 2017 relate primarily to utility plant. The NH BPT effective tax rate was 2.6 percent for the year ended December 31, 2019 (2018 – 3.5 percent, 2017 - 3.8 percent) and was applied to PNGTS’ taxable income.

The state income taxes of PNGTS are broken out as follows:

Year ended December 31 (millions of dollars)	2019	2018	2017
State income tax benefit (expense)
Current	(1)	(2)	(1)
Deferred	2	1	—
	1	(1)	(1)

Acquisitions and Goodwill

(n)    Acquisitions and Goodwill

The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill.

Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if any indicators of impairment are evident. The Partnership can initially assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired and if the Partnership concludes there is not a greater than 50 percent likelihood that the fair value of the reporting unit is greater than its carrying value, the Partnership will then perform the quantitative goodwill impairment test. The Partnership can also elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Partnership compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of

a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value.

We calculate the estimated fair value of the reporting unit using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for of the reporting unit, estimates of the useful life over which cash flows will occur, and a determination of weighted average cost of capital. The estimates used to calculate the fair value of the reporting unit can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether the goodwill in the reporting unit has suffered an impairment.

The Partnership accounts for business acquisitions between itself and TC Energy, also known as “dropdowns,” as transactions between entities under common control. Using this approach, the assets and liabilities of the acquired entities are recorded at TC Energy’s carrying value. In the event recasting is required, the Partnership’s historical financial information will be recast, with the exception of net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners’ Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners’ Equity.

Fair Value Measurements

(o)    Fair Value Measurements

For cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Judgment is required in developing these estimates.

Derivative Financial Instruments and Hedging Activities

(p)    Derivative Financial Instruments and Hedging Activities

The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings.

The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). In a cash flow hedging relationship, the change in the fair value of the hedging derivative is reported as a component of other comprehensive income and reclassified into earnings as part of “financial charges and other” line in the Consolidated Statement of Operations in the same period or periods during which the hedged transaction affects earnings or is reclassified immediately to net income when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur.

In some instances, the derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change.

Asset Retirement Obligation

(q)    Asset Retirement Obligation

The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists, and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses.

The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system’s assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2019 and 2018.

Government Regulation

(r)    Government Regulation

The Partnership's subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated rate-making process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators' decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. At December 31, 2019, the Partnership had nil amount of regulatory assets reported as part of other current assets in the balance sheet and nil amount of regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities. At December 31, 2018, the Partnership had regulatory assets amounting to $2 million reported as part of other current assets in the balance sheet and $2 million regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities both representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually. Long-term regulatory liabilities that the Partnership has collected in its current rates related to future removal costs on its transmissions and gathering facilities are included in other long-term liabilities (refer to Note 10).

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EQUITY INVESTMENTS (Details) - USD ($) $ in Millions					1 Months Ended			3 Months Ended								7 Months Ended	12 Months Ended
	Jan. 06, 2020	Nov. 01, 2019	Sep. 01, 2017	Jun. 01, 2017	Aug. 31, 2019	Jun. 30, 2019	Apr. 30, 2006	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 01, 2017
EQUITY INVESTMENTS
Equity Earnings								$ 45.0	$ 31.0	$ 30.0	$ 54.0	$ 44.0	$ 34.0	$ 36.0	$ 59.0		$ 160.0	$ 173.0	$ 124.0
Equity Investments								1,098.0				1,196.0					1,098.0	1,196.0
Distributions from Equity Investments
Distributions received from equity investments																	258.0	198.0	145.0
Distributions from equity investments																	200.0	188.0	140.0
Return on investment distribution classified as investing activities																	58.0	10.0	5.0
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt (Note 9)								123.0				$ 36.0					$ 123.0	36.0
Revenues (expenses)
Transmission revenues																		194.0
Operating expenses																		(57.0)
Depreciation																		(29.0)
Financial charges and other																		(14.0)
Net income																		$ 94.0
Northern Border
EQUITY INVESTMENTS
Partnership interest held (as a percent)																	50.00%
Great Lakes
EQUITY INVESTMENTS
Partnership interest held (as a percent)																	46.45%
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill								$ 260.0									$ 260.0
Great Lakes | Minimum
EQUITY INVESTMENTS
Excess of estimated fair value over carrying value (as a percent)												10.00%						10.00%
ONEOK Partners, L.P. | Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)								50.00%									50.00%
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)			50.00%
Equity contribution			$ 83.0
Capital contribution to reduce the outstanding balance of revolver debt			$ 166.0
Cash distribution						$ 100.0
Distribution financed by borrowings (as a percent)						100.00%				100.00%
Northern Border | Revolving credit facility
EQUITY INVESTMENTS
Maximum borrowing capacity						$ 200.0				$ 200.0
Great Lakes
EQUITY INVESTMENTS
Total cash call issued to fund debt repayment												$ 10.0			$ 11.0
LIABILITIES AND PARTNERS' EQUITY
Current portion of long-term debt (Note 9)								$ 21.0				21.0					$ 21.0	$ 21.0
Iroquois
EQUITY INVESTMENTS
Ownership interest (as a percent)								49.34%									49.34%
Total cash call issued to fund debt repayment																		7.0
Distributions from Equity Investments
Return on investment distribution classified as investing activities																	$ 8.0	10.0
Limited partners, Distribution declared		$ 28.0
ASSETS
Cash and cash equivalents								$ 43.0									43.0
Other current assets								36.0									36.0
Property, plant and equipment, net								570.0									570.0
Other assets								16.0									16.0
Assets, total								665.0									665.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities								34.0									34.0
Net long-term debt, including current maturities								317.0									317.0
Current portion of long-term debt (Note 9)								3.0				146.0					3.0	146.0
Other non-current liabilities								20.0									20.0
Partners' capital								294.0									294.0
Liabilities and Partners' Equity, total								$ 665.0									665.0
Revenues (expenses)
Transmission revenues																$ 110.0	180.0
Operating expenses																(32.0)	(58.0)
Depreciation																(17.0)	(29.0)
Financial charges and other																(9.0)	(11.0)
Net income																52.0	$ 82.0
Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)								50.00%									50.00%
Equity Earnings																	$ 69.0	68.0	67.0
Equity Investments								$ 422.0				497.0					422.0	497.0
Amortization period of transaction fee							12 years
Transaction fee							$ 10.0
Additional ownership interest acquired (as a percent)							20.00%
Equity contribution																			83.0
Undistributed earnings																		0.0	0.0	$ 0.0
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill								115.0								$ 115.0	115.0		115.0
Distributions from Equity Investments
Distributions received from equity investments																	144.0	83.0	83.0
Return on investment distribution classified as investing activities																	50.0
ASSETS
Cash and cash equivalents								21.0				10.0					21.0	10.0
Other current assets								37.0				36.0					37.0	36.0
Property, plant and equipment, net								989.0				1,037.0					989.0	1,037.0
Other assets								12.0				13.0					12.0	13.0
Assets, total								1,059.0				1,096.0					1,059.0	1,096.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities								42.0				34.0					42.0	34.0
Deferred credits and other								39.0				35.0					39.0	35.0
Net long-term debt, including current maturities								364.0				264.0					364.0	264.0
Current portion of long-term debt (Note 9)								0.0									0.0
Partners' capital								615.0				764.0					615.0	764.0
Accumulated other comprehensive loss								(1.0)				(1.0)					(1.0)	(1.0)
Liabilities and Partners' Equity, total								$ 1,059.0				1,096.0					1,059.0	1,096.0
Revenues (expenses)
Transmission revenues																	300.0	289.0	291.0
Operating expenses																	(82.0)	(78.0)	(78.0)
Depreciation																	(62.0)	(60.0)	(59.0)
Financial charges and other																	(18.0)	(15.0)	(18.0)
Net income																	$ 138.0	136.0	$ 136.0
Northern Border | Northern Border
EQUITY INVESTMENTS
Ownership interest (as a percent)								50.00%									50.00%
Great Lakes
EQUITY INVESTMENTS
Ownership interest (as a percent)								46.45%									46.45%
Percentage less than of which fair value exceeded carrying value																10.00%			10.00%
Equity Earnings																	$ 51.0	59.0	$ 31.0
Equity Investments								$ 491.0				489.0					491.0	489.0
Equity contribution								4.6			$ 5.1						10.0	9.0	9.0
Undistributed earnings																	0.0	0.0	0.0
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill												260.0						260.0
Distributions from Equity Investments
Distributions received from equity investments																	(59.0)	58.0	35.0
ASSETS
Current assets								72.0				75.0					72.0	75.0
Property, plant and equipment, net								685.0				689.0					685.0	689.0
Assets, total								757.0				764.0					757.0	764.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities								33.0				26.0					33.0	26.0
Net long-term debt, including current maturities								219.0				240.0					219.0	240.0
Other non-current liabilities								6.0				4.0					6.0	4.0
Partners' capital								499.0				494.0					499.0	494.0
Liabilities and Partners' Equity, total								$ 757.0				764.0					757.0	764.0
Revenues (expenses)
Transmission revenues																	238.0	246.0	181.0
Operating expenses																	(79.0)	(68.0)	(66.0)
Depreciation																	(32.0)	(32.0)	(29.0)
Financial charges and other																	(16.0)	(18.0)	(20.0)
Net income																	111.0	128.0	66.0
Great Lakes | Iroquois
Distributions from Equity Investments
Distributions received from equity investments																	$ 55.0
Iroquois
EQUITY INVESTMENTS
Ownership interest (as a percent)	49.34%			49.34%				49.34%									49.34%				49.34%
Equity Earnings																	$ 40.0	46.0	26.0
Equity Investments								$ 185.0				210.0					185.0	210.0
Equity contribution				$ 710.0	$ 4.0												4.0
Undistributed earnings																$ 0.0	0.0	0.0
Additional consideration on surplus cash				$ 28.0
Distributions from Equity Investments
Distributions received from equity investments																		56.0
Distributions from equity investments	$ 14.0
Return on investment distribution classified as investing activities																	$ 8.0	10.0	$ 5.0
ASSETS
Cash and cash equivalents												80.0						80.0
Other current assets												32.0						32.0
Property, plant and equipment, net												581.0						581.0
Other assets												8.0						8.0
Assets, total												701.0						701.0
LIABILITIES AND PARTNERS' EQUITY
Current liabilities												19.0						19.0
Net long-term debt, including current maturities												325.0						325.0
Other non-current liabilities												14.0						14.0
Partners' capital												343.0						343.0
Liabilities and Partners' Equity, total												$ 701.0						$ 701.0

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ACQUISITIONS - 2017 Acquisition and 2016 PNGTS Acquisition (Details)			1 Months Ended	12 Months Ended
	Aug. 01, 2017 USD ($) item	Jun. 01, 2017 USD ($)	Aug. 31, 2019 USD ($)	Dec. 31, 2019 USD ($)	Feb. 20, 2020 USD ($)	Jan. 06, 2020
PNGTS
ACQUISITIONS
Ownership interest, including acquired interest (as a percent)		61.71%
Outstanding debt		$ 5,000,000
PNGTS purchase price
Current assets		25,000,000
Property, plant and equipment, net		294,000,000
Current liabilities		(4,000,000)
Deferred state income taxes		(10,000,000)
Long-term debt, including current portion		(41,000,000)
Net assets		264,000,000
Non-controlling interest		(100,000,000)
Carrying value of pre-existing Investment in PNGTS		(132,000,000)
TransCanada's carrying value of the acquired 11.81 percent interest at June 1, 2017		32,000,000
Excess purchase price over net assets acquired		21,000,000
Total cash consideration		53,000,000
Purchase price before assumption of debt		55,000,000
Final working capital adjustment		3,000,000
Reduction in partner's equity due to excess purchase price		$ 21,000,000
Iroquois
ACQUISITIONS
Interest acquired (as a percent)	49.34%	49.34%		49.34%		49.34%
Option to acquire (as a percent)		0.66
Amount of final purchase price adjustments		$ 19,000,000
Additional consideration on surplus cash		28,000,000
Purchase price before assumption of debt		710,000,000
Outstanding debt		164,000,000
Payment for option to acquire		1,000
Net purchase price
Net Purchase Price		593,000,000
Less: TransCanada's carrying value of Iroquois at June 1, 2017		223,000,000
Excess purchase price		370,000,000
Net purchase price		710,000,000	$ 4,000,000	$ 4,000,000
Reduction in partner's equity under equity method investments		370,000,000
Iroquois | PNGTS
ACQUISITIONS
Purchase price		765,000,000
Amount of final purchase price adjustments		$ 50,000,000
Iroquois | Investing Activities
ACQUISITIONS
Expected return on investment distribution classified as investing activities	$ 28,400,000
Number of quarters for distribution of surplus cash | item	11
Iroquois | TC Energy
ACQUISITIONS
Expected return on investment distribution classified as investing activities	$ 28,000,000
Iroquois | Cash Distribution Paid
ACQUISITIONS
Distributions received to date					$ 25,800,000
PNGTS
ACQUISITIONS
Interest acquired (as a percent)		11.81%
Interest acquired by Partnership (as a percent)		11.81%
Purchase price		$ 55,000,000
Amount of final purchase price adjustments		3,000,000
Outstanding debt		$ 5,000,000

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FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - USD ($) $ in Millions		12 Months Ended
	Jun. 26, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest rate derivatives
Net realized gain related to the interest rate swaps included in financial charges and other			$ 1.0	$ 1.0
Amortization of Derivatives Loss			1.0	1.0
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, after Tax		$ (13.0)	$ (2.0)	5.0
Accounts receivable
Interest rate derivatives
Maximum counterparty credit exposure		$ 0.0
2013 Term Loan Facility
Interest rate derivatives
Repayments of secured debt	$ 50.0
Unwind rate of interest rate swap (as a percent)	2.81%
Secured debt | PNGTS 5.90% Senior Secured Notes due 2018
Interest rate derivatives
Stated interest rate (as a percent)		5.90%	5.90%
Interest rate swaps | Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022
Interest rate derivatives
Weighted average fixed interest rate (as a percent)		3.26%
Hedges of cash flows | Interest rate swaps | Financial charges and other
Interest rate derivatives
Net realized gain related to the interest rate swaps included in financial charges and other		$ 1.0		0.0
Hedges of cash flows | Recurring fair value measurement | Level 2 | Interest rate swaps
Interest rate derivatives
Fair value of derivative asset, gross			$ 8.0
Fair value of derivative liability, gross		6.0
Fair value of derivative asset, net			8.0
Fair value of derivative liability, net		6.0
PNGTS
Interest rate derivatives
Amortization of Derivatives Loss			$ 1.0	$ 1.0
PNGTS
Interest rate derivatives
Ownership interest (as a percent)			61.71%	61.71%
PNGTS
Interest rate derivatives
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, after Tax			$ 20.9
Payments for derivative instruments		$ 20.9

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TRANSACTIONS WITH MAJOR CUSTOMERS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Transactions with major customers
Trade accounts receivable	$ 44		$ 37
Revenues | Credit Concentration Risk | Anadarko Energy Services Company
Transactions with major customers
Revenues		$ 48
Concentration percentage		10.00%
Revenues | Credit Concentration Risk | Anadarko/Tenaska customer group
Transactions with major customers
Revenues	144
Trade accounts receivable | Credit Concentration Risk | Anadarko Energy Services Company
Transactions with major customers
Trade accounts receivable		$ 4
Concentration percentage		10.00%
Trade accounts receivable | Credit Concentration Risk | Tenaska
Transactions with major customers
Trade accounts receivable	$ 4
Concentration percentage	10.00%

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PARTNERS' EQUITY - Class B Units (Details) - USD ($) $ / shares in Units, $ in Millions														3 Months Ended	12 Months Ended
	Nov. 14, 2019	Aug. 14, 2019	May 13, 2019	Feb. 11, 2019	Nov. 14, 2018	Aug. 15, 2018	May 15, 2018	Feb. 13, 2018	Nov. 14, 2017	Aug. 11, 2017	May 15, 2017	Feb. 14, 2017	Apr. 01, 2015	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Common Units
PARTNERS' EQUITY
Cash distribution	$ 46	$ 46	$ 46	$ 46	$ 46	$ 46	$ 46	$ 71	$ 70	$ 69	$ 65	$ 64
Net income (loss) attributable to common units															$ 267	$ (191)	$ 219
Class B Units
PARTNERS' EQUITY
Cash distribution				$ 13				$ 15				$ 22			13	15	22
Net income (loss) attributable to common units															$ 8	$ 13	15
TC Energy
PARTNERS' EQUITY
Remaining ownership interest (as a percent)															30.00%
TC Energy | Distributions | Common Units
PARTNERS' EQUITY
Percentage of reduction in distributions payable														35.00%
Distribution per common unit														$ 1.00
Minimum distribution payable per common unit															$ 3.94
TC Energy | Distributions | Class B Units
PARTNERS' EQUITY
Percentage of reduction in distributions payable															35.00%
GTN | TC Energy | Class B Units
PARTNERS' EQUITY
Threshold of GTN's distributions for payment to Class B units															$ 20
Percentage applied to GTN's distributable cash flow															30.00%
GTN | TC Energy | Distributions | Class B Units
PARTNERS' EQUITY
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)													30.00%		30.00%
Percentage applied to 30 percent of GTN's distributions above threshold for the year ending December 31, 2019															100.00%
Threshold of GTN's total distributable cash flows for payment to Class B units for the year ending December 31, 2019															$ 20
Percentage applied to 30 percent of GTN's distributions above threshold thereafter															25.00%
Threshold of GTN's distributions for payment to Class B units															$ 20		$ 20	$ 20
Percentage applied to GTN's distributable cash flow															30.00%

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NET INCOME PER COMMON UNIT- Determination of Net Income (Loss) per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended								12 Months Ended
	Apr. 01, 2015	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net income (loss) per common unit
Net income (loss) attributable to controlling interests										$ 280	$ (182)	$ 252
Net income attributable to PNGTS' former parent												(2)
Net income (loss) attributable to General and Limited Partners										280	(182)	250
Incentive distributions attributable to the General Partner												(12)
Net income attributable to the General Partner and common units										272	(195)	223
Net income (loss) attributable to General Partner's two percent interest										(5)	4	(4)
Net income (loss) per common unit - basic and diluted (in dollars per unit)		$ 0.95	$ 0.76	$ 0.75	$ 1.28	$ (5.80)	$ 0.79	$ 1.00	$ 1.32
Distributions
Net income attributable to controlling interests		$ 76	$ 56	$ 55	$ 93	$ (413)	$ 62	$ 73	$ 96
Class B Units
Net income (loss) per common unit
Net income (loss) attributable to common units or Class B units										8	13	15
Common Units
Net income (loss) per common unit
Net income (loss) attributable to common units or Class B units										$ 267	$ (191)	$ 219
Weighted average common units outstanding (millions) - basic and diluted										71.3	71.3	69.2
Net income (loss) per common unit - basic and diluted (in dollars per unit)										$ 3.74	$ (2.68)	$ 3.16
General Partner | TC Pipelines, LP | Common Units
Net income (loss) per common unit
General partner interest (as a percent)										2.00%	2.00%	2.00%
GTN | Class B Units | TC Energy
Distributions
Threshold of GTN's distributions for payment to Class B units										$ 20
Percentage applied to GTN's distributable cash flow										30.00%
GTN | Class B Units | TC Energy | Distributions
Net income (loss) per common unit
Net income (loss) attributable to controlling interests										$ (8)	$ (13)	$ (15)
Distributions
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent)	30.00%									30.00%
Threshold of GTN's distributions for payment to Class B units										$ 20		$ 20	$ 20
Percentage applied to GTN's distributable cash flow										30.00%
Class B reduction										$ 4	$ 7

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ORGANIZATION

12 Months Ended

Dec. 31, 2019

ORGANIZATION

ORGANIZATION

NOTE 1 ORGANIZATION

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

At December 31, 2018, the Partnership owned its pipeline assets through an intermediate general partnership, TC PipeLines Intermediate GP, LLC (Intermediate GP) and three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership. During the fourth quarter of 2019, the Partnership initiated the dissolution of the ILPs and Intermediate GP. Effective October 31, 2019, the Intermediate GP and ILPs transferred 100 percent of the ownership of their pipeline assets to the Partnership. As a result, the Partnership owns its pipeline assets directly which creates a more efficient partnership structure with no economic impact to the general and limited partners of the Partnership.

Pipeline	Length	Description	Ownership
GTN	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison	303 miles	Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border	1,412 miles	Extends between 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 Rocky Mountain area for deliveries to the Midwest. ONEOK Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border.	50 percent
PNGTS	295 miles	Connects with the TQM 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 undivided ownership interest based on contractually agreed upon percentages. The Joint Facilities are maintained and operated by MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.	61.71 percent
Great Lakes	2,115 miles	Connects with the TC Energy Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TC Energy owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois	416 miles	Extends from the TC Energy Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by: TC Energy (0.66 percent), Dominion Energy (50 percent). Iroquois is maintained and operated by a subsidiary of Iroquois.	49.34 percent

The Partnership is managed by its General Partner, TC PipeLines GP, Inc. (General Partner), an indirect wholly-owned subsidiary of TC Energy. The General Partner provides management and operating services to the Partnership and is reimbursed for its costs and expenses. The General Partner owns 5,797,106 of our common units, 100 percent of our Incentive Distribution Rights (IDRs) and a two percent general partner interest in the Partnership at December 31, 2019. TC Energy also indirectly holds an additional 11,287,725 common units, for a total ownership of approximately 24 percent of our outstanding common units and 100 percent of our Classs B units at December 31, 2019 (Refer to Note 11).

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Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2019	Feb. 19, 2020	Jun. 30, 2019
Document and Entity Information
Document Type	10-K
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Dec. 31, 2019
Entity File Number	001-35358
Entity Registrant Name	TC PipeLines, LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	52-2135448
Entity Address, Address Line One	700 Louisiana Street
Entity Address, Address Line Two	Suite 700
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002-2761
City Area Code	877
Local Phone Number	290-2772
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Title of 12(b) Security	Common units representing limited partner interests
Trading Symbol	TCP
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding		71,306,396
Entity Central Index Key	0001075607
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 2.7

XML

CONSOLIDATED STATEMENT OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash Generated from Operations
Net income (loss)	$ 298.0	$ (165.0)	$ 263.0
Depreciation	78.0	97.0	97.0
Impairment of long lived assets (Note 7)		537.0
Impairment of goodwill (Note 4)		59.0
Amortization of debt issue costs reported as interest expense (Note 13)	2.0	2.0	2.0
Amortization of realized loss on derivative instrument (Note 20)		1.0	1.0
Equity earnings from equity investments (Note 5)	(160.0)	(173.0)	(124.0)
Distributions received from operating activities of equity investments (Note 5)	200.0	188.0	140.0
Change in other long-term liabilities	(1.0)	(2.0)
Equity allowance for funds used during construction	(2.0)	(1.0)	(1.0)
Change in operating working capital (Note 16)	(3.0)	(3.0)	(2.0)
Cash generated from operations	412.0	540.0	376.0
Investing Activities
Distribution received from return of investment (Note 5)	58.0	10.0	5.0
Capital expenditures	(75.0)	(40.0)	(29.0)
Other	(1.0)	4.0	1.0
Investing activities	(32.0)	(35.0)	(761.0)
Financing Activities
Distributions paid (Note 15)	(189.0)	(218.0)	(284.0)
Distributions paid to non-controlling interests	(22.0)	(14.0)	(5.0)
Distributions paid to former parent of PNGTS			(1.0)
Common unit issuance, net (Note 11)		40.0	176.0
Long-term debt issued, net of discount (Note 9)	30.0	219.0	802.0
Long-term debt repaid (Note 9)	(136.0)	(516.0)	(310.0)
Debt issuance costs		(1.0)	(2.0)
Financing activities	(330.0)	(505.0)	354.0
Increase/(decrease) in cash and cash equivalents	50.0		(31.0)
Cash and cash equivalents, beginning of year	33.0	33.0	64.0
Cash and cash equivalents, end of year	83.0	33.0	33.0
Interest payments paid	87.0	94.0	79.0
State income taxes paid	2.0	1.0	2.0
Supplemental information about non-cash investing and financing activities
Accrued capital expenditures	12.0	7.0	9.0
Class B Units
Financing Activities
Distributions paid to Class B units (Notes 11 and 15)	(13.0)	(15.0)	(22.0)
Portland Natural Gas Transmission System And Iroquois Acquisition
Investing Activities
Investment of interests			(646.0)
Great Lakes
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	(51.0)	(59.0)	(31.0)
Investing Activities
Investment of interests	(10.0)	(9.0)	(9.0)
Iroquois
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	(40.0)	(46.0)	(26.0)
Investing Activities
Investment of interests	(4.0)
Distribution received from return of investment (Note 5)	8.0	10.0	5.0
Northern Border
Cash Generated from Operations
Equity earnings from equity investments (Note 5)	(69.0)	$ (68.0)	(67.0)
Investing Activities
Investment of interests			$ (83.0)
Distribution received from return of investment (Note 5)	$ 50.0

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ORGANIZATION - Capitalization (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Common Units
Partners' Equity
Number of units	71,300,000	71,300,000	70,600,000
Common Units | General Partner | TC Pipelines, LP
Partners' Equity
Ownership interest in the Partnership (as a percent)	2.00%	2.00%	2.00%
Class B Units | TC Energy | TC Energy
Partners' Equity
Limited partner interest (as a percent)	24.00%
General Partner | TC Pipelines, LP
Partners' Equity
IDRs ownership (as a percent)	100.00%
Limited Partners | Common Units
Partners' Equity
Number of units	71,306,396
Limited Partners | Common Units | TC Pipelines, LP
Partners' Equity
Number of units	5,797,106
Limited Partners | Common Units | TC Energy
Partners' Equity
Number of units	11,287,725
Limited Partners | Class B Units | TC Energy
Partners' Equity
Number of units	1,900,000
Limited partner interest (as a percent)	100.00%

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RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2019

RELATED PARTY TRANSACTIONS

Summary of capital and operating costs charged to pipeline systems by related party

Year ended December 31 (millions of dollars)	2019	2018	2017
Capital and operating costs charged by TC Energy’s subsidiaries to:
Great Lakes (a)	47	44	36
Northern Border(a)	39	36	43
PNGTS (a)	7	9	9
GTN	45	34	34
Bison	2	6	6
North Baja	5	4	4
Tuscarora	4	4	4
Impact on the Partnership’s net income attributable to controlling interests:
Great Lakes	20	19	15
Northern Border	18	16	16
PNGTS	4	5	5
GTN	33	28	29
Bison	2	6	6
North Baja	4	4	4
Tuscarora	4	4	4

Summary of amount payable to related party for costs charged

December 31 (millions of dollars)	2019	2018
Amount payable to TC Energy’s subsidiaries for costs charged in the year by:
Great Lakes (a)	5	3
Northern Border(a)	4	3
PNGTS (a)	1	1
GTN	5	4
Bison	—	1
North Baja	1	—
Tuscarora	—	1

(a) Represents 100 percent of the costs.

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PARTNERS' EQUITY - ATM Equity Issuance Program (Details) - ATM Equity Issuance Program - USD ($) shares in Millions, $ in Millions	2 Months Ended	12 Months Ended
	May 19, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Aug. 31, 2016	Aug. 31, 2014
Common Units
PARTNERS' EQUITY
Aggregate gross sales limit					$ 400	$ 200
Units sold		0.7	3.2
Net proceeds from issuance of common units		$ 39	$ 173
Sales agent commissions			2
Reclassification of common unit issuance subject to rescission, net (in units)	1.6
Common units subject to rescission				$ 0
TC Pipelines, LP | General Partner
PARTNERS' EQUITY
Equity contribution		$ 1	$ 3

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NET INCOME PER COMMON UNIT - General Partner Interest (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
General Partner | Common Units | TC Pipelines, LP
PARTNERS' EQUITY
General partner interest (as a percent)	2.00%	2.00%	2.00%

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income (loss)	$ 298	$ (165)	$ 263
Other comprehensive income (loss)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, after Tax	(13)	(2)	5
Reclassification to net income of gains and losses on cash flow hedges (Notes 12 and 20)	(1)	5
Amortization of realized loss on derivative instrument (Notes 12 and 20)		1	1
Other comprehensive income (loss) on equity investments (Note 12)	1	(1)	1
Comprehensive income (loss)	285	(162)	270
Comprehensive income attributable to non-controlling interests	18	17	11
Comprehensive income (loss) attributable to controlling interests	$ 267	$ (179)	$ 259

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CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
Gain (losses) related to cash flow hedges in AOCI expected to be reclassified to Net income in the next 12 months	$ 2

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SIGNIFICANT ACCOUNTING POLICIES - Ownership Interests Acquired (Details)	Jun. 01, 2017
PNGTS
Acquisitions
Interest acquired (as a percent)	11.81%
Ownership interest (as a percent)	11.81%
Iroquois
Acquisitions
Interest acquired (as a percent)	49.34%
PNGTS
Acquisitions
Ownership interest, including acquired interest (as a percent)	61.71%

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ACCOUNTS RECEIVABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2019

ACCOUNTS RECEIVABLE AND OTHER

Schedule of accounts receivable and other

December 31 (millions of dollars)	2019	2018
Trade accounts receivable, net of allowance of nil	37	44
Imbalance receivable from affiliates	—	2
Other	6	2
	43	48

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PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2019

PROPERTY, PLANT AND EQUIPMENT

Schedule of property, plant and equipment

	2019			2018
		Accumulated	Net Book		Accumulated	Net Book
December 31 (millions of dollars)	Cost	Depreciation	Value	Cost	Depreciation	Value
Pipeline	1,907	(929)	978	1,901	(876)	1,025
Compression	584	(202)	382	550	(182)	368
Metering and other	180	(56)	124	176	(52)	124
Construction in progress	44	-	44	12	—	12
	2,715	1,187	1,528	2,639	(1,110)	1,529

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ORGANIZATION (Tables)

12 Months Ended

Dec. 31, 2019

ORGANIZATION

Schedule of ownership interests in natural gas pipeline systems

Pipeline	Length	Description	Ownership
GTN	1,377 miles	Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California.	100 percent
Bison	303 miles	Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets.	100 percent
North Baja	86 miles	Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline.	100 percent
Tuscarora	305 miles	Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada.	100 percent
Northern Border	1,412 miles	Extends between 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 Rocky Mountain area for deliveries to the Midwest. ONEOK Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border.	50 percent
PNGTS	295 miles	Connects with the TQM 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 undivided ownership interest based on contractually agreed upon percentages. The Joint Facilities are maintained and operated by MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc.	61.71 percent
Great Lakes	2,115 miles	Connects with the TC Energy Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TC Energy owns the remaining 53.55 percent of Great Lakes.	46.45 percent
Iroquois	416 miles	Extends from the TC Energy Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by: TC Energy (0.66 percent), Dominion Energy (50 percent). Iroquois is maintained and operated by a subsidiary of Iroquois.	49.34 percent

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NET INCOME (LOSS) PER COMMON UNIT (Tables)

12 Months Ended

Dec. 31, 2019

NET INCOME (LOSS) PER COMMON UNIT

Schedule of net income per common unit

(millions of dollars, except per common unit amounts)	2019		2018		2017
Net income (loss) attributable to controlling interests		280		(182)		252
Net income attributable to PNGTS' former parent (a)		—		—		(2)
Net income (loss) allocable to General Partner and Limited Partners		280		(182)		250
Incentive distributions attributable to the General Partner (b)		—		—		(12)
Net income attributable to the Class B units (c)		(8)		(13)		(15)
Net income (loss) allocable to the General Partner and common units		272		(195)		223
Net (income) loss allocable to the General Partner's two percent interest		(5)		4		(4)
Net income (loss) attributable to common units		267		(191)		219
Weighted average common units outstanding (millions) – basic and diluted		71.3		71.3		69.2
Net income (loss) per common unit – basic and diluted	$	3.74	$	(2.68)	$	3.16

(a) Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated to TC Energy and was not allocable to either the general partner, common units or Class B units.

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

(c) As discussed in Note 11, the Class B units entitle TC Energy to a distribution which is an amount based on 30 percent of GTN’s distributions after exceeding certain annual thresholds and Class B Reduction. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 – “Earnings per share,” the Partnership allocated the Class B units distribution in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2019 less the threshold level of $20 million (2018 and 2017 - less $20 million) and less the Class B Reduction (2019 - $4 million, 2018 - $7 million. The Class B Reduction did not apply during 2017).

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GOODWILL AND REGULATORY (Details) $ in Millions			3 Months Ended		5 Months Ended	12 Months Ended		18 Months Ended	24 Months Ended	36 Months Ended	42 Months Ended	44 Months Ended	48 Months Ended	65 Months Ended
	Dec. 06, 2018	Dec. 01, 2018	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 01, 2020	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 01, 2020 item	Dec. 31, 2021	Dec. 31, 2021	Jan. 31, 2023	Oct. 01, 2022	Jan. 31, 2023	Jul. 01, 2024	Nov. 30, 2018 USD ($)	Oct. 16, 2018 USD ($)	Dec. 31, 2017 USD ($)
REGULATORY
Provision for revenue sharing							$ 10
Goodwill impairment charge							59
Goodwill			$ 71			$ 71	71										$ 130
Great Lakes | FERC
REGULATORY
Decrease in rate (as a percent)												2.00%
GTN | FERC
REGULATORY
Decrease in rate (as a percent)									6.60%	10.00%
Amount agreed to issue as refund to customers from January 1 to October 31, 2018															$ 10	$ 10
Rate reduction replaced (as a percent)															(8.30%)
Provision for revenue sharing			1	$ 9
Northern Border | FERC
REGULATORY
Decrease in rate (as a percent)														2.00%
Iroquois | FERC
REGULATORY
Decrease in rate (as a percent)					3.25%			3.25%
Iroquois | 2016 Settlement | FERC
REGULATORY
Decrease in rate (as a percent)								6.50%
Iroquois | 2019 Settlement | FERC
REGULATORY
Decrease in rate (as a percent)								6.50%
Number phases of reduction of rates | item								2
North Baja
REGULATORY
Goodwill						48
North Baja | FERC
REGULATORY
Decrease in rate (as a percent)		10.80%
Tuscarora
REGULATORY
Decrease in rate (as a percent)	1.70%
Goodwill						23
Tuscarora | FERC
REGULATORY
Decrease in rate (as a percent)											10.80%		1.70%
Tuscarora
REGULATORY
Goodwill impairment charge						59
Goodwill			$ 82			$ 23	$ 82

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PROPERTY, PLANT AND EQUIPMENT - Property, Plant and Equipment Impairment in Bison (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018
Schedule of Investments [Line Items]
Impairment of long-lived assets		$ 537
Bison
Schedule of Investments [Line Items]
Reduction in future revenue	$ 537

XML

ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
ACCOUNTS RECEIVABLE AND OTHER
Trade accounts receivable, net of allowance of nil	$ 37	$ 44
Imbalance receivable from affiliates		2
Other	6	2
Accounts receivable and other	43	48
Trade accounts receivable, allowance

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RELATED PARTY TRANSACTIONS (Details) $ in Millions			1 Months Ended	12 Months Ended
	Oct. 31, 2019 USD ($)	Nov. 01, 2017	Sep. 21, 2017 Bcf	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Nov. 01, 2020 USD ($)
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				$ 8.0	$ 6.0
Amount included in receivables from related party					2.0
General Partner | Reimbursement of costs of services provided
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				4.0	4.0	$ 4.0
Great Lakes | TransCanada's subsidiaries
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party				19.0	18.0
Great Lakes | TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				5.0	3.0
Termination options beginning		3 years
Great Lakes | TC Energy | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				47.0	44.0	36.0
Impact on the Partnership's net income attributable to controlling interests				20.0	19.0	15.0
Amount included in receivables from related party				34.0	36.0
Great Lakes | TC Energy | Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Contract term		10 years
Total revenue earned				$ 76.0	$ 76.0	$ 13.0
Great Lakes | TC Energy | Transportation contracts | Total net revenues | Customer concentration risk
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues				73.00%	73.00%	57.00%
Great Lakes | TC Energy | Affiliated rental revenue
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues						1.00%
Great Lakes | TC Energy | Affiliated rental revenue | Maximum
Capital and operating costs charged to the pipeline systems and amount payable
Percent of total revenues				1.00%	1.00%
Great Lakes | ANR Pipeline Company | Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Contract term					15 years
Total contract value					$ 1,300.0
Transportation capacity per day | Bcf			0.711
Northern Border | TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				$ 4.0	3.0
Northern Border | TC Energy | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				39.0	36.0	$ 43.0
Impact on the Partnership's net income attributable to controlling interests				18.0	16.0	16.0
PNGTS | TransCanada's subsidiaries | Transportation contracts
Capital and operating costs charged to the pipeline systems and amount payable
Amount included in receivables from related party				0.0	0.0
Revenues from related party				1.0	1.0	1.0
PNGTS | TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				1.0	1.0
PNGTS | TC Energy | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				7.0	9.0	9.0
Impact on the Partnership's net income attributable to controlling interests				4.0	5.0	5.0
PNGTS | TC Energy | Portland XPress expansion project (PXP), Phase III | PXP Phase III
Capital and operating costs charged to the pipeline systems and amount payable
Costs reimbursable at reporting date				$ 0.6
PNGTS | TC Energy | Portland XPress expansion project (PXP), Phase III | PXP Phase III | Forecast
Capital and operating costs charged to the pipeline systems and amount payable
Costs reimbursable at reporting date							$ 8.0
PNGTS | Affiliates | Construction of facilities | Minimum
Capital and operating costs charged to the pipeline systems and amount payable
Reimbursement of costs	$ 140.0
PNGTS | Affiliates | Portland XPress expansion project (PXP), Phase III
Capital and operating costs charged to the pipeline systems and amount payable
Expansion Project, Phase In Period				3 years
GTN | TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				$ 5.0	4.0
GTN | TC Energy | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				45.0	34.0	34.0
Impact on the Partnership's net income attributable to controlling interests				$ 33.0	$ 28.0	$ 29.0
Percentage of capital and operating costs charged				100.00%	100.00%	100.00%
Bison | TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable					$ 1.0
Bison | TC Energy | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				$ 2.0	6.0	$ 6.0
Impact on the Partnership's net income attributable to controlling interests				2.0	6.0	6.0
North Baja | TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable				1.0
North Baja | TC Energy | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				5.0	4.0	4.0
Impact on the Partnership's net income attributable to controlling interests				4.0	4.0	4.0
Tuscarora | TC Energy
Capital and operating costs charged to the pipeline systems and amount payable
Net amounts payable					1.0
Tuscarora | TC Energy | Capital and operating costs
Capital and operating costs charged to the pipeline systems and amount payable
Costs charged				4.0	4.0	4.0
Impact on the Partnership's net income attributable to controlling interests				$ 4.0	$ 4.0	$ 4.0

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OTHER LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
OTHER LIABILITIES
Regulatory liabilities	$ 29	$ 27
Other liabilities	7	2
Other liabilities, total	$ 36	$ 29

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Changes in accumulated other comprehensive income (loss) (AOCI) by component
Partners' Equity at beginning of year	$ 591
Change in fair value of interest rate derivative instruments recognized in other comprehensive income	(13)	$ (2)	$ 5
PNGTS' amortization of realized loss on derivative instrument (Note 20)		1	1
Net other comprehensive income	(13)	3	7
Partners' Equity at end of year	656	591
Accumulated Other Comprehensive Income (Loss)
Changes in accumulated other comprehensive income (loss) (AOCI) by component
Partners' Equity at beginning of year	8	5	(2)
Change in fair value of interest rate derivative instruments recognized in other comprehensive income	(13)	(2)	5
Amounts reclassified from AOCI	(1)	5
PNGTS' amortization of realized loss on derivative instrument (Note 20)	1	1	1
Other comprehensive income (loss) - effects of Iroquois' retirement benefit plans		(1)	1
Net other comprehensive income	(13)	3	7
Partners' Equity at end of year	(5)	8	5
Cash flow hedges
Changes in accumulated other comprehensive income (loss) (AOCI) by component
Partners' Equity at beginning of year	8	4	(2)
Change in fair value of interest rate derivative instruments recognized in other comprehensive income	(13)	(2)	5
Amounts reclassified from AOCI	(1)	5
PNGTS' amortization of realized loss on derivative instrument (Note 20)		1	1
Net other comprehensive income	(14)	4	6
Partners' Equity at end of year	(6)	8	4
Equity Investments
Changes in accumulated other comprehensive income (loss) (AOCI) by component
Partners' Equity at beginning of year		1
PNGTS' amortization of realized loss on derivative instrument (Note 20)	1
Other comprehensive income (loss) - effects of Iroquois' retirement benefit plans		(1)	1
Net other comprehensive income	1	$ (1)	1
Partners' Equity at end of year	$ 1		$ 1

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CASH DISTRIBUTIONS - Quarterly Distributions (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash distributions
Period after the end of each quarter within which quarterly cash distributions to partners are to be paid	45 days
General Partner | TC Pipelines, LP | Common Units
Cash distributions
General partner interest (as a percent)	2.00%	2.00%	2.00%

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SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
State income tax benefit (expense)
Total state income taxes	$ 1	$ (1)	$ (1)
PNGTS
Income Taxes
Effective income tax rate (as a percent)	2.60%	3.50%	3.80%
State income tax benefit (expense)
Current	$ 1	$ 2	$ 1
Deferred	(2)	(1)
Total state income taxes	$ (1)	$ 1	$ 1